Berens Energy Ltd.
TSX : BEN

August 13, 2009 09:00 ET

Berens Energy Ltd. Releases Financial Results for the Second Quarter and Six Months Ended June 30, 2009

CALGARY, ALBERTA--(Marketwire - Aug. 13, 2009) - Berens Energy Ltd. (TSX:BEN)



FINANCIAL AND OPERATING HIGHLIGHTS

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($ Cdn thousands, Three months ended Six months ended
except as noted) June 30, June 30,
% %
2009 2008 Change 2009 2008 Change
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Sales volume
Natural gas
(mcf/day) 20,152 19,677 2% 20,939 19,390 8%
Oil and ngls
(bbl/day) 821 859 (4%) 874 744 18%
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boe/day (6 to 1) 4,180 4,139 1% 4,364 3,975 10%
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Revenue net of
royalties 9,038 20,738 (56%) 19,905 32,255 (38%)
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Net income (loss) (3,782) (1,612) (134%) (6,868) (7,026) 2%
Per share (basic
and diluted) $(0.04) $ (0.02) $ (0.07) $ (0.08)
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Funds from
operations(1) 3,867 12,570 (69%) 9,515 21,838 (56%)
Per share (basic and
diluted)(1) $ 0.04 $ 0.13 $ 0.10 $ 0.23
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Capital costs
Exploration and
development 1,569 1,696 (7.5%) 11,730 11,865 (1%)
Land and seismic 408 1,015 (60%) 1,598 2,429 (34%)
Other - 4 - - 7 -
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Total 1,977 2,715 (27%) 13,328 14,301 (7%)
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Net wells completed (#) - - 4 5
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Net working capital
deficit - excluding
unrealized hedging
losses(2) (60,966) (51,766) 18% (60,966) (51,766) 18%
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Net working capital
deficit - including
unrealized hedging
losses (61,906) (63,942) (5%) (61,906) (64,942) (5%)
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Shares outstanding
End of period
(000's) 93,547 93,547 - 93,547 93,547 -
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(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.

(2) Non-GAAP measure - adjusts working capital for unrealized hedging gains
and losses.


Second Quarter 2009 Operating Highlights

- Production - Q2 2009 production averaged 4,180 boe/d, up 1% over Q2 2008. Production for the first six months of 2009 averaged 4,364 boe/d, up 10% over the first six months of 2008. Significant plant turn around activity took place in the second quarter of 2009 resulting in an average of approximately 150 boe/d shut in during the quarter. In addition, production continues to be restricted in Lanfine to preserve net asset value for certain wells under the new royalty framework that took effect on January 1, 2009.

- Capital Spending - Minimal capital spending took place in the second quarter with no drilling taking place due to spring break-up. Planned capital spending for 2009 is $26 million. Average 2009 production is expected to be approximately 4,400 boe/d, an increase of 4% over average production in 2008. The operating bank line has been reviewed and extended at $66 million until January 1, 2010 which will provide adequate financial flexibility to execute the planned capital spending.

- Funds from Operations - Funds from operations for Q2 2009 were $3.9 million ($0.04 per share), down 69% compared to Q2 2008. For the first six months of 2009 funds from operations were $9.5 million, down 56% compared to the first six months of 2008. Weak natural gas and oil prices have more than offset production gains and cost improvements.

- Land - Berens' total undeveloped land currently stands at 70,000 net acres. The undeveloped land base in Pembina has continued to increase as 12 (9.0 net) sections of undeveloped land have been added so far during 2009. The land gains in Pembina have been offset by non-prospective acreage expiries in the second quarter of 2009 primarily in Lanfine, Deep Basin and non-core areas. Undeveloped land declined by 11,000 acres in the quarter.

- Cardium Resource Play - Recent success has been experienced by industry competitors drilling for light oil in the Cardium zone using horizontal well and multi-frac technologies in the general Pembina area. Berens has been monitoring this new play and has approximately 68 sections (38 net) of Cardium rights on the flank of the large Cardium oil field in central Alberta. The Cardium zone in many of Berens' sections has attributes similar to successful horizontal wells drilled by competitors on the flanks of the Cardium oil field. Two wells are planned for the third and fourth quarters to assess the potential of this exciting emerging resource play.

- Drilling Inventory - We continue to have approximately 85 locations in our drilling inventory and are well positioned to accelerate activity when natural gas prices improve. With success in the emerging Cardium oil resource play, additional drilling inventory will be added on existing, developed acreage.

Message to the shareholders

In what is normally a quiet quarter due to spring break-up Berens was building for the future. No wells were drilled in the quarter but a strong group of drilling locations has been worked up for the second half of 2009 that will add to our reserve and production base and enhance our land position in Pembina. We are off to a great start in the second half of 2009 as we have drilled two wells since the end of the second quarter, both strong natural gas wells in Pembina. The two horizontal, multi-stage frac wells we drilled in Pembina in the fourth quarter of 2008 and the first quarter of 2009 continue to meet or exceed our expectation. The first well, brought on in November 2008 continues to produce strongly at just under 1.5 mmcf/d. Our second well, brought on stream in March, has produced at a steady, restricted rate of 4 mmcf/d since it came on stream. With the strong inventory of wells planned for the balance of 2009 we remain confident that we will continue to be a leading company in finding and development costs.

Perhaps the most exciting development in the second quarter of 2009 was the emergence of a new potential resource play over which Berens has significant land holdings in Pembina. We have continually evaluated the Cardium oil potential on our Pembina lands and recent industry success in the greater Pembina area using horizontal wells and multi-stage frac technology to drill light oil wells in the Cardium zone has validated this resource play. Nearby vertical wells in the Cardium have had mixed economics due to the tight sands that typify the zone. Horizontal well and multi-stage frac technology appears to be opening up this play in a fashion similar to industry experience in the tight sand Bakken formations in Saskatchewan. We have 68 sections (38 net) of Cardium rights on existing lands in Pembina. We will be drilling two horizontal wells to the Cardium in the third and fourth quarters of 2009 to test this play on our lands. With success our drilling inventory could expand significantly.

Natural gas prices remain weak. However, with low current drilling activity in Canada and the US, we believe that reduced natural gas supply will lead to gas price recovery perhaps sooner than many anticipate. We are also seeing lower activity result in reduced costs for materials and services in the field. We have lived within the discipline of spending within cash flow for the past three years and will continue to do so. Our 2009 capital budget of $26 million can be funded with cash flow and drilling credits and we will maintain debt levels close to current levels. I'm pleased to note that our bank line has been extended at $66 million until January 1, 2010 which gives us even further financial flexibility to execute our drilling plans.

Until we see a recovery in natural gas prices we will focus drilling only on wells that will earn lands on farm-in commitments or preserve prospective expiring lands. We have already had success in 2009 adding to our land and prospect inventory with 12 new sections added Pembina so far this year and we continue to work on a number of farm-in proposals. Our strategy of adding land and drilling inventory while prices are weak will position us to accelerate activity when natural gas prices recover.

Sincerely,

Daniel F. Botterill, President & Chief Executive Officer

Berens Energy Ltd.

