Berens Energy Ltd.

August 13, 2008 23:59 ET

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

CALGARY, ALBERTA--(Marketwire - Aug. 13, 2008) -



FINANCIAL AND OPERATING HIGHLIGHTS

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($ Cdn thousands, Three months Six months

except as noted) ended June 30, ended June 30,

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% %

2008 2007 Change 2008 2007 Change

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Sales volume

Natural gas

(mcf/day) 19,677 19,919 (1%) 19,390 19,315 -

Oil and ngls

(bbl/day) 859 560 53% 744 530 40%

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boe/day (6 to 1) 4,139 3,880 7% 3,975 3,749 6%

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Revenue net of

royalties 20,738 12,643 64% 35,255 24,423 44%

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Net (loss) (1,612) (557) (189%) (7,026) (3,603) (95%)

Per share (basic

and diluted) $(0.02) $(0.01) $(0.08) $(0.04)

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Funds from

operations(1) 12,570 7,782 62% 21,839 14,752 48%

Per share (basic

and diluted)(1) $0.13 $0.08 $0.23 $0.16

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Capital costs

Exploration and

development 1,696 5,120 (67%) 11,865 22,198 (46%)

Land and seismic 1,015 1,085 (6%) 2,429 2,155 13%

Other 4 3 25% 7 15 (53%)

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Total 2,715 6,208 (56%) 14,301 24,368 (41%)

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Net wells completed

(No.) - 1 5 7

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Net working capital

deficit - excluding

unrealized hedging

losses (51,766) (65,073) (20%) (51,766) (65,073) (20%)

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Net working capital

deficit - including

unrealized hedging

losses (63,942) (63,610) 1% (64,942) (63,610) 2%

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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.



Second Quarter 2008 Operating Highlights

Berens is pleased to provide our second quarter results that demonstrate
record cash flows due to increased production volume from successful first
quarter drilling and strong commodity prices:

- Capital Budget - The 2008 capital budget has been increased from $30

million to $40 million. The increase reflects higher cash flow

delivered by increased production volume and stronger commodity

prices. The additional capital combined with strong drilling results

to date is expected to increase the expected exit production rate to

approximately 4,400 boe/d with strong momentum established entering

2009 as most of the additional capital will be spent in the final

four months of 2008.

- Production - Q2 2008 production averaged 4,139 boe/d, up 7% over Q2

2007 and up 9% over Q1 2008 as strong drilling results in the first

quarter of 2008 resulted in significant new production coming on

stream early in the second quarter. This increase in production has

been delivered while decreasing debt and working capital balances

over $13 million or 20 percent since June 30, 2007.

- Production Costs - Costs averaged $7.68 per boe in Q2 2008 with costs

for the first six months of 2008 averaging $7.98 per boe, up 6%

compared to the first six months of 2007. We expect operating costs

to be in the $7.50 range for the remainder of the year.

- Funds from Operations - Funds from operations for Q2 2008 were a

record $12.6 million ($0.13 per share), up 62% compared to Q2 2007

funds from operations of $7.8 million ($0.08 per share). Higher

production, stronger commodity prices and stable per unit operating

costs contributed to the increase. For the quarter ended June 30,

2008, the ratio of debt and working capital to annualized funds from

operation was 1.0 times.

- Land - Berens' total undeveloped land currently stands at 87,000 net

acres. The undeveloped land base has increased in quality as 20

(11.7 net) sections of undeveloped land has been added in Pembina,

our key growth area, 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, a significantly improved balance sheet and continued control on costs. The strong operating results have now been combined with stronger commodity prices and as a consequence, we are increasing our drilling activity for balance of the year. We have achieved this by maintaining our disciplined business focus on value creation.

We delivered average production in the second quarter of 2008 of 4,139 boe/d which is 7% above a year ago while reducing debt by $13 MM or 20%. Second quarter production is also 9% above our Q1 2008 figure of 3,812 boe/d and is primarily attributed to our strong drilling results in the first quarter. Third quarter production is expected to stay relatively flat as second quarter activity was limited due to spring breakup but increases are expected again for fourth quarter.

Drilling activity was minimal in the second quarter, however we have been very active since mid June and to date have drilled an additional 9 wells, 7 wells in Lanfine, with 6 (5.8 net) wells being successful and 2 (net 1.1) wells in Pembina, both successful. In Pembina this continues our string of successful wells at 34. These wells will come on stream throughout third quarter and will provide our production growth for fourth quarter. Through the remainder of third and fourth quarters, we expect to drill 1 well in Deep Basin and as many as 10 more wells in Pembina. Two of the Pembina wells will be horizontal wells using new multi-frac completion technologies and we look forward to the additional prospects that these horizontal wells provide to our drilling inventory.

