Berens Energy Ltd.
TSX : BEN

May 14, 2009 08:30 ET

Berens Energy Ltd. Releases Financial Results for the First Quarter Ended March 31, 2009

CALGARY, ALBERTA--(Marketwire - May 14, 2009) - Berens Energy Ltd. (TSX:BEN)



FINANCIAL AND OPERATING HIGHLIGHTS

----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ Cdn thousands, Three months
except as noted) ended March 31,
----------------------------------------------------------------------------
2009 2008 % Change
----------------------------------------------------------------------------
Sales volume
Natural gas (mcf/day) 21,735 19,104 14%
Oil and ngls (bbl/day) 927 628 48%
----------------------------------------------------------------------------
boe/day (6 to 1) 4,550 3,812 19%
----------------------------------------------------------------------------
Revenue net of royalties 10,866 14,517 (25%)
----------------------------------------------------------------------------
Net income (loss) (3,086) (5,413) 43%
Per share (basic and diluted) $ (0.03) $ (0.06)
----------------------------------------------------------------------------
Funds from operations(1) 5,647 9,269 (39%)
Per share (basic and diluted)(1) $ 0.06 $ 0.10
----------------------------------------------------------------------------
Capital costs
Exploration and development 10,161 10,168 -
Land and seismic 1,190 1,414 (16%)
Other - 2 -
----------------------------------------------------------------------------
Total 11,351 11,586 (2%)
----------------------------------------------------------------------------
Net wells completed (#) 4 5
----------------------------------------------------------------------------
Net working capital deficit -
excluding unrealized hedging
losses(2) (62,956) (61,996) 2%
----------------------------------------------------------------------------
Net working capital deficit -
including unrealized hedging losses (64,054) (69,711) (8%)
----------------------------------------------------------------------------
Shares outstanding
End of period (000's) 93,547 93,172 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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-GGAP measure


First Quarter 2009 Operating Highlights

Berens is pleased to provide our first quarter results that demonstrate ongoing drilling success and continued strong capital efficiency:

- Drilling - Drilling during the first quarter saw a continuation of our 2008 success.

-- Year-to-date drilling has been 80% successful on 5 (2.8 net) completed in the quarter. One of the successful wells was our second horizontal well which tested over 15 million cubic feet per day and was brought on in March at a restricted rate of 4 million cubic feet per day.

-- Our finding and development cost efficiency continued from our top decile results in 2008 with internally estimated finding and development costs in the $12.00/boe range.

- Production - Q1 2009 production averaged 4,550 boe/d, up 19% over Q1 2008. Production was down 6% compared to the fourth quarter of 2008 as production was restricted by approximately 250 boe/d in Lanfine to preserve net asset value for certain wells under the new royalty framework that took effect on January 1, 2009.

- Capital Spending - Planned capital spending for 2009 has been reduced to $26 million from the original budget of $40 million due to weak natural gas prices. Average 2009 production is expected to be approximately 4,400 boe/d, an increase of 4% over average production in 2008.

- Funds from Operations - Funds from operations for Q1 2009 were $5.6 million ($0.06 per share), down 39% compared to Q1 2008. Higher production and lower per unit operating costs were more than offset by weaker commodity prices.

- Land - Berens' total undeveloped land currently stands at 81,000 net acres. The undeveloped land base increased in quality as 12 (8.5 net) sections of undeveloped land has been added during the first quarter of 2009 with 11 of those sections added in the Pembina growth area. We continue to have approximately 85 locations in our drilling inventory and are well positioned to accelerate activity when natural gas prices improve.

Message to the shareholders

Our low risk, repeatable play in Pembina continued to deliver excellent results in the first quarter of 2009. Our technical approach to the area using 3D seismic has delivered long term drilling success rates of over 96 percent. Reserves and production per well continue to be on target and exceed historical averages in the area. We have added to the excitement in Pembina with horizontal wells and multi-frac technology. Our first horizontal well, brought on stream in November 2008 at over eight million cubic feet per day ("mmcf/d") continues to produce steadily at two mmcf/d and we've added a second horizontal well in March which tested over 15 mmcf/d and is on production at a restricted rate of 4 mmcf/d. A third horizontal well encountered technical difficulties during drilling and had to be abandoned after encountering the target zone which encountered strong gas shows and quality reservior. We will return and re-drill this well when commodity prices improve. Internal estimates of finding and development costs for the first quarter of 2009 are consistent with the $12.00/boe we delivered in 2008. We remain confident that we can continue to be a leading company in finding and development costs.