Second Quarter 2009

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

August 13, 2009

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 Pembina, Deep Basin and Eastern 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 June 30, 2009 unaudited financial statements and its December 31, 2008 audited financial statements and notes thereto. This MD&A was prepared using information that is current as of August 12, 2009 unless otherwise noted.

STRATEGY AND OBJECTIVES

The Company has established key performance metrics for 2009 that are evaluated and reviewed quarterly within the context of an annual capital program that is funded by projected cash flows. The 2009 capital budget of $26 million is based on an assumed Cdn$4.00 price for natural gas at AECO and Edmonton reference light oil at Cdn$60.00. The current strategy in the low natural gas price environment is focused on adding land and drilling inventory through farm-ins and land deals that are earned by drilling wells that also benefit from the drilling credit program recently announced by the Province of Alberta. Key performance metrics include production volume growth, finding and development costs, reserve additions, operating and corporate netbacks and return on investment. In the current environment of volatile commodity prices the Company's strategy will adhere to a capital spending program that matches corporate cash flows and as such, actual capital spending may vary from the budget amounts outlined above.

Volume growth is an important equity market measurement that is reported frequently and measures the ability of the capital spending program to add near term cash flow. The Company expects production volume to average 4,400 boe per day in 2009 under the $26 million capital plan, up four percent compared to 2008 average production of 4,222 boe per day.

Longer term value is achieved by adding oil and natural gas reserves at low cost. The Company expects to replace 1.5 times 2009 production with new reserves at finding and development costs below $14.00 per boe. Operating and corporate netbacks are expected to be $20.00 and $14.00 per boe respectively assuming a $4.00 per mcf price for natural gas and $60.00 per barrel for oil. Resulting recycle ratios based on the above factors are approximately 1.3 times on an operating netback basis and 1.0 times based on the corporate netback.

ECONOMIC UNCERTAINTY

Recent economic events have created volatility and an uncertain environment for stock and credit markets and commodity prices in the foreseeable future. Berens' bank line of credit is $65 million at June 30, 2009. Subsequent to June 30, 2009 the bank line was renewed at $66 million until January 1, 2010 at which time it reduces by $1.0 million per month until a February 2010 review date. The December 31, 2009 reserves evaluation will then be taken into consideration to re-establish a new, go forward bank line amount. Further, the Company has conducted its capital spending program within cash flow since the second quarter of 2006 in periods of both high and low commodity prices. During this period Berens has shown consistent growth in both reserves and production. Debt and working capital deficiency was $61.9 million at June 30, 2009. Capital spending for the balance of 2009 is forecasted to be approximately $9 million net of drilling credits resulting in a debt and working capital deficiency balance of approximately $62 million at December 31, 2009.

Berens has a focused asset base with high working interest and operates approximately 85% of its planned capital spending. This high working interest and operatorship allows Berens to control the pace and focus of its capital spending to maintain financial flexibility in various commodity price and economic environments.

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

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2009 2008 2007
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($000's
except as
noted) Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
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Sales
volumes:
Natural gas
(mcf/day) 20,152 21,735 23,632 19,592 19,677 19,104 19,018 18,288
Oil and
natural gas
liquids
(bbl/day) 821 927 882 845 859 628 626 570
Barrels of
oil
equivalent
(boe/day) 4,180 4,550 4,821 4,110 4,139 3,812 3,796 3,618
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Financial:
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Net revenue 9,038 10,866 14,516 17,368 20,738 14,517 13,214 11,864
Net income
(loss) (3,782) (3,086) (698) 8,167 (1,612) (5,413) (680)(23,157)
per share -
basic
($/share) (0.04) (0.03) (0.01) 0.09 (0.02) (0.06) (0.01) (0.25)
per share -
diluted
($/share) (0.04) (0.03) (0.01) 0.09 (0.02) (0.06) (0.01) (0.25)
Capital
costs 1,977 11,351 11,979 13,997 2,715 11,586 6,718 8,541
Shares
outstanding
(000's) 93,547 93,547 93,547 93,547 93,547 93,172 93,172 93,172
Bank debt 60,500 61,000 54,600 48,500 53,000 58,500 53,900 50,800
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Working
capital
(deficit)
including
bank debt (61,906)(64,054)(59,386)(57,040)(64,943)(69,711)(59,516)(58,594)
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Working
capital
(deficit)
including
bank debt
and
excluding
unrealized
hedging
gains and
losses(1) (60,966)(62,956)(58,751)(56,819)(51,766)(61,996)(59,678)(60,051)
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Per unit
information:
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Natural gas
price
($/mcf) 3.82 5.57 7.10 8.77 10.55 8.12 6.52 5.94
Oil and
liquids
price
($/barrel) 51.86 40.64 47.48 100.31 103.76 81.76 71.66 64.11
Oil
equivalent
price
($/boe) 28.61 34.90 43.49 62.41 71.70 54.16 44.48 40.14
Operating
netback
($/boe) 15.15 12.68 24.63 36.19 46.31 32.36 26.85 22.95
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Net wells
completed:
(#)
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Natural gas - 3 2 8 - 5 3 5
Oil - - - - - - - 2
Dry - 1 1 2 - - - 1
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Total - 4 3 10 - 5 3 8
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(1) Non-GAAP measure


Ongoing drilling has delivered the production increases for 2007 and 2008. The decline in the first quarter of 2009 compared to the fourth quarter of 2008 was due to the restriction of 250 boe per day in the Lanfine area to preserve asset value under new Alberta royalty regulations which took affect on January 1, 2009. The decline from the first quarter of 2009 to the second quarter of 2009 was due to lack of drilling activity, natural declines and shut in volumes due to plant turn-arounds. There have been no other material acquisitions or dispositions.

RESULTS OF OPERATIONS

Production Volume

Volume averaged 4,180 boe/d for the quarter ended June 30, 2009, up one percent compared to 4,139 boe/d for the quarter ended June 30, 2008 and down eight percent from the first quarter of 2009. Natural gas represented 80 percent of production in the second quarter of 2009 with the remaining production being 19 percent light oil and natural gas liquids and one percent conventional heavy oil. Fewer wells were drilled over the winter of 2008/09 compared to the prior winter due to weaker natural gas and oil prices resulting in limited growth in production volume as natural declines were experienced during the quarter. No wells were drilled in the second quarter of 2009 due to spring break-up. Maintenance turn-arounds at various third party processing plants, primarily in Pembina, caused an average of 150 boe/d to be shut in during the second quarter of 2009 compared to no volume being shut in for maintenance in the second quarter of 2008.

For the six months ended June 30, 2009 volume averaged 4,364 boe/d, up 10 percent over the six months ended June 30, 2008. The increased volume is due to ongoing drilling success, primarily in Pembina.

