Berens Energy Ltd.

March 26, 2009 23:59 ET

Berens Energy Ltd. Releases Financial Results for the Fourth Quarter and Year Ended December 31, 2008

CALGARY, ALBERTA--(Marketwire - March 26, 2009) -



FINANCIAL AND OPERATING HIGHLIGHTS

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($ Cdn thousands, Three months Twelve months

except as noted) ended December 31, ended December 31,

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% %

2008 2007 Change 2008 2007 Change

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Sales volume

Natural gas

(mcf/day) 23,632 19,018 24% 20,507 18,981 8%

Oil and ngls

(bbl/day) 882 626 41% 804 564 43%

boe/day (6 to 1) 4,821 3,796 27% 4,222 3,728 13%

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Revenue net of

royalties 15,276 13,214 16% 62,660 49,609 26%

Net income (loss) (699) (680) (3%) 443 (27,440)

Per share (basic

and diluted) $(0.01) $(0.01) $0.01 $(0.30)

Funds from

operations(1) 10,047 7,991 26% 40,829 29,554 38%

Per share (basic

and diluted)(1) $0.11 $0.09 22% $0.44 $0.32 38%

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Capital costs

Exploration and

development 9,619 5,986 33,868 35,468

Disposition - - - (6,750)

Land and seismic 2,334 412 6,369 4,293

Other 26 4 40 745

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Total 11,979 6,402 87% 40,278 33,756 19%

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Net wells

completed (No.)

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Natural gas 2 3 14 14

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Oil - - - 2

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Dry 1 - 4 2

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Total 3 3 18 18

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Net working capital

(deficit) - excluding

unrealized hedging

gains/losses (58,751) (59,678) (1%) (58,751) (59,678) (1%)

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Net working capital

(deficit) - including

unrealized heading

gains/losses (59,386) (59,516) - (59,386) (59,516) -

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Shares outstanding

End of period

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

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Note:

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

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

Discussion and Analysis for discussion of this measure.


Message to the shareholders

We entered 2008 confident we could deliver additional growth based on our strong, repeatable drilling success experienced over the 18 months leading up to the end of 2007. We had established an advantage in Pembina based on strong integration of technology, geology and geophysics and remained committed to disciplined cost management for both drilling and operations. Natural gas prices were stronger in early 2008 and we were able to take advantage of this price strength by increasing our capital budget during the year and becoming more aggressive in exploiting our advantage. The result was an outstanding year in terms of reserve and production growth and finding and development cost efficiency.



We delivered again, as promised:

- Drilling success continued with 96% success in our key growth area of

Pembina with finding and development costs less than $10 in this key

growth area.

- We continued to further define our Pembina play and have

significantly reduced the risk in the area using our integrated

technical approach, evident not only in our drilling success rate but

also in our improved reserve and production additions.

- An exciting development in Pembina was the drilling of our first

horizontal well which was completed with a multi-stage frac and came

on production at over 8 million cubic feet per day in November and

continues to be a strong producer. This well was followed up with an

equally successful second well in early 2009 and enhances our

opportunity to further reduce finding and development costs.

- We further developed our land position in the greater Pembina area

during 2008 to continue to build our drilling location inventory.

- As planned, we improved our balance sheet by growing production and

expanding our reserve base with the discipline of spending within

cash flow.

Results continue to improve:

- Total capital, including land and future development capital and

including reserve revisions generates an all in finding and

development cost of $11.95 per boe for the year which is first

quartile in our industry. Our 2008 corporate recycle ratio was

2.4 times.

- Average annual production increased 13% year over year with fourth

quarter 2008 production up 27% over the fourth quarter of 2007.

- Long term value was strengthened with a reserves increase of 22%. We

replaced production by 230% with new reserves. All done with the

drill bit.

- On a per share basis, proved plus probable reserves increased from

96.8 boe per 1,000 shares to 117.3 boe per 1000 shares, also a

22 percent increase. Capital spending was equal to cash flow for the

year and a nominal number of shares were issued in 2008.

- We added 32 (18 net) sections of land in the Pembina area. We've

already added another 12 (9 net) sections in the greater Pembina area

so far in 2009.


Opportunity continues into 2009:

We continue to expand our play in Pembina and have enhanced the opportunity with horizontal technology. As new technologies improve we see additional opportunity in Pembina to broaden their application to further improve results.

Berens is prospect rich and we don't believe now is the time to be passive, despite current weak commodity prices and the unstable economic environment. We have worked hard to attain excellence in our operations and lower our cost structure and we intend to maintain the track record we have established. We will manage our debt levels and be ready to adjust our capital spending to meet cash flows as they change.

Our staff is committed, enthusiastic about our success and look forward to building on the achievements we have made to date. I would like to offer special thanks to our staff and management for their efforts and achievements and to our board of directors for their guidance and support in 2008.

Our shareholders experienced a difficult year in the stock markets in 2008. We thank those shareholders who stood with us through this past year and welcome our new shareholders. In return, we have delivered operational results that should deliver wealth to our shareholders when the markets recover.



Sincerely,

Daniel F. Botterill

President & Chief Executive Officer

Fourth Quarter 2008 Operating Highlights

- Drilling - A total of 5 wells (2.5 net) were drilled in the fourth

quarter resulting in 3 (1.7 net) successful natural gas wells. In

Pembina we were 3 (1.7 net) on 4 (2.2 net) wells with the

unsuccessful well due to mechanical difficulty. In Deep Basin we were

unsuccessful on 1 (0.3 net) well. On a full year basis in 2008, 28

(18.4 net) wells have been drilled with 21 (13.9 net) natural gas

wells and 7 (4.5 net) unsuccessful wells for a net success rate of

75 percent. In the key growth area of Pembina 16 (10.0 net) wells

were drilled resulting in 15 (9.6 net) successful gas wells for a

96 net success ratio in Pembina.

- Reserves - Total working interest proved plus probable reserves as at

December 31, 2008 were 10,972,000 boe, an increase of 22 percent

compared to proved plus probable reserves at December 31, 2007 of

9,016,000. On a per share basis proved plus probable reserves also

grew 22 percent to 117.3 boe/1000 shares outstanding from

96.8 boe/1000 shares outstanding. Reserves growth came entirely from

the successful 2008 exploration and development drilling program

which was funded entirely with cash flow. Berens replaced production

2.3 times through the addition of new proved plus probable reserves

from the exploration and development drilling program with finding

and development costs of $11.95 per boe.

- Production - Q4 2008 production averaged 4,821 boe/d, up 27 percent

over Q4 2007 and up 17 percent over the third quarter of 2008.

Production additions in the fourth quarter of 2008 were delivered by

ongoing strong results in Pembina as well as completion and tie in of

a summer drilling program in Lanfine. On a full year basis, volume in

2008 averaged 4,222 boe/d, up 13 percent compared to 2007.

- Funds from Operations - Funds from operations in Q4 2008 was

$10.0 million ($0.11 per share), up 24 percent compared to Q4 2007

funds from operations of $8.0 million ($0.09 per share). Higher

production in Q4 2008 was complemented by stable operating costs,

offset slightly by lower commodity prices. December 31, 2008 debt and

working capital was 1.5 times annualized Q4 funds from operations.

- Land - Berens total undeveloped land position currently stands at

81,000 net acres. Ninety-seven percent of the undeveloped lands are

located in our three core areas of Pembina, Deep Basin and Lanfine.

In our key growth area of Pembina the undeveloped land position

increased by 6 percent despite a very active drilling program in the

area that converted significant acreage to the developed category.

The 2009 drilling program is based entirely on existing Berens'

controlled undeveloped acreage on which there exists an inventory of

85 locations.


RESERVES

Berens' oil and gas reserves were independently evaluated by GLJ Petroleum Consultants ("GLJ"). The evaluation was completed using the reserves definitions in the Canadian Oil and Gas Evaluation Handbook and the Canadian Securities Administrators National Instrument 51-101 ("NI 51-101"). The tables below summarize Berens' working interest reserves on a gross basis (before deduction for royalties) as at December 31, 2008 using forecast prices and costs based on the GLJ January 1, 2009 price forecast.



Highlights from the 2008 reserve report:

- Proved and probable reserves grew 22 percent to 11.0 million barrels

with growth coming entirely through the drill bit.

- On a per share basis, proved plus probable reserves increased from

96.8 boe per 1000 shares to 117.3 boe per 1,000 shares, also a

22 percent increase as capital spending was equal to cash flow for

the year.

- 2008 production replacement was 230 percent with new reserves on a

proved plus probable basis.

- Finding and development costs for the year for total capital,

including land, future development capital and reserve revisions were

$11.95 per boe on a proved plus probable basis and results in a 2008

corporate recycle ratio of 2.4 times.