Natural gas prices are currently weak. However, with low current drilling activity we believe that reduced natural gas supply will, in time, 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. As a result we have revised our capital budget to $26 million. It is expected that these capital expenditures can be funded with cash flow supplemented by drilling credits that we can earn under the initiatives put forth by the Alberta government in March 2009.

We have an extensive inventory of 85 drilling prospects across our three core areas, all on our existing land base. Until we see a recovery in natural gas prices we will preserve our inventory and are drilling only wells that will earn lands on farm-in commitments or preserve expiring lands. We have already had success in 2009 adding to our land and prospect inventory with 11 new sections added Pembina in the first quarter. Our strategy of adding land 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.

First Quarter 2009

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

May 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 March 31, 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 May 13, 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 current 2009 capital budget of $26 million is based on an assumed Cdn$4.50 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 to 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/boe. Operating and corporate netbacks are expected to be $20.00 and $15.00 respectively assuming a $4.50 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 has been renewed at $66 million effective until June 1, 2009 at which time the line reduces by $1.0 million per month until a September 30, 2009 review date. 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. 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 $64.1 million at March 31, 2009. Capital spending in the second quarter of 2009 is forecasted to be below $2 million resulting in a debt and working capital deficiency balance below $60 million at June 30, 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

----------------------------------------------------------------
2009 2008 2007
----------------------------------------------------------------------------
($000's
except as
noted) Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
----------------------------------------------------------------------------
Sales
volumes:
Natural gas
(mcf/day) 21,735 23,632 19,592 19,677 19,104 19,018 18,288 19,919
Oil and
natural gas
liquids
(bbl/day) 927 882 845 859 628 626 570 560
Barrels of
oil
equivalent
(boe/day) 4,550 4,821 4,110 4,139 3,812 3,796 3,618 3,880
----------------------------------------------------------------------------
Financial:
----------------------------------------------------------------------------
Net revenue 10,866 14,516 17,368 20,738 14,517 13,214 11,864 12,739
Net income
(loss) (3,086) (698) 8,167 (1,612) (5,413) (680)(23,157) (557)
per share -
basic
($/share) (0.03) (0.01) 0.09 (0.02) (0.06) (0.01) (0.25) (0.00)
per share -
diluted
($/share) (0.03) (0.01) 0.09 (0.02) (0.06) (0.01) (0.25) (0.00)
Capital
costs 11,351 11,979 13,997 2,715 11,586 6,718 8,541 6,208
Shares
outstanding
(000's) 93,547 93,547 93,547 93,547 93,172 93,172 93,172 93,172
Bank debt 61,000 54,600 48,500 53,000 58,500 53,900 50,800 62,700
----------------------------------------------------------------------------
Working
capital
(deficit)
including
bank debt (64,054)(59,386)(57,040)(64,943)(69,711)(59,516)(58,594)(63,610)
----------------------------------------------------------------------------
Working
capital
(deficit)
including
bank debt
and
excluding
unrealized
hedging
gains and
losses(1) (62,956)(58,751)(56,819)(51,766)(61,996)(59,678)(60,051)(65,073)
----------------------------------------------------------------------------
Per unit
information:
----------------------------------------------------------------------------
Natural gas
price
($/mcf) 5.57 7.10 8.77 10.55 8.12 6.52 5.94 7.60
Oil and
liquids
price
($/barrel) 40.64 47.48 100.31 103.76 81.76 71.66 64.11 58.98
Oil
equivalent
price
($/boe) 34.90 43.49 62.41 71.70 54.16 44.48 40.14 47.51
Operating
netback
($/boe) 12.68 24.63 36.19 46.31 32.36 26.85 22.95 27.88
----------------------------------------------------------------------------
Net wells
completed: (#)
----------------------------------------------------------------------------
Natural gas 3 2 8 - 5 3 5 1
Oil - - - - - - 2 -
Dry - 1 2 - - - 1 -
----------------------------------------------------------------------------
Total 3 3 10 - 5 3 8 1
----------------------------------------------------------------------------

(1) Non-GAAP measure


Ongoing drilling has delivered the production increases for 2007 and 2008 with the decline in production for the third quarter of 2007 as a result of the disposition of Marten Hills production of 250 boe per day. The decline the first quarter of 2009 compared to the fourth quarter of 2008 was due to the restriction of 250 boe/d in the Lanfine area to preserve asset value under new Alberta royalty regulations which took affect on January 1, 2009. There have been no other material acquisitions or dispositions.