Production Revenue

Natural gas prices averaged $3.82 per mcf for the quarter ended June 30, 2009, down 64 percent compared to $10.55 per mcf in the quarter ended June 30, 2008. Oil and liquids prices averaged $60.43 and $50.27 per barrel respectively for the quarter ended June 30, 2009 for a blended price of $51.86 per barrel, down 50 percent from the quarter ended June 30, 2008 blended oil and liquids price of $103.76 per barrel. On a per boe basis, prices averaged $28.61 in the quarter ended June 30, 2009, down 60 percent compared to $71.70 per boe in the quarter ended June 30, 2008. Revenue before results from hedging was down 60 percent in the quarter ended June 30, 2009 compared to the quarter ended June 30, 2008 due to the decline in both oil and natural gas prices. An additional $0.01 per boe was realized from hedging gains during the quarter ended June 30, 2009 for total revenue of $28.62 per boe. In the quarter ended June 30, 2008 realized hedging losses amounted to $6.91 per boe.

For the six months ended June 30, 2009, natural gas prices averaged $4.72 per mcf down 50 percent compared to $9.35 per mcf in the six months ended June 30, 2008. Combined oil and liquids prices averaged $45.94 per barrel for the six months ended June 30, 2009, down 51 percent from the six months ended June 30, 2008 blended oil and liquids price of $94.47 per barrel. On a boe basis prices averaged $31.87 per boe in the six months ended June 30, 2009, down 50 percent compared to $63.29 per boe in the six months ended June 30, 2008. Oil and natural gas revenue was down 45 percent for the six months ended June 30, 2009 compared to the six months ended June 30, 2008 as volume increases were more than offset by weaker prices. Realized hedging gains during the six months ended June 30, 2009 were $0.31 per boe compared to realized hedging losses of $3.81 per boe in the six months ended June 30, 2008.



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Volumes and prices Three months ended Six months ended
June 30, June 30,
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2009 2008 Change 2009 2008 Change
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Production revenue
($000's) 10,914 27,008 (60%) 25,228 45,801 (45%)
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Production volume
Natural gas (mcf/d) 20,152 19,677 2% 20,939 19,390 8%
Oil and liquids (bbl/d) 821 859 (4%) 874 744 18%
BOE (bbl/d) 4,180 4,139 1% 4,364 3,975 10%
Prices
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Natural gas ($/mcf) 3.82 10.55 (64%) 4.72 9.35 (50%)
Oil and liquids ($/bbl) 51.86 103.76 (50%) 45.94 94.47 (51%)
BOE ($/boe) 28.61 71.70 (60%) 31.87 63.29 (50%)
BOE ($/boe including
hedging) 28.62 64.79 (56%) 32.18 59.48 (46%)
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Royalties

Royalties averaged 17 percent of revenue for the quarter ended June 30, 2009 compared to 23 percent for the quarter ended June 30, 2008. For the six months ended June 30, 2009 royalties averaged 21 percent compared to 23 percent for the six months ended June 30, 2008. Low natural gas prices have resulted in lower percent royalty rates in 2009 compared to 2008. Approximately six percent of production in the quarter ended June 30, 2009 came from new wells brought on stream after April 1, 2009 which qualify for a five percent royalty rate further contributing to lower royalties in the 2009 period.

Royalty expense of $1.9 million was recorded in the quarter ended June 30, 2009, down 70 percent compared to the quarter ended June 30, 2008 due to lower revenue and lower percent royalty rates. For the six months ended June 30, 2009 royalty expense was $5.3 million, down 50 percent compared to the six months ended June 30, 2008 again, due to lower revenue and lower percent rates.



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Royalties Three months ended Six months ended
June 30, June 30,
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2009 2008 Change 2009 2008 Change
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Royalty expense ($000's) 1,876 6,270 (70%) 5,323 10,546 (50%)
Royalty cost per boe $ 4.93 $ 16.65 (70%) $ 6.74 $ 14.58 (50%)
Royalty cost as a
percent of revenue 17% 23% (26%) 21% 23% (9%)
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Production Expenses

Production expenses were $7.69 per boe in the quarter ended June 30, 2009, almost unchanged compared to $7.68 per boe in the quarter ended June 30, 2008. Upward pressures on costs have diminished in 2009 and concentrated efforts to reduce field operation costs have been successful. On March 1, 2009 the Company took over operations on 20 wells that were operated by third parties and has been able to reduce operating costs on these wells compared to the historical contract operating fees. With ongoing cost management, it is expected per unit operating expenses will remain in the $7.60 per boe range for the remainder of the year. For the six months ended June 30, 2009 production expenses were $7.63 per boe, down four percent compared to the six months ended June 30, 2008.

Production expenses for the quarter ended June 30, 2009 were $2.9 million, up one percent compared to the quarter ended June 30, 2008 due to higher volumes. For the six months ended June 30, 2009 production expenses were $6.0 million, up four percent due to higher production volume offset by and lower per unit costs.



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Production expenses Three months ended Six months ended
June 30, June 30,
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2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
Production expenses
($000's) 2,924 2,894 1% 6,027 5,774 4%
Production expenses per
boe $ 7.69 $ 7.68 - $ 7.63 $ 7.98 (4%)
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Transportation costs decreased 21 percent in the quarter ended June 30, 2009 compared to the quarter ended June 30, 2008 as low natural gas prices have reduced the cost of pipeline fuel costs.

Operating Netback (1)

Operating netback represents the margin realized by the production and sale of petroleum and natural gas exclusive of results from hedging. Second quarter 2009 operating netbacks declined due to lower per boe prices offset partially by lower operating and transportation costs.



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Operating Netbacks Three months ended Six months ended
($'s per boe) June 30, June 30,
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2009 2008 Change 2009 2008 Change
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Sales price 28.61 71.70 (60%) 31.87 63.29 (50%)
Less:
Royalties 4.96 16.65 (70%) 6.74 14.58 (50%)
Production expenses 7.69 7.68 - 7.63 7.98 (4%)
Transportation charges .83 1.06 (21%) .90 1.11 (19%)
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Operating netback 15.15 46.31 (67%) 16.59 39.62 (58%)
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Operating netback
including hedging 15.16 39.40 (62%) 18.90 35.81 (47%)
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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, 2009 general and administrative ("G&A") expenses were $1.3 million, down nine percent compared to the quarter ended June 30, 2008 primarily due to lower consulting fees for legal, geological and geophysical and operations as a result of focused G&A cost reductions. In the second quarter of 2008 the bank line was renewed resulting in commitment fees that were not repeated in the second quarter of 2009. For the six months ended June 30, 2009 G&A expenses were $2.8 million, up three percent compared to the six months ended June 30, 2008 primarily due to higher salaries. Stock based compensation declined in the quarter and six months ended June 30, 2009 compared to the quarter and six months ended June 30, 2008 as average option prices have declined due to a lower Company common share price. Additionally, in the 2008 periods, certain employees voluntarily renounced stock options resulting in a significant one time charge to stock based compensation.

On a per unit basis, for the quarter ended June 30, 2009 G&A costs were $3.55 per boe, down 10 percent from $3.95 per boe for the quarter ended June 30, 2008 due to lower costs as volume were almost unchanged. For the six months ended June 30, 2008 per unit G&A costs were $3.49 per boe, down six percent from $3.73 per boe for the six months ended June 30, 2008 as volume increases more than offset the overall cost increase. There were no general and administrative costs capitalized for the periods ended June 30, 2009 or 2008.