- Finding and development costs for the year were $10.35 per boe on a

proved plus probable basis, excluding land capital and revisions and

including future development capital (NI51-101 definition), a

19 percent improvement compared to $12.85 per boe in 2007. On a three

year rolling average basis proved plus probable finding and

development costs are $14.47 per boe.

SUMMARY OF OIL AND GAS RESERVES(1)

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WORKING INTEREST

RESERVES OIL AND LIQUIDS NATURAL GAS

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2008 2007 Percent 2008 2007 Percent

RESERVES CATEGORY (Mbbl) (Mbbl) Change (MMcf) (MMcf) Change

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PROVED

Developed

Producing 1,240 1,050 +18% 25,536 21,855 +17%

Developed

Non-Producing 204 82 +149% 2,706 1,440 +88%

Undeveloped 244 198 +23% 5,794 4,746 +22%

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TOTAL PROVED 1,688 1,330 +27% 34,036 28,041 +21%

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PROBABLE 834 665 +25% 16,667 14,085 +18%

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TOTAL PROVED

PLUS PROBABLE 2,522 1,995 +26% 50,703 42,126 +20%

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WORKING INTEREST

RESERVES BOE

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2008 2007 Percent

RESERVES CATEGORY (Mbbl) (Mbbl) Change

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PROVED

Developed

Producing 5,496 4,693 +17%

Developed

Non-Producing 655 322 +103%

Undeveloped 1,210 989 +22%

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TOTAL PROVED 7,361 6,003 +23%

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PROBABLE 3,611 3,013 +20%

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TOTAL PROVED

PLUS PROBABLE 10,972 9,016 +22%

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WORKING INTEREST BEFORE TAX 10% BEFORE TAX 15%

RESERVES PRESENT VALUE(1) PRESENT VALUE(1)

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2008 2007 Percent 2008 2007 Percent

RESERVES CATEGORY ($000's) ($000's) Change ($000's) ($000's) Change

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PROVED

Developed

Producing 110,683 86,962 +27% 95,743 77,205 +24%

Developed

Non-Producing 12,349 4,842 +155% 10,217 3,971 +157%

Undeveloped 11,875 6,640 +79% 8,254 4,598 +80%

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TOTAL PROVED 134,907 98,444 +37% 114,214 85,774 +33%

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PROBABLE 46,484 34,215 +36% 33,901 25,911 +31%

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TOTAL PROVED

PLUS PROBABLE 181,391 132,659 +37% 148,115 111,685 +33%

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(1) It should not be assumed that the present values of estimated future

net cash flows shown above are representative of the fair market

value of the reserves. There is no assurance that such price and cost

assumptions will be attained and variances could be material. The

recovery and reserves estimates of crude oil, NGL and natural gas

reserves provided herein are estimates only and there is no guarantee

that the estimated reserves will be recovered. Actual crude oil,

natural gas and NGL reserves may be greater than or less than the

estimates provided herein.


Based on current production volume of 4,600 boepd the proved plus probable reserve life index at December 31, 2008 is 6.5 years, unchanged from December 31, 2007. Oil and liquids represent 23 percent of December 31, 2008 reserves, up slightly from 22 percent at December 31, 2007 as the majority of the reserves added in 2008 have been from liquids rich natural gas wells in Pembina.

The following table reconciles the reserve additions from capital spending, dispositions and revisions to opening estimates.



RECONCILIATION OF

COMPANY GROSS RESERVES

BY BARREL OF OIL EQUIVALENT

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BOE

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Proved Plus

Proved Probable

FACTORS (Mboe) (Mboe)

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December 31, 2007 6,003 9,016

Discoveries 166 254

Extensions 2,314 3,387

Technical revisions 367 (204)

Acquisitions 30 41

Dispositions (9) (12)

Economic factors 31 31

Production(1) (1,541) (1,541)

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December 31, 2008 7,361 10,972

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All calculations converting natural gas to crude oil equivalent have been made using a ratio of six thousand cubic feet ("mcf") of natural gas to one barrel of crude oil 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.

Finding and Development Costs

Berens 2008 capital spending on exploration and development activities was $40.1 million including $3.8 million spent on land acquisitions. Proved plus probable finding and development costs for 2008 excluding land acquisitions and including the change in future development capital was $10.35 per boe on a proved plus probable basis and $15.39 per boe on a proved only basis. On a total capital basis, including land acquisitions and technical reserve revisions, proved plus probable finding and development costs were $11.95 per boe in 2008. This results in a corporate recycle ratio for 2008 of 2.4 times. The table below provides detail on finding and development costs on a three year annual and cumulative basis to December 31, 2008.

Finding and development costs for Berens seismic, exploration and development activities for each of the past three years and on a three year cumulative basis are outlined below:



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Three

Year

2008 2007 2006 Totals

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Total capital for seismic,

exploration and development

(excluding land capital) ($000's) 36,315 31,059 53,101 120,475

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Future development capital -

proved ($000's) 17,309 15,112 12,633 16,069

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Future development capital -

proved plus probable ($000's) 22,863 21,187 15,413 21,483

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Reserve extensions, discoveries

and dispositions - proved (Mboe) 2,501 1,777 2,222 6,500

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Reserve extensions, discoveries

and dispositions - proved plus

probable (Mboe) 3,670 2,868 3,271 9,809

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Finding and development costs -

proved (per boe) $15.39 $18.89 $29.12 $21.01

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Finding and development costs -

proved plus probable (per boe) $10.35 $12.85 $20.59 $14.47

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Three year rolling average finding and development costs on a proved plus probable basis for exploration and development activities was $14.47 per boe.

Net Asset Value

The Company's net asset value at December 31, 2008 based on the year end reserves as evaluated by GLJ, including land and debt and working capital is presented below. The net asset value as determined below may not necessarily reflect the current market value of the Company.



Before tax Before tax

10% present Value 15% present Value

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$/ $/

Category ($000's) share(1) ($000's) share(1)

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Proved reserves(2) 134,907 1.44 114,214 1.22

Probable reserves(2) 46,484 0.50 33,901 0.36

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181,391 1.94 148,115 1.58

Land(3) 18,954 0.20 18,954 0.20

Debt & Working Capital Deficit (58,926) (0.63) (58,926) (0.63)

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Net Asset Value -

December 31, 2008 141,419 1.51 108,143 1.15

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(1) Per share values are based on basic shares outstanding of 93,547,064

as there were no dilutive stock options as at December 31, 2008.

(2) Based on an independent evaluation by GLJ effective December 31, 2008

using forecast prices and costs and calculated before deducting

future income taxes.

(3) Land is recorded at December 31, 2008 book value which equates to

$235 per acre.

Berens Energy Ltd.

Annual and Fourth Quarter 2008

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

March 25, 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 December 31, 2008 audited financial statements and notes thereto. This MD&A was prepared using information that is current as of March 25, 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 a planned $40 million capital program plan that is funded by cash flow based on an assumed Cdn$7.00 price for natural gas at AECO and Edmonton Reference light oil at Cdn$70.00. 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 4,900 boe per day in 2009 under the $40 million capital plan, up 16 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 $26.00 and $21.00 respectively assuming a $7.00 per mcf price for natural gas and $70.00 per barrel for oil. Resulting recycle ratios based on the above factors are over 1.9 times on an operating netback basis and 1.5 times based on the corporate netback. Both of these measures deliver long term added value.

ECONOMIC UNCERTAINTY

Recent economic events have created volatility and an uncertain environment for stock and credit markets and commodity prices in the foreseeable future. Berens' bank line of credit has been renewed at $66 million effective 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 all or part of the reduction in the bank line. Further, the Company has conducted its capital spending program within cash flow since the third 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 $59.4 million at December 31, 2008.

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

2008

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($000's except as noted) Q4 Q3 Q2 Q1

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Sales volumes:

Natural gas (mcf/day) 23,632 19,592 19,677 19,104

Oil and natural gas

liquids (bbl/day) 882 845 859 628

Barrels of oil equivalent 4,821 4,110 4,139 3,812

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Financial:

Net revenue 14,627 17,368 20,738 14,517

Net income (loss) (698) 8,167 (1,612) (5,413)

per share - basic

($/share) (0.01) 0.09 (0.02) (0.06)

per share - diluted

($/share) (0.01) 0.09 (0.02) (0.06)

Capital costs 11,979 13,997 2,715 11,586

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

Bank debt 54,600 48,500 53,000 58,500

Working capital (deficit)

including bank debt (59,386) (57,040) (64,943) (69,711)

Working capital (deficit)

including bank debt and

excluding unrealized

hedging gains and losses (58,751) (56,819) (51,766) (61,996)

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Per unit information:

Natural gas price ($/mcf) 7.10 8.77 10.55 8.12

Oil and liquids price

($/barrel) 47.48 100.31 103.76 81.76

Oil equivalent price ($/boe) 43.49 62.41 71.70 54.16

Operating netback ($/boe) 24.63 36.19 46.31 32.36

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Net wells completed: (No.)