RESULTS OF OPERATIONS

Production Volume

Volume averaged 4,550 boe/d for the quarter ended March 31, 2009, up 19 percent compared to 3,812 boe/d for the quarter ended March 31, 2008. Natural gas represented 80 percent of production in the first quarter of 2008 with the remaining production being 19 percent light oil and natural gas liquids and one percent conventional heavy oil.

An active drilling program with high success rates was carried out during the fourth quarter of 2008 and the first quarter of 2009. Well results have been strong and in particular, the Company's first Pembina horizontal well came on stream in November 2008 at rates of over eight million cubic feet per day and has stabilized at over two million cubic feet a day. A total of 5 wells (2.8 net) were drilled in the first quarter of 2009 with three successful (2.0 net) natural gas wells in Pembina, one (0.5 net) successful natural gas wells in Deep Basin. As at March 31, 2009 four wells were being delayed for tie in awaiting the start of the Alberta government royalty relief program that provides for a five percent royalty rate for new wells brought on after April 1, 2009.

Production Revenue

Natural gas prices averaged $5.57 per mcf for the quarter ended March 31, 2009, down 31 percent compared to $8.12 per mcf in the quarter ended March 31, 2008. Oil and liquids prices averaged $44.12 and $39.98 per barrel respectively for the quarter ended March 31, 2009 for a blended price of $40.64 per barrel, down 50 percent from the quarter ended March 31, 2008 blended oil and liquids price of $81.76 per barrel. Prices averaged $34.90 per boe in the quarter ended March 31, 2009, down 36 percent compared to $54.16 per boe in the quarter ended March 31, 2008. Revenue before results from hedging was down 24 percent in the quarter ended March 31, 2009 compared to the quarter ended March 31, 2008 as volume increases were more than offset by the decline in prices. An additional $0.60 per boe was realized from hedging gains during the quarter ended March 31, 2009 for total revenue of $35.50 per boe. In the quarter ended March 31, 2008 realized hedging gains were $0.41 per boe.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volumes and prices Quarter ended
March 31,
----------------------------------------------------------------------------
2009 2008 Change
----------------------------------------------------------------------------
Production revenue ($000's) 14,314 18,793 (24%)
----------------------------------------------------------------------------
Production volume
Natural gas (mcf/d) 21,735 19,104 14%
Oil and liquids (bbl/d) 927 628 48%
BOE (bbl/d) 4,550 3,812 19%
Prices
----------------------------------------------------------------------------
Natural gas ($/mcf) 5.57 8.12 (31%)
Oil and liquids ($/bbl) 40.64 81.76 (50%)
BOE ($/boe) 34.90 54.16 (36%)
BOE ($/boe including hedging) 35.50 54.57 (35%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Royalties

Royalties averaged 24 percent of revenue for the quarter ended March 31, 2009 compared to 23 percent for the quarter ended March 31, 2008. The Alberta Government New Royalty Framework Royalties took effect on January 1, 2009 which combined with still high natural gas reference prices from December 2008 and January 2009 resulted in high royalty rates in January and February. Royalties have also trended higher on a percent of revenue basis as a significant number of high rate wells have been brought on stream in 2008 and early 2009 which attract higher royalty rates. With natural gas prices in the $4.00 range, royalties are expected to trend below 20 percent. Lower natural gas and liquids prices offset the volume based royalty increase such that overall percent royalties have shown little change.

Royalty expense of $3.4 million was recorded in the quarter ended March 31, 2009, down 19 percent compared to the quarter ended March 31, 2008 due to overall lower revenue as higher production volume was offset by lower prices.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Royalties Quarter ended
March 31,
----------------------------------------------------------------------------
2009 2008 Change
----------------------------------------------------------------------------
Royalty expense ($000's) 3,448 4,276 (19%)
Royalty cost per boe $ 8.42 $ 12.33 (32%)
Royalty cost as a percent of revenue 24% 23% 4%
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production Expenses

Production expenses were $7.58 per boe in the quarter ended March 31, 2009, down nine percent compared to $8.30 per boe in the quarter ended March 31, 2008. Costs in 2009 have trended lower as higher volumes have improved economies of scale and a concentrated effort to reduce field operation costs. 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 volume increases and cost management, it is expected per unit operating expenses will remain in the $7.60 per boe range for the remainder of the year.