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General and administrative Three months ended Six months ended
expenses June 30, June 30,
----------------------------------------------------------------------------
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
G&A expenses ($000's) 1,350 1,487 (9%) 2,755 2,686 3%
G&A expenses per boe $ 3.55 $ 3.95 (10%) $ 3.55 $ 3.73 (6%)
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Stock-based compensation
($000's) 169 474 (64%) 354 693 (49%)
Stock-based compensation
per boe $ 0.44 $ 1.26 (65%) $ 0.45 $ 0.96 (53%)
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Interest Expense

For the quarter ended June 30, 2009 interest expense was $0.6 million, down 23 percent compared to $0.8 million for the quarter ended June 30, 2008. For the six months ended June 30, 2009 interest expense was $1.1 million, down 31 percent compared to the six months ended June 30, 2008. Average amounts drawn on the bank operating line in the both periods in 2009 were similar to the 2008 periods as the Company has continued to limit its capital spending to be in line with cash flow. Interest rates have declined significantly in 2009 compared to 2008 as recessionary forces have resulted in lower interest rates. On a per unit basis, interest rates have declined to a greater extent than the dollar cost as production volumes have increased as average debt levels have remained essentially unchanged.



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Interest Expense Three months ended Six months ended
June 30, June 30,
----------------------------------------------------------------------------
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
Interest expenses ($000's) 585 763 (23%) 1,144 1,662 (31%)
Interest expenses per
boe $ 1.54 $ 2.03 (24%) $ 1.45 $ 2.31 (37%)
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Depletion, Amortization and Accretion

In the quarter ended June 30, 2009 Depletion, Amortization and Accretion ("DA&A") totaled $8.8 million ($23.21 per boe) down 12 percent compared to $10.0 million ($26.56 per boe) for the quarter ended June 30, 2008. The per unit depletion rate declined 13 percent comparing the second quarter of 2009 to the second quarter of 2008 as ongoing drilling success and low cost reserve additions have brought down per unit DA&A rates consistently since the beginning of 2007. For the six months ended June 30, 2009 DA&A totaled $17.9 million ($22.66 per boe), down five percent and down 14 percent on a per unit basis compared to the six months ended June 30, 2008 total of $18.9 million ($26.32 per boe).



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Depletion, Amortization Three months ended Six months ended
and Accretion June 30, June 30,
----------------------------------------------------------------------------
2009 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
DA&A expenses ($000's) 8,831 10,005 (12%) 17,904 18,933 (5%)
DA&A expenses per boe $ 23.21 $ 26.56 (13%) $ 22.66 $ 26.32 (14%)
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Income Taxes

The Company does not expect to pay current income tax during 2009 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, 2009 was $3.8 million ($0.04 per share), 135 percent lower compared to a net loss of $1.6 million ($0.02 per share) for the quarter ended June 30, 2008 as commodity price weakness more than offset cost improvement and containment.

CAPITAL COSTS

For the quarter ended June 30, 2009 $1.9 million in capital costs were incurred on exploration and production activities compared to $2.7 million for the quarter ended June 30, 2008. The second quarter in both periods sees limited activity due to normal spring break-up causing an inability to move equipment in the field. Before dispositions, $13.3 million was spent on capital costs on four net wells in the six months ended June 30, 2009 compared to $14.3 million on five net wells in the six months ended June 30, 2008. The non-core Karr asset was sold in the first quarter of 2009 for $1.5 million to take advantage of opportunities to high grade the asset base and focus on the three core areas.



----------------------------------------------------------------------------
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Three months ended Six months ended
($000's) June 30, June 30,
----------------------------------------------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Drilling and completion 720 1,638 9,319 9,322
Equipping and tie-ins 848 58 2,412 2,543
Land 106 264 988 1,605
Geological and geophysical 302 751 610 824
Office and other - 4 - 7
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Total cash expenditure 1,976 2,715 13,329 14,301
Asset retirement obligation (38) 39 (47) 392
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Total capital before acquisitions
and dispositions 1,938 2,754 13,282 14,693
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Net acquisitions (dispositions) (99) - (1,599) -
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Total capital 1,839 2,754 11,683 14,693
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Total cash expenditure 1,976 2,715 13,329 14,301
Abandonment and restoration (38) (55) (103) (127)
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Capital per statement of cash flow 1,938 2,660 13,226 14,174
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Drilling, completion, equip and tie-in activity represented 88 percent of the capital spent in the first six months of 2009 as capital activity focused on developing the Company's land base. A $26 million capital budget is planned for 2009, 89 percent of which is targeted toward drilling, completion, equip and tie-in activity. Due to low commodity prices, drilling capital will be limited to wells that are required to be drilled under farm in commitments to earn lands or to extend land tenure where lands are expiring. Capital will also be directed toward crown land sales in Pembina to ensure the land and opportunity base is increased. It is expected that 2009 capital spending will be funded by cash flow provided by operating activities supplemented by drilling credits earned under a program announced by the Alberta government that will provide credits of $200 per metre of wells drilled between April 1, 2009 and March 31, 2011. An estimated $3.7 million in drilling credits is expected to be earned during 2009.

WORKING CAPITAL

Accounts receivable of $6.9 million at June 30, 2009 were primarily revenue receivables ($4.1 million) and amounts owing from partners ($2.5 million). Accounts payable at June 30, 2009 of $7.6 million were comprised of trade payables for capital and operating costs ($3.0 million), royalties ($2.1 million), amounts owing to partners ($1.4 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($0.5 million).

Working capital excluding bank indebtedness and the unrealized loss on risk management activities was in a deficit position of $0.5 million at June 30, 2009. 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 deficiency, operations and capital costs with a mix of operating cash flow, drilling credits and debt financing through the bank operating line. An operating bank line was in place for $65 million at June 30, 2009, secured by producing properties. At June 30, 2009, $60.5 million was drawn on the bank line leaving $4.5 million of capacity on the line. Subsequent to June 30, 2009 the bank line was renewed at $66 million until January 1, 2010 at which time it reduces by $1.0 million per month until a February 2010 review date. The December 31, 2009 reserves evaluation will then be taken into consideration to re-establish a new, go forward bank line amount. Oil and natural gas reserves added in the first three quarters of 2009 will then be taken into consideration to re-establish a new, go forward bank line amount. Future capital spending is planned at amounts that can be met with expected operating cash flow, drilling credits and the borrowing capacity within the bank line.