Natural gas 2 8 - 5

Oil - - - -

Dry 1 2 - -

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Total 3 10 - 5

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2007

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($000's except as noted) Q4 Q3 Q2 Q1

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Sales volumes:

Natural gas (mcf/day) 19,018 18,288 19,919 18,705

Oil and natural gas

liquids (bbl/day) 626 570 560 499

Barrels of oil equivalent 3,796 3,618 3,880 3,617

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Financial:

Net revenue 13,214 11,864 12,739 11,793

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

per share - basic

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

per share - diluted

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

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

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

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

Working capital (deficit)

including bank debt (59,516) (58,594) (63,610) (67,468)

Working capital (deficit)

including bank debt and

excluding unrealized

hedging gains and losses (59,678) (60,051) (65,073) (66,896)

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Per unit information:

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

Oil and liquids price

($/barrel) 71.66 64.11 58.98 55.24

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

Operating netback ($/boe) 26.85 22.95 27.88 27.16

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Net wells completed: (No.)

Natural gas 3 5 1 5

Oil - 2 - -

Dry - 1 - 1

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Total 3 8 1 6

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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. There have been no other material acquisitions or dispositions.

RESULTS OF OPERATIONS

Production Volume


Production volume averaged 4,821 boe/d for the fourth quarter of 2008, up 27 percent compared to 3,796 boe/d in the fourth quarter of 2007 and up 17 percent compared to the third quarter of 2008. Natural gas represented 82 percent of production in the fourth quarter of 2008 with the remaining production being 17 percent light oil and natural gas liquids and one percent conventional heavy oil. Light oil and natural gas liquids have increased as a percent of production as most of the production growth has come from liquids rich natural gas wells in Pembina and Deep Basin. Drilling success throughout the third quarter and early fourth quarter of 2008 delivered the fourth quarter volume increases.

A seven (4.9 net) well program was drilled in Pembina in the third quarter of 2008 with 100 percent success. The Pembina success continued into the fourth quarter with an additional 3 (1.7 net) successful natural gas wells on 4 (2.2 net) attempts. Most of the Pembina wells were brought on stream throughout the final four months of 2008 resulting most of the fourth quarter production increase. An additional four (3.8 net) successful natural gas wells in Lanfine were brought on stream late in the third quarter which also contributed to the fourth quarter volume increase. The fourth quarter drilling was highlighted by the Company's first horizontal well in Pembina which was brought on stream in late November at initial production rates in excess of eight million cubic feet per day.

Volume averaged 4,222 boe/d for the year ended December 31, 2008, up 13 percent compared to 3,728 boe/d for the year ended December 31, 2007. Production growth was delivered by ongoing drilling success, primarily in Pembina where 15 (9.6 net) successful natural gas wells were drilled on 16 (10.0 net) attempts for a net success rate of 96 percent.

First quarter 2009 production is expected to be 4,600 boepd with production gains from ongoing drilling being offset by the Company's decision to curtail a total of 250 boepd of higher production wells in Lanfine. This curtailment will preserve net asset value under the new royalty framework which became effective January 1, 2009. The first quarter 2009 drilling program includes 4 (2.4 net) wells in Pembina, three (1.7 net) of which are horizontal wells. One (0.5 net) natural gas well was also drilled in Deep Basin in the first quarter of 2009.

Production Revenue

Natural gas prices averaged $7.10 per mcf for the fourth quarter of 2008, up nine percent compared to $6.52 per mcf in the fourth quarter of 2007. Oil and liquids prices averaged $54.61 and $45.90 per barrel respectively in the fourth quarter of 2008 for a blended price of $47.48 per barrel, down 34 percent from the fourth quarter 2007 blended oil and liquids price of $71.66 per barrel. On a boe basis, prices averaged $43.49 in the fourth quarter of 2008, down two percent compared to $44.48 per boe in the fourth quarter of 2007. Revenue before results from hedging was up 24 percent in the fourth quarter of 2008 compared to the fourth quarter of 2007 as production volume increases were offset slightly by lower prices. An additional $1.47 per boe was realized from hedging gains during the fourth quarter of 2008 increasing total revenue per boe to $44.96 compared to $47.16 including realized hedging gains during the fourth quarter of 2007.

Realized natural gas prices averaged $8.56 per mcf for the year ended December 31, 2008, up 23 percent compared to $6.96 per mcf in the year ended December 31, 2007. Oil and liquids prices averaged $93.58 and $79.75 per barrel respectively in the year ended December 31, 2008 for a blended price of $83.05 per barrel, up 32 percent from the year ended December 31, 2007 blended oil and liquids price of $63.02 per barrel. On a boe basis, prices averaged $57.39 in the year ended December 31, 2008, up 28 percent compared to $44.98 per boe in the year ended December 31, 2007. Revenue before results from hedging was up 45 percent in the year ended December 31, 2008 compared to the year ended December 31, 2007 as both volume and prices were higher. Realized hedging losses reduced annual 2008 revenue by $2.98 per boe to $54.41 while in 2007 annual revenue was $1.65 per boe higher due to hedging gains for total revenue per boe of $46.63.



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Volumes and prices Three months Year

ended December 31 ended December 31

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2008 2007 Change 2008 2007 Change

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Production revenue

($000's) 19,292 15,563 24% 88,738 61,281 45%

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Production volume

Natural gas

(mcf/d) 23,632 19,018 24% 20,507 18,981 8%

Oil and liquids

(bbl/d) 882 626 41% 804 564 43%

BOE (bbl/d) 4,821 3,796 27% 4,222 3,728 13%

Prices

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Natural gas

($/mcf) 7.10 6.52 9% 8.56 6.96 23%

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Oil and liquids

($/bbl) 47.48 71.66 (34%) 83.05 63.02 32%

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BOE ($/boe) 43.49 44.48 (2%) 57.39 44.98 28%

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BOE ($/boe

including hedging) 44.96 47.16 (5%) 54.41 46.63 17%

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Royalties

Royalties averaged 24 percent of revenue for the fourth quarter of 2008 compared to 21 percent in the fourth quarter of 2007. Royalties have trended higher on a percent of revenue basis as a significant number of higher rate wells were brought on stream in 2008, primarily in Pembina. Higher volume wells incur higher crown royalty rates. Royalties averaged 24 percent of revenue for the year ended December 31, 2008 compared to 23 percent for the year ended December 31, 2007.

Royalty expense of $4.7 million was recorded in the fourth quarter of 2008, up 42 percent compared to the fourth quarter of 2007 reflecting higher volume and higher percent royalty rates. Royalty expense of $21.5 million was recorded in the year ended December 31, 2008, up 54 percent compared to the year ended December 31, 2007 due to higher production volume and higher percentage royalty rates.



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

Royalties Three months Year

ended December 31 ended December 31

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

2008 2007 Change 2008 2007 Change

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

Royalty expense

($000's) 4,665 3,286 42% 21,488 13,915 54%

Royalty cost

per boe $10.52 $9.41 12% $13.90 $10.23 36%

Royalty percent 24% 21% 14% 24% 23% 4%

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


The effects of the Alberta New Royalty Framework ("NRF") which came in to effect on January 1, 2009 will reduce near term cash flow in a $7.00 natural gas price environment. At a $7.00 per mcf natural gas price royalties are anticipated to increase from historical 24 percent rates to approximately 27 percent. At natural gas prices in the $5.00 to $6.00 range, royalties are expected to be essentially unchanged from historical rates. The Alberta government also announced a new Transitional Royalty Framework ("TRF") which became effective on November 19, 2008 and applies to new wells drilled from 1,000 to 3,000 meters. All new Pembina wells qualify for the TRF with the result that new wells drilled after November 19, 2008 will be subject to royalty rates similar to pre-NRF until 2013 resulting in royalty burden similar to the period prior to the NRF for new production brought on stream in 2009 and beyond.

Further royalty changes and drilling royalty credits were announced by the Alberta government on March 3, 2009. Under this new program wells placed on production after April 1, 2009 will be subject to a 5% royalty rate for one year before reverting back to NRF or TRF as elected. Further, a drilling credit equal to $200 per metre drilled on wells spudded after April 1, 2009 will be awarded on Alberta crown royalties payable. Both of these programs will initially be in place for a one year period with the drilling credits available to offset up to 50% of crown royalties payable for a two year period to March 31, 2011. The Company will benefit from both of these new programs as the entire capital spending program is within Alberta. Management is currently assessing how these new programs may affect the 2009 capital spending program.

Production Expenses

Production expenses were $6.98 per boe in the fourth quarter of 2008, down 3 percent compared to $7.23 per boe in the fourth quarter of 2007. Cost control continues to be a key management objective.

