Proved Plus Probable Reserves (1)
Total reserves increased by 24% over 2003 levels.

Reserve Life Index(1)
Our reserve life index remains one of the longest in the sector.

Annual Average Production
Production volumes increased by 8% to reach a new high by 2004.

2004 Production Mix
Enerplus enjoys a balanced production mix that helps to mitigate the price risk of any one commodity.

Enerplus offers investors the benefits of owning a large portfolio of income generating energy assets without the degree of exploration risk commonly associated with traditional exploration and production companies. We also compliment our existing assets with the proven ability to expand our opportunity set within the energy industry to provide future growth potential and sustain distributions over the long-term.

OPERATIONS OVERVIEW

Enerplus is the largest conventional crude oil and natural gas income fund in North America with one of the longest reserve life indices and one of the most diverse producing asset bases in the sector.   In 2004, we delivered record levels of production, investment activity and reserve additions as robust energy prices supported an active development and acquisition program.  

Production from our assets averaged 75,130 BOE/day, a new high for Enerplus.   We invested $206.8 million in our development activities that supported these production levels and resulted in 367 net wells drilled with a 99% success rate.   We also completed the largest acquisition in our history, adding significant new production and development opportunities.   Enerplus closed the year with exit production volumes in excess of 80,000 BOE/day and the highest reserve volume in our history at 406 MMBOE. This is a direct result of our acquisition program, internal developments and the addition of 48 MMBOE of probable reserves from our Joslyn oil sands lease.

We expect our production volumes in 2005 will average 75,500 BOE/day (including our expected 2,500 BOE/day divestment program and excluding any new acquisitions).   We have planned capital expenditures of $275 million and expect to drill over 400 net wells.   Our development program will include a balance of gas and oil-related projects on our operated and non-operated properties.   We expect to exit 2005 at a rate of 77,500 BOE/day.

SUPERIOR ASSETS

Enerplus has a diverse set of producing properties concentrated in western Canada with a relatively low decline rate.

This positions us for more predictable and sustainable production volumes over the long-term.   Diversity comes through our ownership in over 300 producing properties with no single property exceeding 7% of our total production.   This mix of properties also provides a window into a significant number of the oil and gas activities in western Canada, allowing us to better understand and capitalize on acquisition and development opportunities in this basin.

Our property base provides a balanced mix between natural gas; light, medium and heavy crude oil; and natural gas liquids production that mitigates commodity price risk.   We continue to be gas-weighted at 60% by production and operate 60% of our total daily production.   This allows us to focus on developing our own core competencies in our operated properties while leveraging off the capabilities of our partners in key non-operated areas.

Asset Mix

Our assets include a diverse mix of natural gas and oil properties, both operated and non-operated, with no single property comprising more than 7% of our total production

Our lower base decline also provides us with one of the longest proved plus probable reserve life indices ("RLI") in the sector at 14.0 years.   Our long RLI is a competitive advantage for a number of reasons as it:

•  Minimizes the amount of development capital needed to sustain production at current levels.

•  Positions us to more selectively pursue accretive acquisitions since we can sustain production with internally generated projects for a period of time.

•  Mitigates the effect of any short-term price decline as a relatively limited amount of reserves are produced in a given time period.

•  Allows us to be more selective in our capital program and provides us time to monitor industry trends before investing, which reduces our overall risk and generally improves the quality of our capital investment program.

This combination of diverse assets and relatively low base decline allows us to be disciplined in our approach to acquisitions and capital investments and provides a strong asset base from which to continue to build the company going forward.  

Key Producing Properties

ACTIVE DEVELOPMENT

Drilling Activity

In 2004, we experienced the most active drilling year in our history while maintaining a 99% success rate.

Development Capital Spending

A large inventory of development opportunities and strong commodity prices supported record capital spending.

We are an active oil and gas organization with significant ongoing drilling and development projects. Over the year, we participated in the drilling of 748 gross wells, an increase of 38% over our 2003 gross drilling activity level.   Within this total, we operated 355 gross wells (269.6 net) or 73% of the net drilling activity.   We also participated in a significant number of optimization and facility-oriented projects designed to enhance our existing well and field performance. The capital efficiency of our overall development program was $18,500/BOE/day, based on initial production rates.