Production expenses for the quarter ended March 31, 2009 were $3.1 million, up eight percent compared to the quarter ended March 31, 2008 due to higher volumes partially offset by lower per unit costs.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production expenses Quarter ended
March 31,
----------------------------------------------------------------------------
2009 2008 Change
----------------------------------------------------------------------------
Production expenses ($000's) 3,103 2,880 8%
Production expenses per boe $ 7.58 $ 8.30 (9%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Transportation costs decreased two percent in the quarter ended March 31, 2009 compared to the quarter ended March 31, 2008 due to higher volume offset by lower per unit costs.

Operating Netback (1)

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



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarterly Operating Netbacks Quarter ended
($'s per boe) March 31,
----------------------------------------------------------------------------
2009 2008 Change
----------------------------------------------------------------------------
Sales price 34.90 54.16 (36%)
Less:
Royalties 8.42 12.33 (32%)
Production expenses 7.58 8.30 (9%)
Transportation charges .97 1.17 (17%)
----------------------------------------------------------------------------
Operating netback 17.93 32.36 (44%)
----------------------------------------------------------------------------
Operating netback including hedging 18.53 32.77 (43%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


General and Administrative Expenses

For the quarter ended March 31, 2009 general and administrative ("G&A") expenses were $1.4 million, up 17 percent compared to the quarter ended March 31, 2008. Higher salaries account for the majority of the increase. G&A charged to partners on capital spending in the first quarter of 2009 was lower than in the first quarter of 2008 as wells are being drilled at higher average working interest than in the prior period. Stock based compensation declined in the quarter ended March 31, 2009 compared to the quarter ended March 31, 2008 as average option prices have declined due to a lower Company common share price.

On a per unit basis, for the quarter ended March 31, 2009 per unit G&A costs were $3.89 per boe, down five percent from $4.09 per boe for the quarter ended March 31, 2008 as volume increases more than offset the dollar increase in costs for the per unit calculation. There were no general and administrative costs capitalized for the quarters ended March 31, 2009 or 2008. Staff levels are expected to remain fairly constant in 2009.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and administrative expenses Quarter ended
March 31,
----------------------------------------------------------------------------
2009 2008 Change
----------------------------------------------------------------------------
G&A expenses ($000's) 1,406 1,199 17%
G&A expenses per boe 3.89 4.09 (5%)
----------------------------------------------------------------------------
Stock-based compensation ($000's) 186 219 (15%)
Stock-based compensation per boe $ 0.45 $ 0.64 (30%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest Expense

For the quarter ended March 31, 2009 interest expense was $0.6 million, down 38 percent compared to $0.9 million for the quarter ended March 31, 2008. Average amounts drawn on the bank operating line in the first quarter of 2009 were similar to the first quarter of 2008 as the Company has continued to limit its capital spending to be in line with cash flow. Interest rates have declined significantly in the first quarter of 2009 compared to 2008 as recessionary forces have resulted in lower interest rates. On a per unit basis, interest rates have declined 47 percent as production volume has increased as average debt levels have remained essentially unchanged.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest Expense Quarter ended
March 31,
----------------------------------------------------------------------------
2009 2008 Change
----------------------------------------------------------------------------
Interest expenses ($000's) 559 899 (38%)
Interest expenses per boe $ 1.37 $ 2.62 (48%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Depletion, Amortization and Accretion

In the quarter ended March 31, 2009 Depletion, Amortization and Accretion ("DA&A") totaled $9.1 million ($22.15 per boe) up two percent compared to $8.9 million ($25.67 per boe) for the quarter ended March 31, 2008. The per unit depletion rate declined 14 percent comparing the first quarter of 2009 to the first 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.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Depletion, Amortization and Accretion Quarter ended
March 31,
----------------------------------------------------------------------------
2009 2008 Change
----------------------------------------------------------------------------
DA&A expenses ($000's) 9,072 8,929 2%
DA&A expenses per boe $ 22.15 $ 25.67 (14%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 March 31, 2009 was $3.1 million ($0.03 per share) an improvement of 43 percent compared to a net loss of $5.4 million ($0.06 per share) for the quarter ended March 31, 2008. The quarter ended March 31, 2008 was negatively affected by a large unrealized loss on risk management activities of $7.7 million.