Production expenses were $7.88 per boe in the year ended December 31, 2008, up four percent compared to $7.55 per boe in the year ended December 31, 2007. Inflationary pressures on costs during 2008 combined with increases in certain third party processing fees have caused increased costs. With ongoing volume increases and cost management, it is expected future per unit operating expenses will be in the $8.00 per boe range.

Fourth quarter 2008 production expenses were $3.1 million, up 23 percent compared to the fourth quarter of 2007 due to higher production volume and a slight decrease in per unit costs. Production expenses for the year ended December 31, 2008 were $12.2 million, up 18 percent compared to the year ended December 31, 2007 due to higher volumes and higher per unit costs.



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

Production expenses Three months Year

ended December 31 ended December 31

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

2008 2007 Change 2008 2007 Change

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

Production expenses

($000's) 3,095 2,524 23% 12,180 10,280 18%

Production expenses

per boe $6.98 $7.23 (3%) $7.88 $7.55 4%

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

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


Transportation costs increased 25 percent in the fourth quarter of 2008 compared to the fourth quarter of 2007 and 20 percent for the year ended December 31, 2008 compared to the year ended December 31, 2007 mainly due to higher production volume. On a per unit basis, transportation costs remained unchanged in the $1.00 per boe range.

Operating Netback(1)

Operating netback represents the margin realized by the production and sale of petroleum and natural gas. Fourth quarter 2008 operating netbacks, excluding the results of hedging, declined seven percent compared to the fourth quarter of 2007 mainly due to higher percent royalty burden. For the year ended December 31, 2008 operating netbacks, excluding the results of hedging, improved 32 percent compared to the year ended December 31, 2007 due to higher per boe prices, offset by higher royalty burden and higher per unit operating costs.



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

Operating Netbacks Three months Year

($'s per boe) ended December 31 ended December 31

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

2008 2007 Change 2008 2007 Change

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

Sales price 43.49 44.48 (2%) 57.39 44.98 28%

Less:

Royalties

(net of ARTC) 10.52 9.41 12% 13.90 10.23 36%

Production

expenses 6.98 7.23 (3%) 7.88 7.55 4%

Transportation

charges 0.97 0.99 (2%) 1.02 0.96 6%

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Operating netback 24.93 26.85 (7%) 34.59 26.24 32%

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

Operating netback

including hedging 26.39 29.53 (11%) 31.61 27.89 13%

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

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

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


General and Administrative Expenses

General and administrative ("G&A") expenses were $1.1 million in the fourth quarter of 2008, down 21 percent compared to the fourth quarter of 2007. The 2007 period incurred additional cost for increased incentive bonus payments paid in the fourth quarter of 2007 for the strong operating results achieved during 2007. In the year ended December 31, 2008 G&A expenses were $5.3 million, up 19 percent compared to the year ended December 31, 2007 due to higher salaries and inflationary pressures. In addition company operated wells were generally drilled at higher working interest than in 2007 resulting in lower capital administration costs recovered from partners.

On per unit basis, general and administrative costs were $2.49 per boe for the fourth quarter of 2008, down 38 percent compared to $4.01 per boe in the fourth quarter of 2007 due to increased production volume and lower costs. For the year ended December 31, 2008 per unit G&A costs were $3.40 per boe, up four percent from $3.26 per boe for the year ended December 31, 2007 as volume increases offset the increase in costs for the per unit calculation. There were no general and administrative costs capitalized in the fourth quarters or for the years 2008 or 2007.

Staff levels are expected to remain fairly constant in 2009. Per unit general and administrative costs are expected to decline as production levels increase.



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

General and

administrative Three months Year

expenses ended December 31 ended December 31

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

2008 2007 Change 2008 2007 Change

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

G&A expenses

($000's) 1,105 1,401 (21%) 5,255 4,433 19%

G&A expenses

per boe $2.49 $4.01 (38%) $3.40 $3.26 4%

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

Stock based

compensation

($000's) 172 239 (28%) 1,033 905 14%

Stock based

compensation

per boe $0.39 $0.69 (38%) $0.67 $0.67 -

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

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


Interest Expense

Interest expense was $0.6 million in the fourth quarter of 2008 compared to $0.9 million in the fourth quarter of 2007. For the year ended December 31, 2008 interest expense was $2.9 million compared to $4.0 million for the year ended December 31, 2007, a decrease of 27 percent. Average debt levels have remained consistent over the 2007 and 2008 period as the Company maintained a capital spending program that was limited to cash flow over the past two years. Interest rates declined significantly in 2008 as the worldwide banking and economic situation worsened and liquidity was added to the financial systems around the world resulting in the decline in year over year and quarter over quarter interest expense. On a per unit basis, annual interest costs have been reduced by 36 percent as production volume has increased while debt levels were essentially unchanged.



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

Interest Expense Three months Year

ended December 31 ended December 31

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

2008 2007 Change 2008 2007 Change

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

Interest expenses

($000's) 594 949 (37%) 2,926 4,028 (27%)

Interest expenses

per boe $1.34 $2.72 (51%) $1.89 $2.96 (36%)

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

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


Depletion, Amortization and Accretion

Depletion, amortization and accretion ("DA&A") totaled $10.4 million ($23.35 per boe) in the fourth quarter of 2008, up 10 percent in total and down 13% on a per unit basis compared to $9.4 million ($26.85 per boe) in the fourth quarter of 2007. Ongoing drilling success and low cost reserve additions have brought down per boe DA&A rates. In the year ended December 31, 2008 DA&A totaled $38.3 million ($24.81 per boe) down two percent and down 14 percent on a boe basis compared to $39.2 million ($28.79 per boe) for the year ended December 31, 2007 as the reduction in the per unit rate more than offset the increase in cost due to increased volume.



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

Depletion,

Amortization Three months Year

and Accretion ended December 31 ended December 31

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

2008 2007 Change 2008 2007 Change

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

DA&A expenses

($000's) 10,357 9,379 10% 38,336 39,180 (2%)

DA&A expenses

per boe $23.35 $26.85 (13%) $24.81 $28.79 (14%)

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Income Taxes

The Company did not pay current income tax during 2008 and does not expect to pay current income taxes in 2009 as there are sufficient capital cost pools and expected future capital spending to shelter taxable income. Current taxes were recorded for provincial capital taxes.

GOODWILL IMPAIRMENT

Goodwill, at the time of acquisition, represents the excess of purchase cost of a business over the fair value of net assets acquired. Thereafter, goodwill is not amortized and is assessed for impairment at least annually. If the estimated fair value of the business is less than the book value, a second test is performed to determine the amount of the impairment. Goodwill was originally recorded primarily on the Resolution Resources Ltd. acquisition (2003) and the Berland Exploration Ltd. acquisition (2006).

The Company recorded a partial impairment of goodwill in the fourth quarter of 2006 and a further impairment of goodwill for the remaining amount of the goodwill balance of $20.8 million in the third quarter of 2007.

NET INCOME (LOSS)

The net loss for the fourth quarter of 2008 was $0.7 million ($0.01 per share), a 3 percent improvement compared to a loss of $0.7 million ($0.01 per share) in the fourth quarter of 2007. Increased revenue from higher 2008 production volume was partially offset by higher royalties and slightly higher production costs.

Net income for the year ended December 31, 2008 was $0.4 million ($0.01 per share) compared to a net loss of $27.4 million ($0.32 per share) for the year ended December 31, 2007. The 2007 period had goodwill impairment recorded resulting in the majority of the losses.

CAPITAL COSTS

Capital costs were $12.0 million in the fourth quarter of 2008 compared to $6.4 million in the fourth quarter of 2007. A total of three net wells were drilled in the fourth quarter of 2008, equal to the number of net wells drilled in the fourth quarter of 2007. Two re-completions were conducted in the fourth quarter of 2008 with no re-completions conducted in the fourth quarter of 2007. In both years the main activity was in the Pembina area.

For the year ended December 31, 2008 $40.3 million of capital costs were incurred compared to $39.3 million (before disposition proceeds of $6.8 million) for the year ended December 31, 2007 with 18 net wells drilled in 2008 compared to 18 net wells in 2007. The 2008 and 2007 capital programs have been funded entirely by cash flow from operations resulting in average reserve growth of 19% per year over the two year period.