NON-GAAP MEASUREMENTS

This MD&A contains the term "funds from operations" and "operating netback". As an indicator of the Company's performance, these terms should not be considered an alternative to, or more meaningful than "cash flow from operating activities" or "net income (loss)" as determined in accordance with Canadian generally accepted accounting principles. The Company's determination of funds from operations and operating netback may not be comparable to those reported by other companies, especially those in other industries. Management feels that funds from operations is a useful measure to help investors assess whether the Company is generating adequate cash amounts from its operations 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 Cash flow provided by operating activities and funds from operations for the periods ended June 30 is as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
($000's) June 30, June 30,
----------------------------------------------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Cash flow provided by operating
activities 3,719 9,173 7,406 14,780
Changes in non-cash working capital
items related to operating activities 109 3,342 2,006 6,931
Cost of abandonment and restoration 38 55 103 127
----------------------------------------------------------------------------
Funds from operations 3,866 12,570 9,515 21,838
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 $0.04 per share (basic and diluted) for the quarter ended June 30, 2009 compared to $0.13 for the quarter ended June 30, 2008. For the six months ended June 30, 2009 funds from operations per share were $0.10 compared to $0.23 for the six months ended June 30, 2008. Higher production volume and cost improvements have been more than offset by weaker commodity prices causing the reduction in funds from operations.

RISKS

Primary financial risks relate to volatility of commodity prices. Interest 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 further changes to royalties for new wells drilled after November 19, 2008 described as the Transitional Royalty Framework. The Province of Alberta announced additional measures in March 2009 that provide for five percent royalties for a one year period on new wells brought on stream after April 1, 2009 and drilling credits of $200 per metre for wells spudded after April 1, 2009 until March 31, 2010. Both incentive programs were subsequently extended by one year until March 31, 2011. The Transitional Royalty Framework and the additional announcements add layers of complexity on the New Royalty Framework implemented on January 1, 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 is exposed to fluctuations in interest rates on its bank loan which charges interest at variable market rates. The Company entered into an interest rate swap transaction effective February 2009 to fix the interest rate on $40.0 million of its variable rate demand bank line. The transaction fixes the interest rate for a two year period at a borrowing rate of 2.39 percent. Including the Company's borrowing margin on its bank line the current all in rate on the $40 million fixed is 5.39 percent. 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, 2009 results in an unrealized liability of $936,000 (December 31, 2008 - $748,000 liability).

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 marked-to-market position on natural gas hedging contracts in place at June 30, 2009 resulted in an unrealized loss of $4,000 (December 31, 2008 - $114,000 gain). Total realized gains/losses from commodity price risk management activities in the second quarter of 2009 were $3,000 (2008 - $2,741,000 loss).

As at June 30, 2009 the Company has entered into natural gas hedging positions summarized in the following table. All natural gas contracts are priced in Canadian dollars per gigajoule ("GJ"). The price per GJ can be converted to an approximate price per million cubic feet ("MCF") by multiplying the per GJ price by 1.05. GJ volume can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95.



Natural Gas Risk Management Contracts

----------------------------------------------------------------------------
Daily quantity Term of Contract Fixed price per gigajoule
(GJ/day) (Cdn$/GJ)

----------------------------------------------------------------------------
2,000 June 1 to December 31, 2009 $3.40 floor/$5.00 ceiling
----------------------------------------------------------------------------
2,000 July 1 to December 31, 2009 $3.435 floor/$5.00 ceiling
----------------------------------------------------------------------------


Subsequent to June 30, 2009 the following additional risk management
contracts were put in place.

----------------------------------------------------------------------------
Daily quantity Term of Contract Fixed price per
(GJ/day) gigajoule (Cdn$/GJ)

----------------------------------------------------------------------------
2,000 August 1, 2009 to March 31, 2010 $4.00 fixed price
----------------------------------------------------------------------------
2,000 August 1, 2009 to March 31, 2010 $4.16 fixed price
----------------------------------------------------------------------------
2,000 August 1, 2009 to March 31, 2010 $4.18 fixed price
----------------------------------------------------------------------------

Absent risk management contracts, the effects of changes in commodity
prices on annual cash flow before working capital changes are summarized
in the following table based on estimated production of 4,400 boe/d.

----------------------------------------------------------------------------
Commodity Price change Cash flow change ($ 000's)
----------------------------------------------------------------------------
Natural gas ($/mcf) 1.00 4,400
----------------------------------------------------------------------------
Oil and Liquids ($/bbl) 10.00 1,400
----------------------------------------------------------------------------


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, 2009 were $74,000 (2008 - $105,000) and for the six months ended June 30, 2009 were $136,000 (2008 - $162,000).

SHARE DATA

As of the date of this MD&A the Company had 93,547,064 issued and outstanding common shares. Additionally, as at June 30, 2009 options to purchase 7,518,500 common shares have been issued.

DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's disclosure controls and procedures at the financial year end of the Company and have concluded that the Company's disclosure controls and procedures are effective at the financial year end of the Company for the foregoing purposes.

INTERNAL CONTROL OVER FINANCIAL REPORTING

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal control over financial reporting to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of financial statements for external purposes in accordance with the Canadian GAAP. The control framework the Company's officers have used to design the issuer's ICFR is the COSO financial framework. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's internal control over financial reporting at December 31, 2008 and concluded that the Company's internal control over financial reporting is effective, at the financial year end of the Company, for the foregoing purpose the Company is required to disclose herein any change in the Company's internal control over financial reporting that occurred during the period beginning on December 31, 2008 and ended on June 30, 2009 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. No material changes in the Company's internal control over financial reporting were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

It should be noted that a control system, including the Company's disclosure and internal controls and procedures over financial reporting, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

RISKS AND UNCERTAINTIES, CRITICAL ACCOUNTING ESTIMATES AND RECENT ACCOUNTING PRONOUNCEMENTS

The MD&A is based on the 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

Credit Risk and Fair Value of Financial Assets and Financial Liabilities

Effective January 1, 2009, the Company adopted the Emerging Issues Committee of the CICA issued Abstract #173, "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities", concerning the measurement of financial assets and financial liabilities. The new policy assesses an entity's own credit risk and the credit risk of the counterparty when determining the fair value of financial instruments. The effect that the implementation had on the Company's financial position in the current quarter was a reduction in unrealized hedging losses of $130,000 and a corresponding decrease in unrealized interest rate risk management expense. An adjustment was not made to the December 31, 2008 unrealized interest rate hedging loss as it was deemed to be not material.

FUTURE ACCOUNTING PRONOUNCEMENTS

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 data in accordance with IFRS.

In the second quarter of 2008 the Company began to develop its IFRS changeover plan. Initial activities include training sessions and acquisition of written standards and examples of IFRS disclosure to identify where key differences between Canadian GAAP and IFRS exist. A key determination that has significant effect on the financial statements will be the identification of cash generating units ("CGU") within the Company's production properties which are currently considered as a whole. Initial account mapping based on a total of five CGU's has been started but is too preliminary to assess the possible affect on the Company's financial statements. The Company intends to disclose its convergence plan and qualitative effects of IFRS on its financial statements as they become more fully developed.

Financial Instruments - Disclosures

In June 2009, the Accounting Standards Board amended Section 3862, Financial Instruments - Disclosures to converge with Improving Disclosures about Financial Instruments (Amendments to IFRS 7). The amendments expand the disclosures required in respect of recognized fair value measurements and clarify existing principles for disclosures about the liquidity risk associated with financial instruments. This standard will be effective for the annual period ending December 31, 2009. The Company expects to have derivative instruments outstanding at December 31, 2009 and will follow the amended Section 3862 disclosure.