Capital expenditures are on target to the end of second quarter and with our strong production results and improved commodity prices, our cash flows are much stronger. This has allowed us to significantly improve our balance sheet and increase our capital spending for the second half of the year. Our 2008 budget has been increased to $40 million from $30 million with the increase in spending targeted for Pembina in the third and fourth quarters. The increase in spending along with our solid production results to date is expected to increase our average fourth quarter production rate to approximately 4,400 boe/d. In addition, as much of the increase in spending will occur in the final months of the year, we expect strong production momentum heading into 2009.

We continue to exploit our competitive advantage in our core areas based on intensive integration of technology, geology and geophysics which has reduced our risks. We are confident in our ability to repeat our 2007 finding and development costs of $13.00 /boe in 2008. As well, drilling, completion and operating costs remain under control and will be an ongoing focus area for our team as industry activity increases.

We are pleased with our results, continue to stay focused on value creation, and are looking forward as we step up our activity levels to generate increased shareholder value.



Sincerely,

Daniel F. Botterill

President & Chief Executive Officer

Berens Energy Ltd.

Second Quarter 2008

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

August 12, 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 June 30, 2008 interim financial statements and notes thereto. This MD&A was prepared using information that is current as of August 12, 2008 unless otherwise noted.

STRATEGY AND OBJECTIVES

The 2008 $40 million capital program is funded by cash flow based on an assumed natural gas price of $8.50 per mcf for the remainder of 2008. This program is expected to generate 2008 exit production rates of 4,400 to 4,500 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 1.5 times with new reserves at finding and development costs below $15.00/boe. Operating and corporate netbacks are expected to be $35.00 per boe and $28.00 per boe respectively assuming a $8.50 per mcf price for natural gas and $100.00 per barrel for oil. Resulting recycle ratios based on the above factors are expected to be over 2.3 times on an operating netback basis and 1.9 times based on the corporate netback. Both of these measures will deliver long term added value.

FORWARD LOOKING INFORMATION

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

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



QUARTERLY INFORMATION

2008

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

($000's except as noted) Q2 Q1

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Sales volumes:

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

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

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

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Financial:

Net revenue 20,738 14,517

Net (loss) (1,612) (5,413)

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

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

Capital costs 2,715 11,586

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

Bank debt 53,000 58,500

Working capital (deficit)

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

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Per unit information:

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

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

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

Operating netback ($/boe) $46.31 $32.36

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Net wells completed: (No.)

Natural gas - 5

Oil - -

Dry - -

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Total - 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 11,864 12,739 11,793

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

per share - basic

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

per share - diluted

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

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

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

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

Working capital (deficit)

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

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Per unit information:

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

Oil and liquids price

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

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

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

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Net wells completed: (No.)

Natural gas 3 5 1 5

Oil - 2 - -

Dry - 1 - 1

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Total 3 8 1 6

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2006

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

($000's except as noted) Q4 Q3

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Sales volumes:

Natural gas (mcf/day) 18,440 17,355

Oil and natural gas liquids

(bbl/day) 483 479

Barrels of oil equivalent

(bbl/day) 3,556 3,372

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Financial:

Net revenue 11,213 9,536

Net (loss) (21,951) (2,662)

per share - basic

($/share) $(0.24) $(0.03)

per share - diluted

($/share) $(0.24) $(0.03)

Capital costs 12,811 9,746

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

Bank debt 50,080 52,780

Working capital (deficit)

including bank debt (56,271) (61,783)

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Per unit information:

Natural gas price ($/mcf) $7.13 $5.91

Oil and liquids price

($/barrel) $51.54 $62.07

Oil equivalent price ($/boe) $43.96 $39.24

Operating netback ($/boe) $24.24 $21.54

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Net wells completed: (No.)

Natural gas 7 3

Oil - -

Dry 1 1

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Total 8 4

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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 4,139 boe/d for the quarter ended June 30, 2008, up seven percent compared to 3,880 boe/d for the quarter ended June 30, 2007 and up nine percent from the first quarter of 2008. Natural gas represented 79 percent of production in the second 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 six months ended June 30, 2008 volume averaged 3,975 boe/d, up six percent over the six months ended June 30, 2007.