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

Three months Year

($000's) ended December 31, ended December 31,

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

2008 2007 2008 2007

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

Drilling and completion 7,709 3,510 27,252 24,846

Equipping and tie-ins 1,910 2,476 6,617 10,621

Land 852 42 3,922 1,418

Geological and geophysical 1,482 370 2,447 2,390

Office and other 27 4 40 56

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

Total cash expenditure 11,980 6,421 40,278 39,331

Asset retirement obligation (486) - (134) 297

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

Total capital before net

acquisitions (dispositions) 11,494 6,421 40,144 39,628

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

Net acquisitions (dispositions) - - - (6,750)

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

Total capital 11,494 6,421 40,144 32,878

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

Total cash expenditure 11,980 6,421 40,278 39,331

Abandonment and restoration (140) (81) (326) (123)

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

Capital per statement of

cash flow 11,840 6,340 39,952 39,208

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

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


Drilling, completion, equip and tie-in activity represented 80 percent of the capital spent in the fourth quarter of 2008 compared to 93 percent in the fourth quarter of 2007 and 84 percent of capital for the year ended December 31, 2008 compared to 90 percent for the year ended December 31, 2007. Capital activity in 2008 was more focused on developing the land base. A $40 million capital budget is planned for 2009, 89 percent of which is targeted toward drilling, completion, equipping and tie-in activity. It is expected that 2009 capital spending will be funded by cash flow provided by operating activities and will be adjusted should lower commodity prices occur.

WORKING CAPITAL

Accounts receivable of $12.9 million at December 31, 2008 were primarily revenue receivables ($5.9 million) and amounts owing from partners ($6.4 million). Accounts payable at December 31, 2008 of $17.3 million were mainly comprised of trade payables for capital and operating costs ($10.9 million), royalties ($1.3 million), amounts owing to partners ($1.9 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($2.3 million).

Working capital excluding the bank loan was in a deficiency position of $4.8 million at December 31, 2008. Borrowings under the bank line and ongoing cash flows are expected to fund the working capital deficiency.

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. A operating bank line was in place for $66 million at December 31, 2008, secured by producing properties. At December 31, 2008, $54.6 million was drawn on the bank line leaving $11.4 million of capacity on the line. The line of credit has been renewed at $66 million effective 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 reestablish all or part of the reduction in the bank line. Future capital spending is planned at amounts that can be met with expected operating cash flow 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 net income and funds from operations for the periods ended December 31 is as follows:



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

Three months Year

($000's) ended December 31 ended December 31

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

2008 2007 2008 2007

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

Cash flow provided by (used

in) operating activities 6,043 1,508 37,977 28,195

Changes in non-cash working

capital items related to

operating activities 3,664 6,403 2,527 1,236

Cost of abandonment and

restoration 140 80 326 123

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

Funds from operations 10,047 7,991 40,830 29,554

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

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


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 $0.11 (basic and diluted) for the fourth quarter of 2008 and $0.44 per share (basic and diluted) for the year ended December 31, 2008 compared to $0.09 per share for the fourth quarter of 2007 and $0.32 for the year ended December 31, 2007.

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 Transitional Royalty Framework adds a layer 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 2008 to fix the interest rate on $25.0 million of its variable rate demand bank line. The transaction fixes the interest rate for a two year period at an underlying borrowing rate of 3.61 percent. Including the Company's borrowing margin on its bank line the current all in rate of this transaction is 5.21 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 December 31, 2008 results in an unrealized loss of $748,000 for the year ended December 31, 2008. There were no interest rate derivatives in place in 2007. Subsequent to the end of the year, the Company cancelled the 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 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 3.99 percent.

Other risks are related to operations. These risks include, but are not limited to, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, delays or changes in plans with respect to exploration or development projects or capital costs, volatility of commodity prices, currency fluctuations, the uncertainty of reserves estimates, potential environmental liabilities, technology risks, competition for services and personnel, incorrect assessment of the value of acquisitions and failure to realize the anticipated benefits of acquisitions. The foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect operations or financial results are included in a more detailed description of risks in Berens' Annual Information Form on file with Canadian securities regulatory authorities and available on SEDAR at www.sedar.com.

Documented environmental health and safety plans are in place as well as a comprehensive emergency response plan to mitigate operating risks.

COMMODITY PRICE RISK MANAGEMENT

The Company may use financial derivative or fixed price contracts to manage its exposure to fluctuations in commodity prices and foreign currency exchange rates. The Company applies the fair value method of accounting for derivative instruments by initially recording an asset or liability, and recognizing changes in the fair value of the derivative instrument in income.

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



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

NATURAL GAS HEDGING

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

Daily

quantity

(GJ) Term of contract Fixed price per gigajoule

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

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

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


The fair value of the above natural gas derivative instruments marked to market as at December 31, 2008, results in an unrealized gain position of $114,000 compared to an unrealized gain position of $162,000 at December 31, 2007. There were $648,000 ($1.46 per boe) of realized gains on derivative instruments in the fourth quarter of 2008 (2007 - $937,000 gain; $2.68 per boe) and realized losses of $4,589,000 ($2.98 per boe) for the year ended December 31, 2008 (2007 - $2,243,000 gain; $1.65 per boe).

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



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

Commodity Price change Cash flow change ($ 000's)

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

Natural gas ($/mcf) 1.00 4,600

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

Oil and Liquids ($/bbl) 10.00 1,500

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


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 December 31, 2008 were $32,000 and for the year ended December 31, 2008 $261,000 (2007 - $27,000 and $206,000).

SHARE DATA

As of the date of this MD&A the Company had 93,547,064 issued and outstanding common shares. Additionally, options to purchase 7,397,700 common shares have been issued.

DISCLOSURE CONTROLS AND PROCEDURES

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 the financial year end of the Company 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 October 1, 2008 and ended on December 31, 2008 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 has 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 consolidated financial statements, which have been prepared in Canadian dollars in accordance with GAAP. The application of GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates are based on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions.



CHANGES IN ACCOUNTING POLICIES

Financial instruments presentation and disclosure


Effective January 1, 2008, the Company adopted the new Canadian Institute of Chartered Accountants (CICA) recommendations relating to Financial Instruments - Disclosure (section 3862) and Financial Instruments - Presentation (section 3863). The new disclosure required by section 3862 concerning the nature and extent of the risks associated with financial instruments and how those risks are managed, is presented in note 11 to the 2008 Financial Statements. Effective January 1, 2008 the Company adopted CICA recommendations relating to Capital Disclosures (section 1535).



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 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.

Credit Risk and Fair Value of Financial Assets and Financial Liabilities

On January 20, 2009, the Emerging Issues Committee of the CICA issued Abstract No. 173, "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities", concerning the measurement of financial assets and financial liabilities. There has been diversity in practice as to whether an entity's own credit risk and the credit risk of the counterparty are taken into account in determining the fair value of financial instruments. The Committee reached a consensus that these risks should be taken into account in the measurement of financial assets and financial liabilities. The Abstract is effective for all financial assets and financial liabilities measured at fair value for the interim and annual financial statements issued for periods ending on or after the date of issuance of the Abstract with retrospective application without restatement of prior periods. The Company will apply the Abstract at the beginning of its 2009 fiscal year. The Company does not expect the implementation to have a significant effect on the Company's financial position or disclosures.

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 developed a low cost, repeatable drilling program in Pembina which has resulted in consistent reserve and production growth over the past two years. The growth has been based on capital spending programs equal to cash flow over this same period. Net overall drilling success in 2008 was 75 percent and the average well results for reserves and production have significantly exceeded results experienced by Berens prior to 2007. A disciplined approach to cost management has achieved significant reduction in our cost structure both for drilling and ongoing operations. The Company lowered its finding and development costs in 2008 to $10.35 per boe and had operating costs of $7.88 per boe. With this low cost structure, economic returns and positive re-cycle ratios are achievable at natural gas prices as low as $5.00.

Capital spending for 2009 is projected at $40 million and will be funded with cash flow from operations based on assumptions of $7.00 per mcf at AECO and $70 light oil prices at Edmonton. However, the Company is committed to keeping the capital spending amounts within cash flow for 2009 and tracks spending and cash flows closely to ensure this commitment is met. An active drilling program of five wells is planned for the first quarter of 2009 with three of those wells being horizontal wells in Pembina. Capital spending in 2009 will be focused in Pembina where the Company has established a strong drilling record and the wells have the strongest economics. There are currently 85 inventoried drilling locations on existing company lands.

Debt and working capital will continue to be a focus for the Company. With the current weak natural gas price environment, the debt to cash flow ratio may increase due to weaker cash flows as capital spending will be held within cash flows to keep debt levels controlled.





Berens Energy Ltd.

Balance Sheets

As at,

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

(000's) December 31, December 31,

2008 2007

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

ASSETS (note 6)

Current

Cash $ 1 $ 1

Accounts receivable 12,854 10,315

Unrealized gain on risk management (note 11) 114 162

Prepaid expenses and deposits 300 442

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

13,269 10,920

Property, plant and equipment (note 4) 168,564 166,405

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

$ 181,833 $ 177,325

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

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

LIABILITIES AND SHAREHOLDERS' EQUITY

Current

Bank loan (note 6) $ 54,600 $ 53,900

Accounts payable and accrued liabilities 17,291 16,523

Unrealized loss on risk management (note 11) 748 -

Taxes payable 16 14

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

72,655 70,437

Asset retirement obligations (note 5) 3,491 3,273

Future income taxes (note 8) 10,420 10,199

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

$ 86,566 $ 83,909

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

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

Commitments (note 14)

Shareholders' equity

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

Contributed surplus (note 7) 3,228 2,195

Deficit (56,599) (57,042)

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

95,267 93,416

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

$ 181,833 $ 177,325

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

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

See accompanying notes to the financial statements

Berens Energy Ltd.