CAPITAL COSTS

For the quarter ended March 31, 2009 $11.4 million in capital costs on exploration and production activities were incurred compared to $11.6 million for the quarter ended March 31, 2008. five wells (2.8 net) wells were drilled in the first quarter of 2008 compared to nine wells (4.7 net) net wells in the first quarter of 2008. Included in the first quarter 2009 drilling were two (1.0 net) horizontal wells which incur higher costs to drill and complete than vertical wells. 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. At the time of sale, Karr production was 32 boe per day. Net of the disposition, capital costs were $9.8 million for the first quarter of 2009.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter ended
($000's) March 31,
----------------------------------------------------------------------------
2009 2008
----------------------------------------------------------------------------
Drilling and completion 8,598 7,685
Equipping and tie-ins 1,563 2,485
Land 882 1,341
Geological and geophysical 308 73
Office and other - 2
----------------------------------------------------------------------------
Total cash expenditure 11,351 11,586
Asset retirement obligation (9) 353
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total capital before acquisitions and dispositions 11,342 11,949
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net acquisitions (dispositions) (1,500) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total capital 9,842 11,949
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total cash expenditure 11,351 11,586
Abandonment and restoration (64) (72)
----------------------------------------------------------------------------
Capital per statement of cash flow 11,287 11,514
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Drilling, completion, equip and tie-in activity represented 89 percent of the capital spent in the first quarter of 2009 as capital activity focused on developing the Company's extensive 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 an extensive 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, 2010.

WORKING CAPITAL

Accounts receivable of $12.9 million at March 31, 2009 were primarily revenue receivables ($4.1 million), amounts owing from partners ($6.2 million) and the expected proceeds of $1.5 million from the sale of Karr which were collected in April 2009. Accounts payable at March 31, 2009 of $15.2 million were comprised of trade payables for capital and operating costs ($10.9 million), royalties ($1.9 million), amounts owing to partners ($2.4 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($1.9 million).

Working capital excluding bank indebtedness and the unrealized loss on risk management activities was in a deficit position of $2.0 million at March 31, 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 and debt financing through the bank operating line. An operating bank line was in place for $66 million at March 31, 2009, secured by producing properties. At March 31, 2009, $61.0 million was drawn on the bank line leaving $5.0 million of capacity on the line. The line of credit has been renewed at $66 million until June 1, 2009 at which time the line reduces by $1.0 million per month until a September 30, 2009 review date. 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 March 31 is as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter ended
($000's) March 31,
----------------------------------------------------------------------------
2009 2008
----------------------------------------------------------------------------
Cash flow provided by operating activities 3,687 5,607
Changes in non-cash working capital items related
to operating activities 1,896 3,590
Cost of abandonment and restoration 64 72
----------------------------------------------------------------------------
Funds from operations 5,647 9,269
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 $0.06 per share (basic and diluted) for the quarter ended March 31, 2009 compared to $0.10 for the quarter ended March 31, 2008. Higher production volume has 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. 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 4.64 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 March 31, 2009 results in an unrealized liability of $1,098,000 (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.

All commodity derivative instruments had expired by at March 31, 2009, therefore there was no unrealized gain or loss balance at March 31, 2009 (December 31, 2008 - $114,000 gain). There were $248,000 ($0.60 per boe) of realized gains on commodity derivatives in the first quarter of 2009 (2008 - $140,000 gain; $0.41 per boe).

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 4,600 boe/d.



Commodity Price change Cash flow change ($ 000's)
----------------------------------------------------------------------------
Natural gas ($/mcf) 1.00 4,600
----------------------------------------------------------------------------
Oil and Liquids ($/bbl) 10.00 1,500
----------------------------------------------------------------------------


Subsequent to March 31, 2009 the Company entered into natural gas hedging positions as 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
----------------------------------------------------------------------------


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 March 31, 2009 were $62,000 (2008 - $57,000).

SHARE DATA

As of the date of this MD&A the Company had 93,547,064 issued and outstanding common shares. Additionally, as at March 31, 2009 options to purchase 7,552,700 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 March 31, 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.

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. First quarter 2009 drilling was as successful as experienced in the past two years. Management has confidence that low cost reserve additions and production growth will continue to be delivered. A disciplined approach to cost management has achieved significant reduction in our costs supported by moderation in the overall industry cost structure. Further material and industry cost moderation is expected once spring break-up is over and drilling commences in the third quarter.