High drilling success rates, primarily in Pembina were experienced in the first quarter of 2008 and significant production brought on stream late in the first quarter which contributed to the higher production levels in the second quarter of 2008. A total of nine wells (4.7 net) were completed in the first quarter with six successful (3.8 net) natural gas wells in Pembina and two (0.5 net) successful natural gas wells in Deep Basin with one (0.4 net) unsuccessful well in Deep Basin. Drilling commenced very late in the second quarter due to spring break-up conditions in all core areas.

Production Revenue

Natural gas prices averaged $10.55 per mcf for the quarter ended June 30, 2008, up 39 percent compared to $7.60 per mcf in the quarter ended June 30, 2007. Oil and liquids prices averaged $115.13 and $99.77 per barrel respectively for the quarter ended June 30, 2008 for a blended price of $103.76 per barrel, up 76 percent from the quarter ended June 30, 2007 blended oil and liquids price of $58.98 per barrel. On a boe basis prices averaged $71.70 per boe in the quarter ended June 30, 2008, up 51 percent compared to $47.51 per boe in the quarter ended June 30, 2007. Oil and natural gas revenue was up 61 percent in the quarter ended June 30, 2008 compared to the quarter ended June 30, 2007 as both volume and prices increased. Realized hedging losses during the second quarter of 2008 were $6.91 per boe compared to realized hedging gains of $0.27 per boe in the second quarter of 2007.

For the six months ended June 30, 2008, natural gas prices averaged $9.35 per mcf up 22 percent compared to $7.67 per mcf in the six months ended June 30, 2007. Combined oil and liquids prices averaged $94.47 per barrel for the six months ended June 30, 2008, up 65 percent from the six months ended June 30, 2007 blended oil and liquids price of $57.22 per barrel. On a boe basis prices averaged $63.29 per boe in the six months ended June 30, 2008, up 33 percent compared to $47.61 per boe in the six months ended June 30, 2007. Oil and natural gas revenue was up 42 percent for the six months ended June 30, 2008 compared to the six months ended June 30, 2007 as both volume and prices increased. Realized hedging losses during the six months ended June 30, 2008 were $3.81 per boe compared to realized hedging gains of $0.14 per boe in the six months ended June 30, 2007.



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Volumes and prices Three months Six months

ended June 30, ended June 30,

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2008 2007 Change 2008 2007 Change

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Production revenue

($000's) 27,008 16,784 61% 45,801 32,327 42%

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Production volume

Natural gas

(mcf/d) 19,677 19,919 (1%) 19,390 19,315 -

Oil and liquids

(bbl/d) 859 560 53% 744 530 40%

BOE (bbl/d) 4,139 3,880 7% 3,975 3,749 6%

Prices

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Natural gas

($/mcf) 10.55 7.60 39% 9.35 7.67 22%

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Oil and liquids

($/bbl) 103.76 58.98 76% 94.47 57.22 65%

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BOE ($/boe) 71.70 47.51 51% 63.29 47.61 33%

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BOE ($/boe

including

hedging) 64.79 47.78 36% 59.48 48.00 24%

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Royalties

Royalties averaged 23 percent of revenue for the quarter and six months ended June 30, 2008 compared to 24 percent for the quarter and six months ended June 30, 2007. Royalties have trended lower on a percent of revenue basis as more wells are drilled on owned and earned lands compared to earlier periods when a higher percentage of wells were drilled under farm-in arrangements that provided for overriding royalties to the farmor.

Royalty expense of $6.3 million was recorded in the quarter ended June 30, 2008, up 51 percent compared to the quarter ended June 30, 2007 due to higher production volume and revenue offset by lower percentage royalty rates. For the six months ended June 30, 2008 royalty expense was $10.5 million, up 33 percent compared to the six months ended June 30, 2007 again, due to higher production volume and revenue.



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Royalties Three months Six months

ended June 30, ended June 30,

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2008 2007 Change 2008 2007 Change

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Royalty expense

($000's) 6,270 4,140 51% 10,546 7,904 33%

Royalty cost per

boe $16.65 $11.73 42% $14.58 $11.65 25%

Royalty cost as a

percent of revenue 23% 24% (4%) 23% 24% (4%)

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Production Expenses

Production expenses were $7.68 per boe in the quarter ended June 30, 2008, up 12 percent compared to $6.87 per boe in the quarter ended June 30, 2007. For the six months ended June 30, 2008 production expenses were $7.98 per boe, up seven percent compared to the six months ended June 30, 2007. Costs in 2008 have been higher due to ongoing inflationary pressures in the industry and vigilance on costs remains a key objective. With ongoing volume increases and cost management, it is expected per unit operating expenses will be in the $7.50 per boe range for the remainder of the year.