Statements of Operations and Comprehensive Loss and Deficit

For the three months and year ended December 31,

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

(000's) Three months Year

ended December 31, ended December 31,

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

2008 2007 2008 2007

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

Revenue

Oil and natural gas

revenue $ 19,292 $ 15,563 $ 88,738 $ 61,281

Royalties (4,665) (3,286) (21,488) (13,915)

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

14,627 12,277 67,250 47,366

Realized gain (loss) on

risk management (note 11) 649 937 (4,589) 2,243

Unrealized gain (loss) on

risk management (note 11) 159 (1,296) (48) (473)

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

15,435 11,918 62,613 49,136

Interest and other income - - 119 31

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

15,435 11,918 62,732 49,167

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

Expenses

Production 3,095 2,524 12,180 10,280

Transportation 432 346 1,578 1,307

Depletion, amortization

and accretion 10,357 9,377 38,336 39,180

Impairment of goodwill

(note 12) - - - 20,755

General and administrative

(note 10) 1,105 1,401 5,255 4,433

Stock-based compensation

(note 7) 172 239 1,033 905

Interest 594 949 2,926 4,027

Unrealized loss on interest

rate risk management

(note 11) 573 - 748 -

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

16,328 14,836 62,056 80,887

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

Income (loss) before

income taxes (893) (2,918) 676 (31,720)

Income taxes (note 8)

Future expense (recovery) (196) (2,241) 221 (4,319)

Current expense 2 3 12 39

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

(194) (2,238) 233 (4,280)

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

Net income (loss) and

comprehensive income

(loss) for the period (699) (680) 443 (27,440)

Deficit, beginning

of period (55,900) (56,362) (57,042) (29,602)

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

Deficit, end of period $ (56,599) $ (57,042) $ (56,599) $ (57,042)

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

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

Net income (loss) per

share (note 13)

Basic and diluted $ (0.01) $ (0.01) $ 0.00 $ (0.30)

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

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

See accompanying notes to the financial statements



Berens Energy Ltd.

Statements of Cash Flows

For the three months and year ended December 31,

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

(000's) Three months Year

ended December 31, ended December 31,

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

2008 2007 2008 2007

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

OPERATING ACTIVITIES

Net income (loss) for

the period $ (699) $ (680) $ 443 $ (27,440)

Add items not involving

cash

Depletion, amortization

and accretion 10,357 9,377 38,336 39,180

Impairment of goodwill - - - 20,755

Unrealized loss on risk

management 413 1,296 797 473

Future income tax

expense (recovery) (196) (2,241) 221 (4,319)

Stock-based compensation 172 239 1,033 905

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

10,047 7,991 40,830 29,554

Payments for abandonment

and restoration (140) (81) (326) (123)

Change in non-cash working

capital items related to

operating activities

(note 9) (3,864) (6,403) (2,527) (1,236)

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

Cash flow provided by

operating activities 6,043 1,507 37,977 28,195

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

FINANCING ACTIVITIES

Change in bank loan 6,100 3,100 700 3,820

Sale of investment - - - 29

Proceeds from the exercise

of stock options - - 375 225

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

Cash flow provided by

financing activities 6,100 3,100 1,075 4,074

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

INVESTING ACTIVITIES

Purchase of property and

equipment (11,840) (6,340) (39,952) (39,208)

Disposition of property

and equipment - 6,750

Change in non-cash

working capital items

related to investing

activities (note 9) (303) 1,733 900 180

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

Cash flow used in

investing activities (12,143) (4,607) (39,052) (32,278)

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

Increase (decrease) in cash - - - (9)

Cash, beginning of period 1 1 1 10

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

Cash, end of period $ 1 $ 1 $ 1 $ 1

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

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

See accompanying notes to the financial statements



BERENS ENERGY LTD.

Notes to Financial Statements

Years ended December 31, 2008 and 2007

1. NATURE OF OPERATIONS

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

exploration and production company with activities encompassing land

acquisition, geological and geophysical assessment, drilling and

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

and west central Alberta.

2. 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.

Capitalized Costs

The full cost method of accounting is followed whereby all costs relating

to the acquisition of, exploration for and development of oil and gas

reserves are capitalized in a single Canadian cost centre. Such costs

include lease acquisition, lease rentals on undeveloped properties,

geological and geophysical costs, drilling both productive and non-

productive wells, production equipment and overhead charges directly

related to acquisition, exploration and development activities.

Gains or losses are not recognized on the disposition of oil and gas

properties unless such dispositions would change the depletion rate by

20 percent or more. Gains and losses are recognized on the disposition of

other assets.

Depletion and Amortization

All costs of acquisition, exploration and development of oil and gas

reserves, associated tangible plant and equipment costs (net of salvage

value), and estimated costs of future development of proved undeveloped

reserves are depleted and amortized using the unit of production method.

This method is based on estimated gross proved reserves as determined by

independent engineers.

Costs of unproved properties are initially excluded from petroleum and

natural gas properties for the purpose of calculating depletion. When

proved reserves are assigned or the property is considered to be

impaired, the cost of the property or the amount of the impairment is

added to costs subject to depletion.

The volumes of oil and natural gas reserves and production are converted

to equivalent barrels of oil based on the relative energy content of each

product such that six thousand cubic feet of natural gas equals one

barrel of oil, commonly known as the six to one basis.

Office and computer equipment is amortized on a straight-line basis over

ten and four years, respectively.

Ceiling Test

The Company applies an impairment test to the net carrying amount of

petroleum and natural gas assets designed to ensure that such costs do

not exceed their estimated fair value ultimately recoverable. The test is

a two part test whereby the first step is to compare the net carrying

amount of the asset to the aggregate of estimated undiscounted future net

cash flows from production of proved reserves and the cost of unproved

properties less impairment. Future cash flows are estimated using future

prices and costs without discounting. Should the net carrying value of

the petroleum and natural gas assets exceed the estimated amount

ultimately recoverable, the amount of impairment is determined through

the performance of the second part of the test whereby the discounted

estimated future cash flows from proved and probable reserves based on

the future prices and costs plus the cost of unproved properties, net of

impairment allowances, is compared to the book value of the related

assets. Any reduction in net carrying value, as a result of the

impairment test, is included in depletion expense.

Asset Retirement Obligations

The Company estimates the present value of the asset retirement

obligation in the period in which it is incurred and when a reasonable

estimate of its fair value can be made, and records a corresponding

increase in the carrying value of the related long-lived asset. The

estimated fair value is determined through a review of engineering

studies, industry guidelines and management's estimate on a site-by-site

basis. The liability is subsequently adjusted for the passage of time,

which is recognized as an accretion expense in the statement of

operations and included in asset retirement obligations. The liability is

also adjusted due to revisions in either the timing or the amount of the

original estimated cash flows associated with the liability. The increase

in the carrying value of the asset is amortized using the unit of

production method based on estimated gross proved reserves. Actual costs

incurred upon settlement of the asset retirement obligations are charged

against the asset retirement obligation to the extent of the liability

recorded. Any difference between the actual costs incurred upon

settlement of the asset retirement obligation and the recorded liability

is recognized as a gain or loss in the Company's statement of operations.

Revenue Recognition

Oil and natural gas sales are recognized when the significant risks and

rewards of ownership have transferred to the buyer, the price is

determinable and there is reasonable assurance regarding collectability

of the consideration.

Income Taxes

The liability method of accounting for income taxes is followed. Under

this method, future tax assets and liabilities are determined based on

the differences between financial reporting and income tax bases of

assets and liabilities, and are measured using substantively enacted tax

rates and laws that will be in effect when the differences are expected

to reverse. The effect on future tax assets and liabilities of a change

in tax rates is recognized in net income in the period in which the

change occurs.

Joint Ventures

A substantial portion of the Company's exploration, development and

production activities is conducted jointly with others. These financial

statements reflect the Company's proportionate interest in such

activities.

Stock-Based Compensation

Under the stock option plan described in note 7, options to purchase

common shares are granted to directors, officers, employees and

consultants with option strike prices based on the market price at the

time of the grant. Options issued by the Company are accounted for in

accordance with the fair value method of accounting for stock-based

compensation using the Black-Scholes option pricing model. The resulting

cost of the option is charged to income over the vesting period of the

option with a corresponding increase in contributed surplus.

At the time of exercise, the related amounts previously credited to

contributed surplus are also transferred to capital stock. In the event

that vested options expire without being exercised, previously recognized

compensation costs associated with such stock options are not reversed.