Capital spending for 2009 has been revised to $26 million as natural gas prices have weakened. The capital program will 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, the reserve life of new wells is longest and the wells have the strongest economics. Until natural gas prices recover significantly, wells will focus on where undeveloped land can be earned through farm in or sustained due to pending expiry. 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 is expected to commence again in the middle of July 2009 at Pembina where we expect to drill on an ongoing basis until the end of the year and at Lanfine where five wells are planned to be drilled in October to take advantage of drilling credits.

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) March 31, December 31,
2009 2008
----------------------------------------------------------------------------
ASSETS (note 6)
Current
Cash and cash equivalents $ 28 $ 1
Accounts receivable 12,895 12,854
Unrealized gain on risk management (note 10) - 114
Prepaid expenses and deposits 360 300
----------------------------------------------------------------------------
13,283 13,269

Property, plant and equipment (note 4) 169,431 168,564
----------------------------------------------------------------------------
$ 182,714 $ 181,833
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 6) $ 61,000 $ 54,600
Accounts payable and accrued liabilities 15,222 17,291
Unrealized loss on risk management (note 10) 1,098 748
Taxes payable 17 16
----------------------------------------------------------------------------
77,337 72,655

Asset retirement obligations (note 5) 3,578 3,491
Future income taxes 9,432 10,420
----------------------------------------------------------------------------
$ 90,347 $ 86,566
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Shareholders Equity
Capital stock (note 7) $ 148,638 $ 148,638
Contributed surplus (note 7) 3,414 3,228
Deficit (59,685) (56,599)
----------------------------------------------------------------------------
92,367 95,267
----------------------------------------------------------------------------
$ 182,714 $ 181,833
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the unaudited interim financial statements

Berens Energy Ltd.
Statements of Operations, Comprehensive Loss and Deficit - unaudited
For the three months ended March 31,

----------------------------------------------------------------------------
----------------------------------------------------------------------------
(000's) 2009 2008
----------------------------------------------------------------------------
Revenue
Oil and natural gas revenue $ 14,314 $ 18,793
Royalties (3,448) (4,276)
----------------------------------------------------------------------------
10,866 14,517
Realized gain on commodity price risk management
(note 10) 248 140
----------------------------------------------------------------------------
11,114 14,657
Unrealized loss on commodity price risk management
(note 10) (114) (7,693)
----------------------------------------------------------------------------
11,000 6,964
----------------------------------------------------------------------------

Expenses
Production 3,103 2,880
Transportation 398 406
Depletion, amortization and accretion 9,072 8,929
General and administrative 1,406 1,199
Stock-based compensation (note 7) 186 219
Interest 559 899
Unrealized loss on interest rate risk management
(note 10) 349 184
----------------------------------------------------------------------------
15,073 14,716
----------------------------------------------------------------------------

Loss before income taxes (4,073) (7,752)

Income taxes
Future recovery (988) (2,343)
Current expense 1 4
----------------------------------------------------------------------------
(987) (2,339)
----------------------------------------------------------------------------

Net loss and comprehensive loss for the period (3,086) (5,413)
Deficit, beginning of period (56,599) (57,042)
----------------------------------------------------------------------------
Deficit, end of period $ (59,685) $ (62,455)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net loss per share (note 11)
Basic and diluted $ (0.03) $ (0.06)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the unaudited interim financial statements


Berens Energy Ltd.
Statements of Cash Flows - unaudited
For the three months ended March 31,

----------------------------------------------------------------------------
----------------------------------------------------------------------------
(000's) 2009 2008
----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net loss for the period $ (3,086) $ (5,413)
Add items not involving cash
Depletion, amortization and accretion 9,072 8,929
Unrealized risk management loss 463 7,877
Future income tax recovery (988) (2,343)
Stock-based compensation 186 219
----------------------------------------------------------------------------
5,647 9,269
Payments for abandonment and restoration (note 5) (64) (72)
Change in non-cash working capital items related
to operating activities (note 8) (1,896) (3,590)
----------------------------------------------------------------------------
Cash flow provided by operating activities 3,687 5,607
----------------------------------------------------------------------------

FINANCING ACTIVITIES
Change in bank loan 6,400 4,600
----------------------------------------------------------------------------
Cash flow provided by financing activities 6,400 4,600
----------------------------------------------------------------------------

INVESTING ACTIVITIES
Purchase of property and equipment (11,287) (11,514)
Change in non-cash working capital items related
to investing activities (note 8) 1,227 1,308
----------------------------------------------------------------------------
Cash flow used in investing activities (10,060) (10,206)
----------------------------------------------------------------------------

Increase in cash and cash equivalents 27 1
Cash and cash equivalents, beginning of period 1 1
----------------------------------------------------------------------------
Cash and cash equivalents, end of period $ 28 $ 2
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the unaudited interim financial statements



BERENS ENERGY LTD.