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, 2008 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com).

OUTLOOK

Berens has established drilling plays that are repeatable and low risk. Spending within cash flow has been a discipline that has been adhered to since early 2006 and consistent growth has been demonstrated since that time in both strong and weak commodity price periods. In the current weak natural gas price environment focus has been on building the land and drilling inventory base. Drilling is planned only where additional lands can be earned through farm-in commitments or where land can be sustained due to pending expiry. A disciplined approach to cost management has achieved significant reduction in our costs supported by moderation in the overall industry cost structure.

Capital spending for 2009 is budgeted at $26 million and is planned to be funded with cash flow from operations supplemented by drilling credits. Capital spending for 2009 will be focused in Pembina where we wish to increase our land and drilling inventory where the reserve life of new wells is longest and the wells have the strongest economics. Capital will also be spent on crown land sales to ensure that an extensive drilling inventory is maintained for a time when natural gas prices recover and capital spending can be accelerated. There are currently 85 inventoried drilling locations on existing lands. Drilling has commenced in July and two successful natural gas wells have been drilled to date in the third quarter.

During the second quarter an exciting new development emerged in Pembina. Recent success has been experienced by industry drilling for light oil in the Cardium zone using horizontal well and multi-frac technologies in the general Pembina area. Berens has approximately 68 sections (38 net) of Cardium rights on the flank of the large Cardium oil field in central Alberta. The Cardium zone in many of Berens' sections has attributes similar to successful horizontal wells drilled by competitors on the flanks of the Cardium oil field. Two wells are planned for the third and fourth quarters to assess the potential of this exciting emerging oil resource play.

With an extensive land base, a large number of inventoried drilling locations and a focus on expanding the inventory in 2009 the Company is well positioned to accelerate activity when natural gas prices improve.



Berens Energy Ltd.
Balance Sheets - unaudited
As at,

----------------------------------------------------------------------------
----------------------------------------------------------------------------
(000's) June 30, December 31,
2009 2008
----------------------------------------------------------------------------
ASSETS (note 6)
Current
Cash and cash equivalents $ - $ 1
Accounts receivable 6,886 12,854
Unrealized gain on risk management (note 10) - 114
Prepaid expenses and deposits 294 300
----------------------------------------------------------------------------
7,180 13,269

Property, plant and equipment (note 4) 162,539 168,564
----------------------------------------------------------------------------
$ 169,719 $ 181,833
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 6) $ 60,500 $ 54,600
Accounts payable and accrued liabilities 7,643 17,291
Unrealized loss on risk management (note 10) 940 748
Taxes payable 3 16
----------------------------------------------------------------------------
69,086 72,655

Asset retirement obligations (note 5) 3,640 3,491
Future income taxes 8,240 10,420
----------------------------------------------------------------------------
$ 80,966 $ 86,566
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Shareholders Equity
Capital stock (note 7) $ 148,638 $ 148,638
Contributed surplus (note 7) 3,582 3,228
Deficit (63,467) (56,599)
----------------------------------------------------------------------------
88,753 95,267
----------------------------------------------------------------------------
$ 169,719 $ 181,833
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the unaudited interim financial statements


Berens Energy Ltd.
Statements of Operations, Comprehensive Loss and Deficit - unaudited
For the periods ended June 30,

----------------------------------------------------------------------------
----------------------------------------------------------------------------
(000's) Three months ended Six months ended
June 30, June 30,
----------------------------------------------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue
Oil and natural gas revenue $ 10,914 $ 27,008 $ 25,228 $ 45,801
Royalties (1,876) (6,270) (5,323) (10,546)
----------------------------------------------------------------------------
9,038 20,738 19,905 35,255
Realized gain (loss) on commodity
price risk management (note 10) 3 (2,741) 251 (2,601)
----------------------------------------------------------------------------
9,041 17,997 20,156 32,654
Unrealized loss on commodity price
risk management (note 10) (4) (4,602) (118) (12,295)
Other income - 119 - 119
----------------------------------------------------------------------------
9,037 13,514 20,038 20,478
----------------------------------------------------------------------------

Expenses
Production 2,924 2,894 6,028 5,774
Transportation 316 399 714 806
Depletion, amortization and
accretion 8,831 10,005 17,904 18,933
General and administrative 1,350 1,487 2,755 2,686
Stock-based compensation (note 7) 169 474 354 693
Interest 585 763 1,144 1,662
Unrealized loss (gain) on interest
rate risk management (note 10) (163) (141) 187 43
----------------------------------------------------------------------------
14,012 15,881 29,086 30,597
----------------------------------------------------------------------------

Loss before income taxes (4,975) (2,367) (9,048) (10,119)

Income taxes
Future recovery (1,192) (758) (2,180) (3,100)
Current expense (recovery) (1) 3 - 7
----------------------------------------------------------------------------
(1,193) (755) (2,180) (3,093)
----------------------------------------------------------------------------

Net loss and comprehensive loss for
the period (3,782) (1,612) (6,868) (7,026)
Deficit, beginning of period (59,685) (62,455) (56,599) (57,041)
----------------------------------------------------------------------------
Deficit, end of period $ (63,467)$ (64,067)$ (63,467) $(64,067)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net loss per share (note 11)
Basic and diluted $ (0.04)$ (0.02)$ (0.07) $ (0.08)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the unaudited interim financial statements


Berens Energy Ltd.
Statements of Cash Flows - unaudited
For the periods ended June 30,

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
----------------------------------------------------------------------------
(000's) 2009 2008 2009 2008
----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net loss for the period $ (3,782) $ (1,612) $ (6,868) $ (7,026)
Add items not involving cash
Depletion, amortization and
accretion 8,831 10,005 17,904 18,933
Unrealized risk management loss
(gain) (160) 4,461 305 12,339
Future income tax recovery (1,192) (758) (2,180) (3,100)
Stock-based compensation 169 474 354 693
----------------------------------------------------------------------------
3,866 12,570 9,515 21,839
Payments for abandonment and
restoration (note 5) (38) (55) (103) (128)
Change in non-cash working capital
items related to operating activities
(note 8) (109) (3,342) (2,006) (6,931)
----------------------------------------------------------------------------
Cash flow provided by operating
activities 3,719 9,173 7,406 14,780
----------------------------------------------------------------------------

FINANCING ACTIVITIES
Change in bank loan (500) (5,500) 5,900 (900)
Proceeds from the exercise of stock
options - 375 - 375
----------------------------------------------------------------------------
Cash flow provided by (used in)
financing activities (500) (5,125) 5,900 (525)
----------------------------------------------------------------------------

INVESTING ACTIVITIES
Purchase of property and equipment (1,938) (2,660) (13,226) (14,174)
Proceeds from disposition of assets 99 - 1,599 -
Change in non-cash working capital
items related to investing activities
(note 8) (1,408) (1,389) (1,680) (81)
----------------------------------------------------------------------------
Cash flow used in investing
activities (3,247) (4,049) (13,307) (14,255)
----------------------------------------------------------------------------

Decrease in cash and cash
equivalents (28) (1) (1) -
Cash and cash equivalents, beginning
of period 28 2 1 1
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period $ - $ 1 $ - $ 1
----------------------------------------------------------------------------

See accompanying notes to the unaudited interim financial statements


BERENS ENERGY LTD.
Notes to Financial Statements - unaudited
Three and six months ended June 30, 2009 and 2008


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 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.