Measurement Uncertainty

The amount recorded for depletion and amortization of oil and gas

properties, the provision for asset retirement obligations, stock based

compensation, measurement of risk management instruments and the ceiling

test calculation are based on estimates of gross proved reserves,

production rates, commodity prices, future costs, options pricing model

inputs and other assumptions. By their nature, these estimates are

subject to measurement uncertainty and the effect on the financial

statements of changes in such estimates in future years could be

material.

Per Share Information

Per share information is calculated on the basis of the weighted average

number of common shares outstanding during the fiscal period. Diluted per

share information reflects the potential dilution that could occur if

securities or other contracts to issue common shares were exercised or

converted to common shares. Diluted per share information is calculated

using the treasury stock method which assumes that any proceeds received

by the Company upon the exercise of in-the-money stock options would be

used to buy back common shares at the average market price for the

period.

Financial Instruments - Recognition and Measurement

Financial assets and financial liabilities, including derivatives, are

recognized on the balance sheet when the Company becomes a party to the

contractual provisions of the financial instrument or derivative

contract. All financial instruments are measured at fair value upon

initial recognition except for certain related party transactions.

Measurement in subsequent periods depends on whether the financial

instrument has been classified as held-for-trading, available-for sale,

held-to-maturity, loans or receivables, or other financial liabilities.

Financial assets and financial liabilities held-for-trading are measured

at fair value with changes in those fair values recognized in net income.

Held-to-maturity financial assets, loans and receivables, and other

financial liabilities are measured at amortized cost using the effective

interest method of amortization.

Derivative instruments are recorded on the balance sheet at fair value,

including those derivatives that are embedded in financial or non-

financial contracts that are not closely related to the host contracts.

Changes in the fair values of derivative instruments are recognized in

net income, with the exception of derivatives designated as effective

cash flow hedges and hedges of the foreign currency exposure of a net

investment in a self-sustaining foreign operation, which are recognized

in other comprehensive income.

Debt issue costs are expensed as incurred.

Flow-through Common Shares

Resource expenditure deductions for income tax purposes related to

exploration and development activities funded by flow-through share

arrangements are renounced to investors in accordance with income tax

legislation. The estimated tax benefits transferred to shareholders are

recorded as future income taxes and a reduction to share capital when the

expenditures are renounced, which for accounting purposes, is when the

appropriate documentation is filed with Canada Revenue Agency.

Accounting changes

Accounting changes are applied retrospectively unless otherwise permitted

or where impracticable to determine. Voluntary changes in an accounting

policy are made only when required by a primary source of GAAP or the

change results in more relevant and reliable information.

Comprehensive income (loss) and accumulated other comprehensive income

(loss)

Comprehensive income consists of net income and other comprehensive

income ("OCI"). OCI includes unrealized gains and losses on financial

assets classified as available-for-sale, unrealized translation gains and

losses arising from self-sustaining foreign operations net of hedging

activities and changes in the fair value of the effective portion of cash

flow hedging instruments.

The Company has not entered into any transactions which require any

amounts to be recorded to other comprehensive income (loss) or

accumulated other comprehensive income (loss).

3. CHANGES IN ACCOUNTING POLICIES

Financial Instruments Presentation and Disclosure

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

of Chartered Accountants (CICA) recommendations relating to Financial

Instruments - Disclosure (section 3862) and Financial Instruments -

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

concerning the nature and extent of the risks associated with financial

instruments and how those risks are managed, is presented in note 11.

Effective January 1, 2008 the Company adopted CICA recommendations

relating to Capital Disclosures (section 1535) which establishes

standards for disclosing information about an entity's capital and how it

is managed. As permitted, comparative information for the disclosure

required by section 3862 has not been provided. The adoption of these

sections did not affect the Company's financial position or operating

results.

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.

Credit Risk and Fair Value of Financial Assets and Financial Liabilities

On January 20, 2009, the Emerging Issues Committee of the CICA issued

Abstract No. 173, "Credit Risk and the Fair Value of Financial Assets and

Financial Liabilities", concerning the measurement of financial assets

and financial liabilities. There has been diversity in practice as to

whether an entity's own credit risk and the credit risk of the

counterparty are taken into account in determining the fair value of

financial instruments. The Committee reached a consensus that these risks

should be taken into account in the measurement of financial assets and

financial liabilities. The Abstract is effective for all financial assets

and financial liabilities measured at fair value for the interim and

annual financial statements issued for periods ending on or after the

date of issuance of the Abstract with retrospective application without

restatement of prior periods. The Company will apply the Abstract at the

beginning of its 2009 fiscal year. The Company does not expect the

implementation to have a significant affect on the Company's financial

position or disclosures.

4. PROPERTY, PLANT AND EQUIPMENT

December 31, 2008 December 31, 2007

Accumulated Accumulated

depletion and depletion and

($000's) Cost depreciation Cost depreciation

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

Petroleum and

natural gas

properties 314,170 145,966 274,067 108,045

Office and

computer

equipment 774 414 734 351

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

314,944 146,380 274,801 108,396

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

Net book value 168,564 166,405

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

At December 31, 2008, costs of $18,954,000 (2007 - $21,159,000) related

to undeveloped land have been excluded from the depletion and

depreciation calculation. At December 31, 2008 estimated future

development costs of $17,698,000 have been included in the depletion and

depreciation calculation (2007 - $15,511,000). A ceiling test was

completed at December 31, 2008 resulting in no impairment.

Benchmark pricing used for ceiling test purposes is shown in the

following table.

Oil

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

WTI Edmonton Cromer

Cushing Par Price Hardisty Medium

Oklahoma 40 API Heavy 29 API

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

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

Forecast

2009 57.50 68.61 43.10 59.00

2010 68.00 78.94 49.76 68.68

2011 74.00 83.54 54.35 73.52

2012 85.00 90.92 59.23 80.01

2013 92.01 95.91 62.54 84.40

Natural gas NGLs

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

FOB

Field Gate Inflation

AECO-C gas (propane/ rate Exchange

Price butane) % per rate

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

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

Forecast

2009 7.58 47.68 2.0 0.825

2010 7.94 55.65 2.0 0.850

2011 8.34 58.90 2.0 0.875

2012 8.70 64.10 2.0 0.925

2013 8.95 67.62 2.0 0.950

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 $3,491,000 as at

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

future liability of $11,231,000 (2007 - $8,611,000). These payments are

expected to be made over the next 5 to 30 years. An inflation rate of

2 percent and a credit adjusted risk free rate of 10 percent were used to

calculate the present value of the asset retirement obligations.

The following table reconciles the asset retirement obligations:

($000's) 2008 2007

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

Obligation, beginning of year 3,273 2,645

Increase in obligation during the year 612 420

Revision to estimates (421) -

Paid for abandonments (326) (123)

Accretion expense 352 331

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

Obligation, end of year 3,491 3,273

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

6. BANK LOAN

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

totaling $66.0 million at December 31, 2008 which is subject to periodic

review. The line of credit has been renewed at $66 million effective

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 1.25% if debt to

cash flow ratio is above 2.5. The average rate paid for the quarter ended

December 31, 2008 was 4.7% (2007 - 7.5%) and for the year ended

December 31, 2008 was 5.4% (2007 - 7.7%). At December 31, 2008,

$54.6 million was drawn on the bank loan, leaving $11.4 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, 2006 92,947,064 148,038

Shares issued on exercise of

stock options 225,000 225

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

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

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

Shares issued on exercise of

stock options 375,000 375

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

Balance December 31, 2008 93,547,064 148,638

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

(c) Stock Option Plan

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

outstanding common shares is reserved for options to be granted to

directors, officers, employees and consultants with terms established by

the Board of Directors.

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

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

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

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

to the date of the grant.

The following table sets forth a reconciliation of the plan activity

through December 31, 2008:

2008 2007

Weighted Weighted

average average

exercise exercise

Number of price ($ Number of price ($

Options per share) Options per share)

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

Outstanding, beginning

of year 6,238,200 1.42 4,416,200 1.68

Granted 3,521,500 0.74 2,309,500 0.94

Cancelled (1,259,500) 1.12 (262,500) 1.99

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

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

Outstanding, end of year 7,655,200 0.96 6,238,200 1.42

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

Exercisable 2,488,056 1.25 3,216,359 1.54

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

The following table sets forth additional information relating to the

stock options outstanding at December 31, 2008:

Options Outstanding Exercisable Options

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

Weighted Weighted

average average

exercise Weighted exercise Weighted

price average price average

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

range Options share) expiry Options share) expiry

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

$0.25 to $0.79 2,470,000 0.54 4.53 244,035 0.76 3.70

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

$0.80 to $1.34 4,083,000 1.05 3.27 1,271,989 1.13 1.83

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

$1.35 to $1.89 1,097,200 1.54 1.07 967,032 1.52 0.86

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

$1.90 to $2.44 - - - - - -

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

$2.45 to $3.00 5,000 2.90 1.92 5,000 2.90 1.92

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

7,655,200 0.96 3.36 2,488,056 1.25 1.64

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

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 - 2.7 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 at the dates of grant for the options outstanding at

December 31, 2008 is $0.515 per option. For the quarter ended

December 31, 2008 $171,000 and for the year ended December 31, 2008

$1,033,000 was recorded for stock based compensation (2007 - $239,000 and

$905,000 respectively) with a corresponding increase recorded to

contributed surplus. During 2008 a total of 470,000 expiring options were

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

the Board of Directors approved certain option holders to receive a cash

settlement for the difference between the market price and the option

strike price in lieu of exercising the stock option resulting in no

shares being issued for the exercise of these options.