Notes to Financial Statements - unaudited

Three months ended March 31, 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. 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 $130,000 and a corresponding decrease in unrealized interest rate risk management expense as at March 31, 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. 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

March 31, 2009 December 31, 2008
Accumulated Accumulated
depletion and depletion and
($000's) Cost depreciation Cost depreciation
----------------------------------------------------------------------------
Petroleum and
natural gas
properties 324,013 154,926 314,170 145,966
----------------------------------------------------------------------------
Office and
computer
equipment 774 430 774 414
----------------------------------------------------------------------------
324,787 155,356 314,944 146,380
----------------------------------------------------------------------------
Net book value 169,431 168,564
----------------------------------------------------------------------------


At March 31, 2008, costs of $16,276,000 (December 31, 2008 - $18,954,000) related to undeveloped land have been excluded from the depletion and depreciation calculation. At March 31, 2008 estimated future development costs of $17,698,000 have been included in the depletion and depreciation calculation. A ceiling test was completed at March 31, 2009 resulting in no impairment. The sale of Karr for $1.5 million was recorded as at March 31, 2009 as a reduction to property, plant and equipment with a corresponding increase to accounts receivable. The sale proceeds were collected in April 2009.

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 $3,578,000 as at March 31, 2008 (2008 - $3,636,000) based on a total future liability of $11,502,000 (2008 - $8,828,000). 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) 2009
----------------------------------------------------------------------------
Obligation, beginning of period 3,491
Increase in obligation during the period 55
Paid for abandonments (64)
Accretion expense 96
----------------------------------------------------------------------------
Obligation, end of period 3,578
----------------------------------------------------------------------------


6. BANK OPERATING LINE

An agreement with a Canadian bank is in place for an operating bank line totaling $66.0 million at March 31, 2009 which is subject to periodic review. The line of credit remains at $66 million until June 1, 2009 at which time the line reduces by $1.0 million per month until a September 30, 2009 review date. 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 rate paid for the quarter ended March 31, 2009 was 3.9% (2008 - 6.6%). At March 31, 2009, $61.0 million was drawn on the bank loan, leaving $5.0 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 March 31, 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 three months ended March 31,

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 380,000 0.51 - -
Forfeited (482,500) 1.52 - -
----------------------------------------------------------------------------
Outstanding, end
of period 7,552,700 0.90 6,238,200 1.42
----------------------------------------------------------------------------
Exercisable 2,344,888 1.16 3,631,851 1.51
----------------------------------------------------------------------------


The following table sets forth additional information relating to the stock
options outstanding at March 31, 2009:


Options Outstanding Exercisable Options
----------------------------------------------------------------------------
Weighted Weighted
average average Weighted
exercise Weighted exercise average
Number price average Number price years
Exercise price of ($ per years to of ($ per to
range Options share) expiry Options share) expiry
----------------------------------------------------------------------------
$0.25 to $0.79 2,850,000 0.54 4.36 244,035 0.76 3.45
----------------------------------------------------------------------------
$0.80 to $1.34 4,083,000 1.05 3.02 1,611,321 1.10 1.84
----------------------------------------------------------------------------
$1.35 to $1.89 614,700 1.55 1.59 484,532 1.53 1.39
----------------------------------------------------------------------------
$1.90 to $2.44 - - - - - -
----------------------------------------------------------------------------
$2.45 to $3.00 5,000 2.90 1.67 5,000 2.90 1.67
----------------------------------------------------------------------------
$0.25 to $3.00 7,552,700 0.90 3.41 2,344,888 1.16 1.91
----------------------------------------------------------------------------


The fair value method for measuring option awards based on the Black Scholes valuation model is used. Key assumptions used for the Black Scholes based valuation of options are: Risk free rate - 1.85 percent; average expected life - 4.5 years; no expected dividend yield; 46 percent volatility. Estimated future forfeiture assumptions are not used in calculations as forfeitures are recognized as they occur. The weighted average option price for options outstanding at March 31, 2009 is $0.494 per option. For the quarter ended March 31 2009, $186,000 (2008 - $219,000) was recorded for options issued and outstanding with a corresponding increase recorded to contributed surplus.