Production expenses for the quarter ended June 30, 2008 were $2.9 million, up 19 percent compared to the quarter ended June 30, 2007 due to higher volumes and higher per unit costs. For the six months ended June 30, 2008 production expenses were $5.8 million, up 14 percent due to higher production and higher per unit costs.



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Production expenses Three months Six months

ended June 30, ended June 30,

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2008 2007 Change 2008 2007 Change

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Production expenses

($000's) 2,894 2,426 19% 5,774 5,072 14%

Production expenses

per boe $7.68 $6.87 12% $7.98 $7.47 7%

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Transportation costs increased 10 percent in the quarter ended June 30, 2008
compared to the quarter ended June 30, 2007 due to higher volume and higher
per unit costs due to increased transportation rates on major natural gas trunk
pipelines.

Operating Netback(1)

Operating netback represents the margin realized by the production and sale
of petroleum and natural gas exclusive of results from hedging. Second quarter
2008 operating netbacks improved due to higher per boe prices, lower percentage
royalty costs and stable operating costs.

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Quarterly Operating

Netbacks Three months Six months

($'s per boe) ended June 30, ended June 30,

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2008 2007 Change 2008 2007 Change

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Sales price 71.70 47.51 51% 63.29 47.61 33%

Less:

Royalties 16.65 11.73 42% 14.58 11.65 25%

Production

expenses 7.68 6.87 12% 7.98 7.47 7%

Transportation

charges 1.06 1.03 3% 1.11 0.95 17%

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Operating netback 46.31 27.88 66% 39.62 27.53 44%

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Operating netback

including hedging 39.40 27.47 43% 35.81 27.34 31%

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


General and Administrative Expenses

For the quarter ended June 30, 2008 general and administrative ("G&A") expenses including stock based compensation were $2.0 million, up 48 percent compared to the quarter ended June 30, 2007. G&A charged to partners on capital spending during the second quarter of 2008 was lower than in the second quarter of 2007 as the total level of capital spending was lower in the 2008 period and wells were being drilled at higher average working interests. During the second quarter of 2008 certain stock option holders of expiring options elected to be paid in cash compensation for the difference between the exercise price and market price of their options which increased G&A for the quarter by $124,000. Stock based compensation was significantly higher in the second quarter of 2008 compared to the second quarter of 2007 as 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. This resulted in a one time charge to stock based compensation of $247,000 in the second quarter of 2008.

On a per unit basis, for the quarter ended June 30, 2008 per unit cash G&A costs excluding stock based compensation were $3.95 per boe, up 27 percent from $3.10 per boe for the quarter ended June 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 $5.21 per boe for the quarter ended June 30, 2008, up 39% compared to $3.75 for the quarter ended June 30, 2007. There were no general and administrative costs capitalized for the quarters ended June 30, 2008 or 2007.

For the six months ended June 30, 2008 G&A costs including stock based compensation were $3.4 million, up 37 percent compared to the six months ended June 30, 2007 due to lower capital recoveries, option payouts and higher stock based compensation charges described above. On a per unit basis, for the six months ended June 30, 2008 per unit cash G&A costs excluding stock based compensation were $3.73 per boe, up 25 percent from $2.99 per boe for the six months ended June 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. Without the one-time charges experienced in the second quarter, per unit general and administrative costs are expected to return to similar levels as in 2007.



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General and administrative Three months Six months

expenses ended June 30, ended June 30,

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2008 2007 Change 2008 2007 Change

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G&A expenses

($000's) 1,487 1,095 36% 2,686 2,028 32%

G&A expense per boe $3.95 $3.10 27% $3.73 $2.99 25%

Stock based

compensation

($000's) 474 230 106% 693 433 60%

Stock based

compensation

per boe $1.26 $0.65 93% $0.96 $0.64 50%

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Total 1,961 1,325 48% 3,379 2,461 37%

G&A expenses per

boe $5.21 $3.75 39% $4.69 $3.63 29%

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Interest Expense

For the quarter ended June 30, 2008 interest expense was $0.8 million or 29 percent lower compared to $1.1 million for the quarter ended June 30, 2007. Average amounts drawn on the bank operating line in the first quarter of 2008 were lower than in the first quarter of 2007 as Marten Hills assets were sold for $6.75 million in the third quarter of 2007 and capital spending has been below cash flow for the first six months of 2008. Average interest rates have been lower in the 2008 period compared to 2007. In addition the borrowing premium charged by the bank declines as the debt to cash flow ratio improves resulting in a 0.4 percent reduction in borrowing cost as the debt to cash flow ratio has declined.