(d) Contributed Surplus

The following table sets forth the continuity of contributed surplus for

the year ended December 31, 2008:

($000's)

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

December 31, 2006 1,290

2007 Stock based compensation expense 905

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

December 31, 2007 2,195

2008 Stock based compensation expense 1,033

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

December 31, 2008 3,228

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

At the time of exercise of a stock option, the related amounts previously

credited to contributed surplus are also transferred to share capital. In

the event that vested options expire without being exercised, previously

recognized compensation costs associated with such stock options are not

reversed.

8. INCOME TAXES

The income tax expense or recovery differs from the amount computed by

applying the Canadian statutory rates to the loss before tax as follows:

($000's) 2008 2007

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

Income (Loss) before income taxes 676 (31,720)

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

Current statutory income tax rate 29.51% 32.13%

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

Anticipated tax expense (recovery) 199 (10,193)

Increase (decrease) in recovery resulting from:

Adjust to actual tax return (164) -

Effect of future tax rate reductions (121) (957)

Impairment of goodwill - 6,669

Unrealized risk management gains - (152)

Non-deductible expenses 319 300

Other (12) 14

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

Future income tax expense (recovery) 221 (4,319)

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

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

Capital tax 12 12

Other - 27

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

Current income tax expense 12 39

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

Future income taxes reflect the net tax effects of temporary differences

between the carrying amounts of assets and liabilities for financial

reporting purposes and the amounts used for income tax purposes. The

components of the future tax assets are as follows:

($000's) 2008 2007

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

Future tax liabilities

Net book value of capital assets in

excess of tax pools (12,272) (12,132)

Future tax assets

Share issue costs 297 432

Attributed Canadian royalty income 683 683

Asset retirement obligation 872 818

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

Net future tax liabilities (10,420) (10,199)

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

Tax Pools

At December 31, 2008 the petroleum and natural gas properties had an

approximate tax basis of $127,000,000.

Capital loss carry-forwards exist totaling $3,363,000 which are available

to offset future capital gains for which no future income tax asset has

been recognized in the accounts.

9. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in Non-cash Working Capital

For the years ended December 31,

($000's) 2008 2007

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

Accounts receivable (2,539) 9,286

Prepaid expenses and deposits 142 (228)

Accounts payable and accrued liabilities 768 (10,099)

Taxes payable 2 (16)

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

(1,627) (1,057)

Change in non-cash working capital related

to investing activities 900 180

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

Change in non-cash working capital related

to operating activities (2,527) (1,237)

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

Cash interest and taxes paid

For the year ended December 31,

($000's) 2008 2007

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

Cash income and other taxes paid 10 28

Cash interest paid 2,926 4,028

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

10. 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 December 31, 2008 were $32,000

and for the year ended December 31, 2008 $261,000 (2007 - $27,000 and

$206,000).

11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Financial assets and liabilities recognized on the balance sheets consist

of cash, accounts receivable, accounts payable, bank loan and commodity

price and interest rate risk management instruments.

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

Accounts receivable are with customers, sales agents and joint venture

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

usual credit risks. The Company mitigates these risks by entering into

transactions with long-standing, reputable counterparties and partners.

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

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

spending taking place. The maximum credit exposure with accounts

receivable is the carrying value. At December 31, 2008, the largest

single credit exposure was approximately $5.5 million from the Company's

sales agent the balance of which is settled monthly. At December 31,

2008, 18 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 with to reconcile older operating and capital billings. This

party is current on recent billings. Management has assessed the

Company's accounts receivable customers and concluded the amounts owing

and no allowance for doubtful accounts receivable was required nor were

any balances deemed to be impaired.

(b) Interest Rate Risk

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

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

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

rate on $25.0 million of its variable rate demand bank line beginning in

February 2008. The transaction fixes the interest rate for a two year

period at an underlying borrowing rate of 3.61 percent. Including the

Company's borrowing margin on its bank line the current all in rate of

this transaction is 5.21 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 swap as at December 31,

2008 results in an unrealized loss of $748,000 for the year ended

December 31, 2008. A one percent change in interest rates for the

remaining term of this interest rate swap at December 31, 2008 would

change the fair value of the derivative instrument by approximately

$280,000. There were no interest rate derivatives in place in 2007. The

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

the remaining amount of bank debt is approximately $234,000. Subsequent

to the end of the year, the Company cancelled the 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 3.99 percent.

(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 is a summary of natural gas price risk management

derivative contracts in effect as of December 31, 2008. All natural gas

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

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

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

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

0.95.

Natural Gas Risk Management Contracts

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

Daily

quantity Fixed price per gigajoule

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

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

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

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

Fair values for commodity price derivatives are provided by the financial

intermediary with whom the transactions were completed and tested by the

Company for reasonableness based on comparing current market prices and

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

gas derivative instruments marked-to-market as at December 31, 2008

results in an unrealized gain of $114,000 (December 31, 2007 - gain of

$162,000). For the quarter ended December 31, 2008 a $159,000 gain was

recorded reflecting the change in the balance sheet mark-to-market

position from December 31, 2008. For the year ended December 31, 2008 a

$48,000 loss was recorded reflecting the change in the balance sheet

mark-to-market position from December 31, 2007. Total realized gains from

risk management activities in the fourth quarter of 2008 were $648,000

(2007 - $937,000 gain). Total realized losses for the year ended

December 31, 2008 were $4,589,000 (2007 - $2,243,000 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.

The estimated change in the fair value of the commodity price derivatives

in place at December 31, 2008 for a $1/mcf change in the natural gas

price is $180,000. Absent the above-noted risk management contracts, the

effects of changes in commodity prices on annual net income summarized in

the following table on the basis of average annual production of

approximately 4,600 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

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

(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

December 31, 2008 this ratio was 1.5:1 down from 1.9:1 for the quarter

ended December 31, 2007.

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

Target

At December 31 ($000's) Measure 2008 2007

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

Components of Ratio

Current assets 13,269 10,920

Current liabilities (72,655) (70,436)

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

(59,386) (59,516)

Unrealized risk management

loss (gain) 635 (162)

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Debt and working capital (58,751) (59,678)

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

Funds from operations - three

months ended December 31

annualized(1) 40,188 31,996

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

Ratio 1.5:1 1.5:1 1.9:1

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

(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.

12. GOODWILL

The Company recorded an impairment of goodwill in the amount of

$24.2 million in 2006 and a further impairment to the remaining goodwill

balance of $20.8 million in the third quarter of 2007.

13. PER SHARE INFORMATION

The weighted average number of common shares outstanding for the quarter

ended December 31, 2008 of 93,547,064 was used to calculate basic and

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

The weighted average number of common shares outstanding for the year

ended December 31, 2008 was 93,365,712 to calculate basic and diluted

income per share (2007 - 93,067,132 basic and diluted). The stock options

are considered as anti-dilutive for the year ended December 31, 2008. The

total number of shares issuable under the stock option plan which are

potentially dilutive in future periods as of December 31, 2008 was

7,655,200.

14. COMMITMENTS

Commitments exist for leased office space, software and vehicles. The

amounts for leased space exclude operating costs, taxes, insurance and

utilities:

Year

($000's)

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

2009 387

2010 450

2011 330

2012 314

2013 314

Thereafter 209

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

Total 2,004

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

Directors and officers are indemnified against any and all claims or

losses reasonably incurred in the performance of their service to the

Company to the extent permitted by law. The Company has acquired and

maintains liability insurance for its directors and officers.

15. COMPARATIVE FIGURES

Certain figures have been re-classified to conform to the financial

statement presentation adopted in 2008.

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.
    Mr. Daniel F. Botterill
    President and Chief Executive Officer
    (403) 303-3262
    Email: dbotterill@berensenergy.com

    OR

    Berens Energy Ltd.
    Mr. Dell P. Chapman
    Vice President, Finance and Chief Financial Officer
    (403) 303-3267
    Email: dchapman@berensenergy.com