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.

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, 2008 except as noted below. However, 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, 2008. Certain prior period amounts have been reclassified to conform to current disclosure.

a) CHANGES IN ACCOUNTING POLICIES

Credit Risk and Fair Value of Financial Assets and Financial Liabilities

Effective January 1, 2009, the Company adopted the Emerging Issues Committee of the CICA issued Abstract #173, "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities", concerning the measurement of financial assets and financial liabilities. The new policy assesses an entity's own credit risk and the credit risk of the counterparty when determining the fair value of financial instruments. The effect that the implementation had on the Company's financial position was a reduction in unrealized hedging losses of $132,000 and a corresponding decrease in unrealized interest rate risk management expense as at June 30, 2009. An adjustment was not made to the December 31, 2008 unrealized interest rate hedging loss as it was deemed to be not material.

Future accounting changes

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 data in accordance with IFRS.

In the second quarter of 2008 the Company began to develop its IFRS changeover plan. Initial activities include training sessions and acquisition of written standards and examples of IFRS disclosure to identify where key differences between Canadian GAAP and IFRS exist. A key determination that has significant effect on the financial statements will be the identification of cash generating units within the Company's production properties which are currently considered as a whole. Based on analysis to date, six CGU's have been identified. Analysis has been completed using December 31, 2008 property plant and equipment balances to assess the potential IFRS 1 adjustments to be made on conversion. The Company intends to disclose its convergence plan and qualitative effects of IFRS on its financial statements as they become more fully developed.

Financial Instruments - Disclosures

In June 2009, the Accounting Standards Board amended Section 3862, Financial Instruments - Disclosures to converge with Improving Disclosures about Financial Instruments (Amendments to IFRS 7). The amendments expand the disclosures required in respect of recognized fair value measurements and clarify existing principles for disclosures about the liquidity risk associated with financial instruments. This standard will be effective for the annual period ending December 31, 2009. The Company expects to have derivative instruments outstanding at December 31, 2009 and will follow the amended Section 3862 disclosure.



4. PROPERTY, PLANT AND EQUIPMENT

June 30, 2009 December 31, 2008
Accumulated Accumulated
depletion and depletion and
($000's) Cost depreciation Cost depreciation
----------------------------------------------------------------------------
Petroleum and natural
gas properties 325,852 163,637 314,170 145,966
Office and computer
equipment 774 450 774 414
----------------------------------------------------------------------------
326,626 164,087 314,944 146,380
----------------------------------------------------------------------------
Net book value 162,539 168,564
----------------------------------------------------------------------------


At June 30, 2008, costs of $14,076,000 (December 31, 2008 - $18,954,000) related to undeveloped land have been excluded from the depletion and depreciation calculation. At June 30, 2008 estimated future development costs of $17,698,000 have been included in the depletion and depreciation calculation. A ceiling test was completed at June 30, 2009 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 $3,640,000 as at June 30, 2009 (December 31, 2008 - $3,491,000) based on a total future liability of $11,502,000 (December 31, 2008 - $11,231,000). These payments are expected to be made over the next 5 to 25 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) 2009
----------------------------------------------------------------------------
Obligation, beginning of period 3,491
Increase in obligation during the period 55
Paid for abandonments (103)
Accretion expense 197
----------------------------------------------------------------------------
Obligation, end of period 3,640
----------------------------------------------------------------------------


6. BANK OPERATING LINE

An agreement with a Canadian bank is in place for an operating bank line totaling $65.0 million at June 30, 2009 which is subject to periodic review. Subsequent to June 30, 2009 the bank line was renewed at $66 million until January 1, 2010 at which time it reduces by $1.0 million per month until a February 2010 review date. The December 31, 2009 reserves evaluation will then be taken into consideration to re-establish a new, go forward bank line amount. Collateral for the facility consists of a general assignment of book debts and a $35.0 million debenture with a floating charge over all assets of the Company and a $75.0 million supplemental debenture with a floating charge over all assets of the Company. The bank line is a demand line and carries an interest rate of the Bank's prime rate adjusted for a factor based on the most recent quarterly debt to cash flow calculation. The adjustment factor ranges from 0.00% if debt to cash flow ratio is below 1 (calculated on a trailing quarter annualized basis), to 2.5% if debt to cash flow ratio is above 3.0. The average interest rate paid for the quarter ended June 30, 2009 was 3.9% (2008 - 5.2%) and for the six months ended June 30, 2009 4.0% (2008 - 5.9%) At June 30, 2009, $60.5 million was drawn on the bank loan, leaving $4.5 million of undrawn capacity.

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, 2007 93,172,064 148,263
Shares issued on exercise of stock options 375,000 375
----------------------------------------------------------------------------
Balance December 31, 2008 and
June 30, 2009 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,

2009 2008
Weighted Weighted
average average
Number of exercise price Number of exercise price
Options ($ per share) Options ($ per share)
----------------------------------------------------------------------------
Outstanding,
beginning of
period 7,655,200 0.96 6,238,200 1.42
Granted 510,000 0.53 1,779,000 1.01
Cancelled - (1,052,500) 2.88
Forfeited (646,700) 1.49 (845,000) 1.00
----------------------------------------------------------------------------
Outstanding, end
of period 7,518,500 0.88 6,119,700 1.11
----------------------------------------------------------------------------
Exercisable 3,040,157 1.12 2,320,024 1.28
----------------------------------------------------------------------------


The following table sets forth additional information relating to the stock
options outstanding at June 30, 2009:

Options Outstanding Exercisable Options
----------------------------------------------------------------------------
Weighted Weighted
average average
exercise Weighted exercise Weighted
Number price average Number price average
Exercise price of ($ per years to of ($ per years to
range Options share) expiry Options share) expiry
----------------------------------------------------------------------------
$ 0.25 to $0.79 2,980,000 0.54 4.15 244,035 0.76 3.20
----------------------------------------------------------------------------
$ 0.80 to $1.34 4,083,000 1.05 2.77 2,414,290 1.08 2.26
----------------------------------------------------------------------------
$ 1.35 to $1.89 450,500 1.61 1.86 376,832 1.62 1.79
----------------------------------------------------------------------------
$ 1.90 to $2.44 - - - - - -
----------------------------------------------------------------------------
$ 2.45 to $3.00 5,000 2.90 1.42 5,000 2.90 1.42
----------------------------------------------------------------------------
$ 0.25 to $3.00 7,518,500 0.88 3.26 3,040,157 1.12 2.27
----------------------------------------------------------------------------


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 issued in 2009 are: Risk free rate - 0.25 percent; average expected life - 4.5 years; no expected dividend yield; 46 percent volatility. Estimated future forfeiture assumptions are not used in calculations as forfeitures are recognized as they occur. The weighted average fair value for options outstanding at June 30, 2009 is $0.488 per option. For the quarter ended June 30, 2009, $169,000 (2008 - $474,000) and for the six months ended June 30, 2009 $354,000 (2008 - $693,000) was recorded for options issued and outstanding with a corresponding increase recorded to contributed surplus.