For the six months ended June 30, 2008 interest expense was $1.7 million or 18 percent lower compared to $2.0 million for the six months ended June 30, 2007 for the same reasons described above.



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Interest expense Three months Six months

ended June 30, ended June 30,

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2008 2007 Change 2008 2007 Change

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Interest expense

($000's) 763 1,070 (29%) 1,662 2,025 (18%)

Interest expense

per boe $2.03 $3.03 (33%) $2.31 $2.98 (22%)

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Depletion, Amortization and Accretion

In the quarter ended June 30, 2008 Depletion, Amortization and Accretion ("DA&A") totaled $10.0 million ($26.56 per boe) down six percent compared to $10.6 million ($30.09 per boe) for the quarter ended June 30, 2007. The per unit depletion rate declined 12 percent comparing the second quarter of 2008 to the second quarter of 2007 as ongoing drilling success and low cost reserve additions have brought down per unit DA&A rates throughout 2007 and 2008. This per unit reduction has more than offset the increase in DA&A charge due to higher production volume. For the six months ended June 30, 2008 DA&A totaled $18.9 million ($26.32 per boe), down five percent and down 11 percent on a per unit basis from $20.0 million ($29.42 per boe) for the six months ended June 30, 2007.



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Depletion, Amortization Three months Six months

and Accretion ended June 30, ended June 30,

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

2008 2007 Change 2008 2007 Change

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DA&A expense

($000's) 10,005 10,623 (6%) 18,933 19,967 (5%)

DA&A expense per

boe $26.56 $30.09 (12%) $26.32 $29.42 (11%)

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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 LOSS

The net loss for the quarter ended June 30, 2008 was $1.6 million ($0.02 per share) compared to a net loss of $0.6 million ($0.01 per share) for the quarter ended June 30, 2007 as higher production volume and commodity prices were offset primarily by unrealized hedging losses recorded in the quarter. Adjusting for the after tax amount of the unrealized loss on risk management activities of $4.6 million in the second quarter of 2008, net income was $1.6 million. For the six months ended June 30, 2008 the net loss was $7.0 million or $0.08 per share compared to a loss of $3.6 million or $0.04 per share for the six months ended June 30, 2007. Again, adjusting for the after tax unrealized hedging loss recorded in the first six months of 2008, net income was $1.6 million.

CAPITAL COSTS

For the quarter ended June 30, 2008 $2.7 million in capital costs on exploration and production activities were incurred compared to $6.2 million for the quarter ended June 30, 2007. No wells were drilled in the second quarter of 2008 until very late in the quarter as spring break-up extended well into June this year. For the six months ended June 30, 2008 total spending was $14.3 million compared to $24.4 million in the first six months of 2007. Five net wells were completed in the first six months of 2008 compared to seven net wells completed in the first six months of 2007. In addition, significant decreases in drilling costs have been realized in the 2008 period as operations have improved with full time staff dedicated to the drilling program and a general easing in industry cost pressures.



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Three months Six months

($000's) ended June 30, ended June 30,

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

2008 2007 2008 2007

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Drilling and completion 1,638 2,756 9,322 14,550

Equipping and tie-ins 58 2,364 2,543 7,647

Land 264 519 1,605 626

Geological and geophysical 751 566 824 1,530

Office and other 4 3 7 15

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Total 2,715 6,208 14,301 24,368

Asset retirement obligation 39 3 392 171

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Total capital 2,754 6,211 14,693 24,539

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Drilling, completion, equip and tie-in activity represented 83 percent of the capital spent in the first six months of 2008 as capital activity focused on developing the extensive land base. A $40 million capital budget is planned for 2008, 92 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 $14.0 million at June 30, 2008 were primarily revenue receivables ($9.1 million) and amounts owing from partners ($4.2 million). Accounts payable at June 30, 2008 of $13.3 million were mainly comprised of trade payables for capital and operating costs ($5.8 million), royalties ($2.2 million), amounts owing to partners ($1.1 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($1.3 million).

Working capital excluding bank indebtedness and the unrealized loss on risk management activities was in a surplus position of $1.2 million at June 30, 2008.