(d) Contributed Surplus

The following table sets forth the continuity of contributed surplus for the year ended March 31, 2009:



($000's)
----------------------------------------------------------------------------
December 31, 2008 3,228
2008 Stock based compensation expense 186
----------------------------------------------------------------------------
March 31, 2009 3,414
----------------------------------------------------------------------------

8. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-cash Working Capital
For the quarters ended March 31,

2009 2008
($000's)
----------------------------------------------------------------------------
Accounts receivable (41) (3,561)
Prepaid expenses and deposits (60) (205)
Accounts payable and accrued liabilities (2,069) 1,480
Taxes payable 1 4
----------------------------------------------------------------------------
(2,169) (2,282)

Change in non-cash receivable for asset disposition 1,500 -
Less: Change in non-cash working capital related to
investing activities 1,227 1,308
----------------------------------------------------------------------------
Change in non-cash working capital related to
operating activities (1,896) (3,590)

Cash interest and taxes paid
For the quarters ended March 31,

($000's) 2009 2008
----------------------------------------------------------------------------
Cash income and other taxes paid - -
Cash interest paid 559 899
----------------------------------------------------------------------------


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 March 31, 2009 were $62,000 (2008 - $57,000).

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. The fair value of these financial instruments approximates their carrying amounts due to their short terms to maturity except for derivatives used for interest rate and commodity price risk management which values are outlined below. Accounts receivable, 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.

(a) Credit Risk

At March 31, 2009 the maximum credit exposure with accounts receivable is the carrying value. The largest single credit exposure was approximately $3.9 million from the Company's sales agent the balance of which is settled monthly. An overdue account receivable of $80,000 from a company that declared bankruptcy was written off during the quarter ended March 31, 2009. At March 31, 2009, 11 percent of accounts receivable were non-current as defined by accounts over 90 days outstanding. The majority of the overdue accounts receivable are with a single counterparty with which the Company is working to reconcile older operating and capital billings. Certain overdue amounts have been collected from this counterparty since March 31, 2009 and this party is current on recent billings. 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. 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 4.64 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 pursuant to CICA EIC-173 using a management estimated discount rate of 8.5 percent. 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 March 31, 2009 results in an unrealized liability of $1,098,000 (December 31, 2008 - $749,000). Assuming no other changes, a one percent change in interest rates for the remaining term of this interest rate swap at March 31, 2009 would change the fair value of the derivative instrument by approximately $552,000. 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.

There were no oil or natural gas derivative instruments in place as of March 31, 2009. The marked-to-market position on natural gas hedging contracts as at December 31, 2008 resulted in an unrealized gain of $114,000. Total realized gains from risk management activities in the first quarter of 2009 were $248,000 (2008 - $140,000 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 any hedging activity, the effects of changes in commodity prices on annual net income summarized in the following table on the basis of average annual production of approximately 4,600 boe/d.



Commodity Price change Net Income change
($000's)
----------------------------------------------------------------------------
Natural gas ($/mcf) 1.00 $ 4,600
----------------------------------------------------------------------------
Oil and Liquids ($/bbl) 10.00 $ 1,500
----------------------------------------------------------------------------


Subsequent to March 31, 2009 the Company entered into natural gas hedging positions as 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
----------------------------------------------------------------------------


(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 March 31, 2009 this ratio was 2.8:1 compared to 1.7:1 at March 31, 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 March 31, 2009. The Company will continue to limit capital spending to funds from operations and 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 March 31 ($000's) Measure 2009 2008
Components of Ratio
----------------------------------------------------------------------------
Current assets 13,283 14,525
Current liabilities (77,337) (84,236)
----------------------------------------------------------------------------
(64,054) (69,711)
Unrealized risk management loss (gain) 1,098 7,856
----------------------------------------------------------------------------
Debt and working capital (62,956) (61,855)
----------------------------------------------------------------------------
Funds from operations - three months
ended March 31 annualized (1) 22,588 37,076
----------------------------------------------------------------------------
Ratio 1.5:1 2.8:1 1.7:1
----------------------------------------------------------------------------

(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 March 31, 2009 of 93,547,064 was used to calculate basic and diluted loss per share (2008 - 93,172,064). 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 March 31, 2009 was 7,552,700.

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