Average annual production volumes increased in 2006 as a result of our internal development program and a full year of our U.S. acquisitions.

OUR OPERATIONS

2006 Production

In 2006, we were able to grow the production from our assets as a result of the successful execution of the largest development capital program in our history and strong base performance. Daily production averaged 85,800 BOE/day, a new high for Enerplus and slightly ahead of our guidance of 85,500 BOE/day. Strong base production performance from our U.S. and Canadian operations and production additions from our capital program resulted in an increase in our year-over-year exit rate from 85,000 BOE/day in 2005 to 87,500 BOE/day in 2006, demonstrating our ability to grow production through internal development without the benefit of any significant acquisition activity.

Approximately 50% of our average daily production volumes are attributed to resource plays, with the Sleeping Giant project in Montana now our single largest producing property. We continue to operate approximately 64% of our daily production volumes.

We expect 2007 average production to remain essentially flat at 85,000 BOE/day with a reduced capital program of $410 million. We expect to exit 2007 with daily production of 86,000 BOE/day as a result of the timing of our capital expenditures which are back-end loaded. These targets are exclusive of any acquisition or divestment activity that may occur as a normal part of our business.

2006 Capital Spending

Development capital spending of $491 million during 2006 was in line with our guidance of $485 million despite industry inflationary pressures. Through this spending, we added approximately 21,400 BOE/day of initial production at an attractive on-stream cost of $23,000/BOE/day which is significantly better than our on-stream cost in 2005 and was slightly better than expected. We achieved these results due to the strength of our opportunity set and our ability to allocate capital to our most attractive projects. Our capital high-grading in 2006 included increasing our Bakken oil spending and deferring some of our less attractive shallow gas and waterflood projects.

Key attributes of our 2006 capital program include:

• We achieved better than expected capital efficiencies despite inflationary pressures. Inflation averaged approximately 15%, meaningfully higher than anticipated. As a result we chose to defer approximately 10% of our planned activity to manage our capital spending while maintaining attractive capital efficiencies.
• Approximately 57% of our capital was directed to oil development while 43% was directed to natural gas opportunities reflecting the strength of the oil markets and the attractiveness of our Bakken oil development in the U.S.
• 64% of our capital spending was focused on resource plays.
• We also invested approximately $89 million (18% of our total capital) in longer-term opportunities in oil sands, land, seismic and higher risk drilling activities which did not add production or cash flow in the current year but positions us to add significant production and reserves over the next few years.
• Operated capital spending accounted for 73% of the total which is higher than last year due to higher spending on our U.S. Bakken oil projects.

Development spending has been increasing as our internal opportunities expand.

Our capital efficiency improved in 2006 by nearly 17%.

2007 Capital Spending

Capital spending has been reduced to $410 million for 2007 based on our current commodity price outlook. Should commodity prices change and/or if we experience better success, our capital budget could increase or decrease. Our spending will continue to be focused on resource play development. We also expect to spend $84 million (20%) on longer-term opportunities in oil sands, land, seismic and higher risk drilling.

The most significant reductions in our program will occur in our shallow gas/CBM program and U.S. Bakken spending. The shallow gas/CBM program was deferred given potential risks we see with near-term gas prices although with continued gas price strength, these programs could be increased. Currently, we plan to continue with a base level program concentrating on our most profitable opportunities in this area as it is a core activity for us and represents a significant percentage of our future opportunity. The reduction in our U.S. Bakken spending reflects the completion of a majority of our drilling program of two wells per section. We are currently testing the benefits of a third well per section, exploring other zones in the area as well as extending the Bakken play into North Dakota. With success in these areas, we could increase our U.S. spending.

* 2006 production was not recorded for Joslyn as the operation has not reached commercial production levels. Based on first month production rates.

2006 Drilling Activity

In 2006, we participated in the drilling of 360.9 net wells, significantly less than our original guidance of 550 net wells, while maintaining our success rate of 99%. During the course of the year, we elected to defer a portion of our drilling program as a result of industry inflationary pressures and lower natural gas prices. We deferred the drilling of approximately 140 net shallow gas and CBM wells, approximately 30 net waterflood wells and 20 other net wells. Funds from these programs offset the inflationary pressures on the remainder of the drilling program and ensured the execution of other more profitable drilling programs such as those in our Bakken oil and other conventional drilling programs. In total we drilled 275.1 net natural gas wells and 85.8 net crude oil wells in 2006.

As commodity prices have increased, especially crude oil prices, we have expanded our asset base into new regions and resource plays. We have seen a trend toward the drilling of deeper and more technically challenging wells. We see this as a necessary competitive advantage going forward as we work to unlock the opportunity available within these new resource plays. As illustrated in our drilling chart, our shallow gas/CBM program which has historically dominated our drilling program has declined due to natural gas price weakness in 2006 and the growth of drilling in more challenging oil areas.

We maintained an active drilling program in 2006 with a 99% success rate.

Total reserve volumes were essentially flat year-over-year.

Reserves

Attractive reserve additions from our U.S. properties, oil sands and conventional Canadian operations were partially offset by unexpected capital inflation and negative revisions (mainly in the probable category) in our Canadian conventional areas. Enerplus achieved overall proved plus probable finding, development and acquisition costs including future development capital of $23.19/BOE in 2006 ($20.45/BOE excluding FDC) and a three-year average FD&A cost of $14.90/BOE ($11.51/BOE excluding FDC).

Other key points in our reserve assessment include:

• Reserve life index increased to 14 years in line with our historical performance.
• We replaced 82% of our produced reserves production without the benefit of any significant acquisitions. Over the last five years, we have averaged almost 200% reserve replacement inclusive of acquisition and divestment activity.
• Our U.S. operations added 7.3 million BOE at a one-year proved plus probable F&D cost of $13.78/BOE including FDC reflecting a 20% increase in reserves at December 31, 2005 as a result of our strong operational and development performance in the U.S.
• 6.9 million BOE were added to our oil sands reserves at a one-year proved plus probable F&D cost of $10.54/BOE ($5.67/BOE excluding FDC) reflecting another successful year of core hole drilling and analysis.
• No changes were made to the allocation of reserves associated with the SAGD portion of the Joslyn lease versus the mining portion. Total and Enerplus are in discussions on a potential change to the lease development plan which could impact the reserve allocation between the mine and SAGD portions of the lease and the timing of reserve bookings.
• There are no proved or probable mining reserves included in our year-end reserve summary. The current North Mine project continues to progress and there is the potential to book probable reserves associated with this project at year-end 2007.
• Canadian conventional development added over 19 million BOE, excluding negative revisions, at a one-year proved plus probable F&D cost of $20.63/BOE ($17.17/BOE without FDC). This reflects the strong conventional drilling results we achieved in Canada which were partially offset by the negative revisions tied to existing Canadian operations.
• Proved and probable negative revisions of 7.5 MMBOE were predominantly from the "probable" reserves category which has less certainty than "proved" reserves. These revisions represent less than 2% of our total year-end reserves and were mainly due to performance and economic factors in a few of our older Canadian conventional properties.
• No changes to the after-tax calculations have been included for our Canadian assets in connection with the proposed changes on taxability for trusts in the Canadian market. Should the proposed legislation be enacted, Enerplus would provide an updated analysis which would include the effect of any enacted tax legislation.
• Acquisition and divestment activity resulted in no significant change to our reserves. Minor acquisitions were offset by the sale of a 1% working interest in our Joslyn lease.

For a full description of our reserves and the associated reserve reporting determination and methodologies, please see the reserve section.

We replaced 82% of production from our internal development program without any significant acquisition activity.