(d) Contributed Surplus

The following table sets forth the continuity of contributed surplus for
the period ended June 30, 2009:

(000's)
----------------------------------------------------------------------------
December 31, 2008 3,228
2009 Stock based compensation expense 354
----------------------------------------------------------------------------
June 30, 2009 3,582
----------------------------------------------------------------------------


8. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-cash Working Capital
For the periods ended June 30,
($000's) 2009 2008
----------------------------------------------------------------------------
Accounts receivable 5,969 (3,707)
Prepaid expenses and deposits 6 (114)
Accounts payable and accrued liabilities (9,648) (3,187)
Taxes payable (13) (4)
----------------------------------------------------------------------------
(3,686) (7,012)
Less: Change in non-cash working capital related
to investing activities (1,680) (81)
----------------------------------------------------------------------------
Change in non-cash working capital related to
operating activities (2,006) (6,931)
----------------------------------------------------------------------------


Cash interest and taxes paid
For the periods ended June 30,

Three months Six Months
($000's) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash income and other taxes paid 13 10 13 10
Cash interest paid 585 763 1,144 1,662
----------------------------------------------------------------------------


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, 2009 were $74,000 (2008 - $105,000) and for the six months ended June 30, 2009 were $136,000 (2008 - $162,000).

10. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair value of financial assets and liabilities

Cash, commodity price and interest rate risk management instruments are designated as "held-for-trading" and recorded at the estimated fair market value. Accounts receivable, prepaid expenses and the bank loan are designated as "loans and receivables" and accounts payable are designated as "other liabilities" and are recorded at their amortized costs. 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

At June 30, 2009 the maximum credit exposure with accounts receivable is the carrying value. The largest single credit exposure was approximately $2.8 million from the Company's sales agent the balance of which is settled monthly. At June 30, 2009, 10 percent of accounts receivable were non-current as defined by accounts over 90 days outstanding. Management has assessed the Company's accounts receivable customers and concluded no allowance for doubtful accounts receivable was required nor were any balances deemed to be impaired.

(b) Interest Rate Risk

The Company is exposed to fluctuations in interest rates on its bank debt which charges interest at variable market rates. In January 2009 the Company cancelled an existing $25 million interest rate swap and simultaneously replaced it with a $40 million fixed interest rate swap for two years beginning in February 2009 which fixes the interest rate for a two year period at an underlying borrowing rate of 2.39 percent. Including the Company's borrowing margin on its bank line the current all in rate of this transaction is 5.39 percent. 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 is then adjusted for credit risk. The credit adjustment on the unrealized interest rate loss position as at December 31, 2008 was not adjusted for credit risk as the adjustment was deemed to be not material. The fair value of the interest rate swap as at June 30, 2009 results in an unrealized liability of $936,000 (December 31, 2008 - $748,000). Assuming no other changes, a one percent change in interest rates for the remaining term of this interest rate swap at June 30, 2009 would change the fair value of the derivative instrument by approximately $565,000. The net income effect on an annual basis of a one percent change in short-term interest rates on the remaining amount of bank debt is approximately $144,000.

(c) 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 table summarizes the natural gas risk management contracts in place at June 30, 2009.



Natural Gas Risk Management Contracts
----------------------------------------------------------------------------
Daily quantity Fixed price per gigajoule
(GJ/day) Term of Contract (Cdn$/GJ)
----------------------------------------------------------------------------
2,000 June 1 to December 31, 2009 $3.40 floor/$5.00 ceiling
----------------------------------------------------------------------------
2,000 July 1 to December 31, 2009 $3.435 floor/$5.00 ceiling
----------------------------------------------------------------------------


Subsequent to June 30, 2009 the following additional risk management
contracts were put in place.
----------------------------------------------------------------------------
Daily quantity Fixed price per
(GJ/day) Term of Contract gigajoule (Cdn$/GJ)
----------------------------------------------------------------------------
2,000 August 1, 2009 to March 31, 2010 $4.00 fixed price swap
----------------------------------------------------------------------------
2,000 August 1, 2009 to March 31, 2010 $4.16 fixed price swap
----------------------------------------------------------------------------
2,000 August 1, 2009 to March 31, 2010 $4.18 fixed price swap
----------------------------------------------------------------------------


The marked-to-market position on natural gas hedging contracts in place at June 30, 2009 resulted in a unrealized loss of $4,000 (December 31, 2008 - $114,000 gain). Total realized gains/losses from commodity price risk management activities in the second quarter of 2009 were $3,000 (2008 - $2,741,000 loss). 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 any hedging activity, the effects of changes in commodity prices on annual net income summarized are in the following table on the basis of average annual production of approximately 4,400 boe/d.



----------------------------------------------------------------------------
Net Income change
Commodity Price change ($000's)
----------------------------------------------------------------------------
Natural gas ($/mcf) 1.00 $4,400
----------------------------------------------------------------------------
Oil and Liquids ($/bbl) 10.00 $1,400
----------------------------------------------------------------------------


(d) 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 loan and taxes payable. This risk is mitigated through the management of cash and bank loan 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 its debt and working capital to funds from operations ratio to a measure of 1.5:1 or lower on a current quarter annualized basis (excluding unrealized hedging gains and losses). For the quarter ended June 30, 2009 this ratio was 3.9:1 compared to 1.0:1 at June 30, 2008. The debt to annualized cash flow is in excess of the target measure primarily due to reduced funds from operations caused by weak natural gas prices in the quarter ended June 30, 2009. The Company will continue to limit capital spending to funds from operations to keep debt levels close to unchanged such that in the longer term the target measure can be met with stronger commodity prices and ongoing volume growth.



----------------------------------------------------------------------------
Target
At June 30 ($000's) Measure 2009 2008
----------------------------------------------------------------------------
Components of Ratio
----------------------------------------------------------------------------
Current assets 7,180 14,579
Current liabilities (69,086) (78,521)
----------------------------------------------------------------------------
(61,906) (63,942)
Unrealized risk management loss
(gain) 940 12,176
----------------------------------------------------------------------------
Debt and working capital (60,966) (51,766)
----------------------------------------------------------------------------
Funds from operations - three months
ended June 30 annualized (1) 15,464 50,280
----------------------------------------------------------------------------
Ratio 1.5:1 3.9:1 1.0:1
----------------------------------------------------------------------------
(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 three and six months ended June 30, 2009 of 93,547,064 was used to calculate basic and diluted loss per share (2008 - 93,192,668 and 93,182,367 respectively). 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 options which are potentially dilutive in future periods as of June 30, 2009 was 7,518,500.

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