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. An operating bank line was in place for $66 million at June 30, 2008, secured by producing properties. At June 30, 2008, $53.0 million was drawn on the bank 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 March 31 is as follows:



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

Three months Six months

($000's) ended June 30, ended June 30,

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

2008 2007 2008 2007

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

Cash flow provided by

operating activities 9,228 3,184 14,908 10,836

Changes in non-cash working

capital items related to

operating activities 3,342 4,598 6,931 3,916

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

Funds from operations 12,570 7,782 21,839 14,752

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

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


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 $0.13 per share (basic and diluted) for the quarter ended June 30, 2008 compared to $0.08 for the quarter ended June 30, 2007 as funds from operations increased with higher volume and commodity prices and only 375,000 shares were issued in the past year for stock options exercised. For the six months ended June 30, 2008 funds from operations per share were $0.23 per share compared to $0.16 per share for the six months ended June 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 4.86 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 June 30, 2008 resulted in an unrealized loss of $43,000 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 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 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 June 30, 2008, results in an unrealized loss position of $12,133,000 compared to an unrealized gain position of $162,000 at December 31, 2007 as crude oil and natural gas prices have increased significantly since December 31, 2007. There was $2,741,000 ($6.91 per boe) of realized losses on derivative instruments for the quarter ended June 30, 2008 (2007 - $95,000 gain). For the six months ended June 30, 2008 $2,601,000 ($3.81 per boe) in realized losses on derivative instruments were recorded (2007 - $108,000 gain). The average fixed price of the natural gas hedging transactions for the remainder of 2008 is $6.82 per GJ ($7.18 per mcf) which will provide protection to corporate cash flow if natural gas prices fall below these levels. The average floor price for the oil hedges is $85.00 per barrel.

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



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

Commodity Price change Cash flow change

($ 000's)

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

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

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

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

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


RELATED PARTY TRANSACTIONS

Fees for legal services are paid to a law firm in which the corporate secretary is a partner. The legal services are rendered in the normal course of business at normal rates charged by the law firm. Legal fees for this firm paid for the quarter ended June 30, 2008 were $105,000 (2007 - $98,000).

SHARE DATA

As of the date of this MD&A the Company had 93,547,064 issued and outstanding common shares. Additionally, as at August 12, 2008 options to purchase 6,119,700 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 Instutute 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 11. Effective January 1, 2008 the company adopted CICA recommendations relating to Capital Disclolsures (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 March 31, 2008 $872,000 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.

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

Drilling success experienced throughout 2007 and the first quarter of 2008 has resulted in steady increases to production volume and cash flows. The strong cash flows have resulted in an improved balance sheet and the ability to increase the 2008 capital spending program to $40 million from the original budget of $30 million. The increase in capital spending is expected to remain within cash flow for the year and debt levels are expected to remain well below 1.5 times cash flow.

The increase in the capital spending budget will be 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. Seven wells have been drilled in Lanfine and two in Pembina since the end of the second quarter with success rates that mirror our recent quarters. As many as 10 more wells are planned for Pembina by the end of 2008 with one additional well in Deep Basin before the end of the year.

Debt and working capital balances have improved and will continue to improve with the planned capital spending plans. Based on second quarter results on an annualized basis, debt and working capital (excluding the unrealized loss on risk management) represents 1.0 times funds from operations. With an extensive land base, a large number of inventoried drilling locations and an increased capital budget, management looks forward to developing our asset base more aggressively in the second half of 2008.



Berens Energy Ltd.

Balance Sheets - unaudited

As at,

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

(000's) June 30, December 31,

2008 2007

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

ASSETS (note 6)

Current

Cash and cash equivalents $ 1 $ 1

Accounts receivable 14,021 10,315

Unrealized gain on risk management (note 10) - 162

Prepaid expenses and deposits 557 442

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

14,579 10,920

Property, plant and equipment

(note 4) 162,347 166,405

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

$ 176,926 $ 177,325

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

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

LIABILITIES AND SHAREHOLDERS' EQUITY

Current

Bank loan (note 7) $ 53,000 $ 53,900

Accounts payable and accrued liabilities 13,335 16,523

Unrealized loss on risk management (note 10) 12,176 -

Taxes payable 10 14

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

78,521 70,437

Asset retirement obligations (note 5) 3,848 3,273

Future income taxes 7,098 10,199

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

89,467 83,909

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

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

Shareholders' equity

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

Contributed surplus (note 7) 2,888 2,195

Deficit (64,067) (57,042)

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

87,459 93,416

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

$176,926 $177,325

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

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

See accompanying notes to the unaudited interim financial statements



Berens Energy Ltd.

Statements of Operations, Comprehensive Loss and Deficit - unaudited

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

(000's) Three months Six months

ended June 30, ended June 30,

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

2008 2007 2008 2007

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

Revenue

Oil and natural gas

revenue $ 27,008 $ 16,784 $ 45,801 $ 32,327

Royalties (6,270) (4,140) (10,546) (7,904)

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

20,738 12,644 35,255 24,423

Realized gain (loss) on

commodity price risk

management (note 10) (2,741) 95 (2,601) 108

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

17,997 12,739 32,654 24,531

Unrealized gain (loss) on

commodity price risk

management (note 10) (4,602) 2,035 (12,295) 828

Other income 119 119

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

13,514 14,774 20,478 25,359

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

Expenses

Production 2,894 2,426 5,774 5,073

Transportation 399 363 806 648

Depletion, amortization and

accretion 10,005 10,623 18,933 19,967

General and administrative

(note 9) 1,487 1,095 2,686 2,028

Stock-based compensation

(note 7) 474 230 693 433

Interest 763 1,070 1,662 2,025

Unrealized loss (gain) on

interest rate risk

management (note 10) (141) - 43 -

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

15,881 15,807 30,597 30,174

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

Loss before income taxes (2,367) (1,033) (10,119) (4,815)

Income taxes

Future recovery (758) (479) (3,100) (1,217)

Current expense 3 3 7 5

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

(755) (476) (3,093) (1,212)

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

Net loss and comprehensive

loss for the period (1,612) (557) (7,026) (3,603)

Deficit, beginning of period (62,455) (32,648) (57,041) (29,602)

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

Deficit, end of period $ (64,067) $(33,205) $(64,067) $(33,205)

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

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

Net loss per share

(note 11)

Basic and diluted $ (0.02) $ (0.01) $ (0.08) $ (0.04)

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

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

See accompanying notes to the unaudited interim financial statements



Berens Energy Ltd.

Statements of Cash Flows - unaudited

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

(000's) Three months Six months

ended June 30, ended June 30,

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

2008 2007 2008 2007

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

OPERATING ACTIVITIES

Net loss for the quarter $ (1,612) $ (557) $ (7,026) $ (3,603)

Add items not involving cash

Depletion, amortization

and accretion 10,005 10,623 18,933 19,967

Unrealized risk

management loss 4,461 (2,035) 12,339 (828)

Future income tax

recovery (758) (479) (3,100) (1,217)

Stock-based compensation 474 230 693 433

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

12,570 7,782 21,839 14,752

Change in non-cash working

capital items related to

operating activities

(note 8) (3,342) (4,598) (6,931) (3,916)

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

Cash flow provided by

operating activities 9,228 3,184 14,908 10,836

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

FINANCING ACTIVITIES

Change in bank loan (5,500) 2,720 (900) 12,620

Proceeds from exercise

of stock options 375 225 375 225

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

Cash flow provided by

financing activities (5,125) 2,945 (525) 12,845

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

INVESTING ACTIVITIES

Purchase of property

and equipment (2,715) (6,208) (14,302) (24,368)

Proceeds from sale of

investment - 26 - 26

Change in non-cash working

capital items related to

investing activities

(note 8) (1,389) 53 (81) 661

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

Cash flow used in investing

activities (4,104) (6,129) (14,383) (23,681)

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

Increase in cash and

cash equivalents (1) - - -

Cash and cash equivalents,

beginning of period 2 10 1 10

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

Cash and cash equivalents,

end of period $ 1 $ 10 $ 1 $ 10

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

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

See accompanying notes to the unaudited interim financial statements



BERENS ENERGY LTD.

Notes to Financial Statements - unaudited

Three and six months ended June 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.

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 11.

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 June 30, 2008 $863,000 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

June 30, 2008 December 31, 2007

Accumulated Accumulated

depletion and depletion and

($000's) Cost depreciation Cost depreciation

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

Petroleum and natural

gas properties 288,753 126,766 274,067 108,045

Office and computer

equipment 740 380 734 351

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

289,493 127,146 274,801 108,396

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

Net book value 162,347 166,405

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

At June 30, 2008, costs of $22,325,000 (December 31, 2007 - $21,159,000)

related to undeveloped land have been excluded from the depletion and

depreciation calculation. At June 30, 2008 estimated future development

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

calculation.

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 $3,848,000 as at

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

liability of $9,089,000 (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 392

Accretion expense 183

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

Obligation, June 30, 2008 3,848

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

6. BANK OPERATING LINE

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

totaling $66 million at June 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 average rate

paid for the quarter ended June 30, 2008 was 5.6 percent

(2007 - 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 June 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 six months ended June 30, 2008:

2008 2007

Weighted Weighted

average average

exercise exercise

Number of price ($ Number of price ($

Options per share) Options per share)

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

Outstanding,

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

Granted 1,779,000 1.01 1,467,000 1.02

Cancelled (1,052,500) 2.88 (238,667) 1.99

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

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

Outstanding,

end of period 6,119,700 1.11 5,419,533 1.52

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

Exercisable 2,320,024 1.28 2,632,028 1.44

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

The following table sets forth additional information relating to the

stock options outstanding at June 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 2,740,500 0.88 4.15 341,356 0.99 3.54

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

$1.00 to $1.49 2,668,700 1.20 2.83 1,473,698 1.24 1.36

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

$1.50 to $1.99 705,500 1.61 1.95 501,667 1.60 1.46

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

$2.00 to $2.49 - - - - - -

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

$2.50 to $3.00 5,000 2.90 2.42 3,333 2.42 2.90

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

$0.50 to $3.00 6,119,700 1.11 3.32 2,320,024 1.28 1.71

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

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 of options outstanding at June 30, 2008 is $0.558 per

option. For the quarter ended June 30, 2008, $474,000 and for the

six months ended June 30, 2008 $693,000 was recorded for stock based

compensation (2007 - $230,000 and $433,000) with a corresponding increase

recorded to contributed surplus.

(d) Contributed Surplus

The following table sets forth the continuity of contributed surplus for

the period ended June 30, 2008:

($000's)

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

December 31, 2007 2,195

2008 Stock based compensation expense 693

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

June 30, 2008 2,888

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

8. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in Non-cash Working Capital

For the six months ended June 30,

($000's) 2008 2007

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

Accounts receivable (3,707) 1,338

Prepaid expenses and deposits (114) 26

Accounts payable and accrued liabilities (3,187) (4,624)

Taxes payable (4) 5

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

(7,012) (3,255)

Change in non-cash working capital related

to investing activities (81) 661

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

Change in non-cash working capital related

to operating activities (6,931) (3,916)

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

Cash interest and taxes paid

For the three and six months ended June 30,

Three Three Six Six

months months months months

($000's) 2008 2007 2008 2007

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

Income and other taxes 10 (*) 10 -

Interest 763 1,070 1,662 2,025

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

9. RELATED PARTY TRANSACTIONS

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

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

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

for this firm paid for the quarter ended June 30, 2008 were $105,000

(2007 - $98,000).

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". Accounts receivable

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

designated as "other liabilities". The fair value of these financial

instruments approximates their carrying amounts due to their short terms

to maturity except for derivatives used for interest rate and commodity

price risk management which values are outlined below.

(a) Credit Risk

Accounts receivable are with customers, sales agents and joint venture

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

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

transactions with long-standing, reputable counterparties and partners.

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

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

spending taking place. The maximum credit exposure with accounts

receivable is the carrying value. At June 30, 2008, the largest single

credit exposure was approximately $8.5 million from the Company's sales

agent the balance of which is settled monthly. At June 30, 2008, nine

percent of accounts receivable were non-current as defined by accounts

over 90 days outstanding. No allowance for doubtful accounts receivable

has been recorded nor are any 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 June 30, 2008 results in an

unrealized gain of $141,000. 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 June 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 Term of Contract Fixed price per gigajoule

quantity (Cdn$/GJ)

(GJ/day)

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

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 Term of Contract Fixed price per barrel

quantity (WTI in Cdn$)

(Barrels/d)

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

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 June 30,

2008 results in an unrealized loss of $12,133,000 (December 31, 2007 -

gain of $162,000). Total realized losses from risk management activities

in the second quarter of 2008 were $2,742,000 (2007 - $13,000 gain).

Total realized losses for the six months ended June 30, 2008 were

$2,601,000 (2007 - $95,000 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 net income summarized in the following table.

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

Commodity Price change Cash flow 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 June 30,

2008 this ratio was 1.0:1.

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

Target

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

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

Components of Ratio

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

Current assets 14,579 21,123

Current liabilities (78,521) (84,733)

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

(63,942) (63,610)

Unrealized risk management loss (gain) 12,176 (1,463)

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

Debt and working capital (51,766) (65,073)

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

Funds from operations - three months

ended June 30 annualized(1) 50,280 31,128

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

Ratio 1.5:1 1.0:1 2.1:1

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

(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 June 30, 2008 of 93,192,668 was used to calculate basic and diluted

income (loss) per share (2007 - 92,973,713). The weighted average number

of common shares outstanding for the six months ended June 30, 2008 was

93,182,367 (2007 - 92,960,461). All of the outstanding options have been

excluded from the calculation of diluted per share information as they

were anti-dilutive. The total number of shares which are potentially

dilutive in future periods as of June 30, 2008 was 6,119,700.

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