Approximately two thirds of our development capital was invested in gas-related projects and one third directed toward oil-related projects.   Operated projects accounted for just over half of our capital spending.   Drilling activity continued to be focused on the development of our shallow natural gas assets in southern Alberta and southwest Saskatchewan where increased drilling density (up to 16 wells per section in selected areas) complemented our traditional programs (two to eight wells per section).   The shallow gas areas around Hanna Garden, Medicine Hat, Verger, Countess and Bantry comprised the majority of our operated drilling activity.   We also had active operated drilling and facility programs in oil dominated areas such as Joarcam, Giltedge, Medicine Hat Glauconitic "C" and others.   The Shackleton and Hatton shallow gas areas in southwest Saskatchewan, the Deep Basin area of northwest Alberta, the Foothills region of western Alberta, Joffre coalbed methane ("CBM") and Joslyn SAGD development were the focus areas of our non-operated capital investment activity in 2004.

We successfully completed a record capital program despite industry limitations of services and supplies given our emphasis on improved planning and execution skills.   We focused on improved cross-group coordination internally and better relationships with key service providers externally.   We added incremental staff in a prudent manner to match our growing activity level.

2005 Outlook

2005 activity promises to be even more robust as our conventional capital program is expected to exceed our current levels. In addition, we expect to invest approximately $30 million in our Joslyn oil sands joint venture project for total capital expenditures around $275 million.   Over all, investments will be split approximately 55% in gas-related projects and 45% in oil-related projects.    

2004 Drilling Activity

2004 Capital Efficiency Summary

 

Focus on Value Creation

We believe long-term success comes from being a top quartile performer in the measures of sustained production and reserves, finding, development and acquisition costs ("FD&A"), recycle ratio and safety.    To achieve these ends, we focus our acquisitions and development capital in areas where we enjoy a competitive advantage.   These areas include shallow gas development, waterfloods and joint venture relationships with select industry partners in identified strategic areas.

Our reserves per trust unit have increased 6.5% year-over-year and have remained constant over the past three years. Production per trust unit is down only slightly year-over-year and over the last three years. These measures speak to the sustainability of the trust and our ability to maintain production, cash flow and distributions over the long-term.   Our relatively low base decline and attractive inventory of internal development projects allows us to achieve these results.   Additional details on reserves and production per trust unit can be found on page 25.   

FD&A costs have improved slightly year-over-year despite increased competition for acquired reserves and increasing service costs within the industry.   The key drivers to our results are our selective acquisitions, internal development and the addition of the Joslyn SAGD reserves.    FD&A costs reflect the cost per BOE of new reserves from both acquisition and development activities.   Under NI 51-101 reporting rules, this measure also incorporates any future development capital required to develop these reserves to more accurately reflect the full cost of new reserve additions.   For more details on FD&A costs, please see page 24 within the reserves section of this report.

Our recycle ratio has been improving over the last three years due to increasing commodity prices and our attractive FD&A costs per BOE.   Recycle ratio is determined by dividing the operating income per BOE by the FD&A cost per BOE.   This is an important measure of performance in the oil and gas industry as it incorporates many key operating metrics into a single measure which is indicative of the value created for each dollar invested.   This measure accounts for the quality of reserves, operating costs, and the attractiveness of acquisitions and internal development capital.    Additional information on recycle ratio can be found on page 25 of the reserves section of
this report.

Our key focus areas of shallow gas development, waterfloods and joint venture activities are more fully described in the following sections.   These areas have been and will continue to be the key components of our business plan.   In 2004, significant progress was made in our efforts to develop new core areas in coalbed methane and oil sands which are also detailed in the sections ahead.  

Reserves per Trust Unit (1)

Enerplus has maintained our reserves per trust unit over the last three years.

Production per Trust Unit (1)

Production per trust unit has declined only marginally over the past three years.

FD&A Costs (1)

FD&A costs improved slightly year-over-year despite increasing cost pressures in the industry.

Recycle Ratio (1)

Our recycle ratio has increased for the third straight year reflecting solid performance and increasing commodity prices.

Shallow Natural Gas Development

Shallow gas encompasses seven key properties located in southern Alberta and southwest Saskatchewan, including new areas acquired through the Ice Energy and ChevronTexaco transactions in 2004.   Shallow gas has been a core play type since the mid-90s and has provided significant value creation as gas prices have increased the value of our existing production and supported the economic development of increased density drilling.    We have grown the production from 12 MMcf/day (2,000 BOE/day) in the late-90s, to almost 84 MMcf/day (14,000 BOE/day) today through both development and acquisitions.  

Operating over 70% of our production volumes, shallow gas now represents approximately 18% of our current production and 20% of our reserves with over 500 billion cubic feet of proved plus probable reserves (83 MMBOE).   The asset base also carries a substantial reserve life index of 17 years.

Shallow gas is an excellent trust asset. The shallow natural gas formations in southern Alberta and southeast Saskatchewan consist of a massive tightly packed sandstone that covers a geographical area of over 10,000 square kilometres. These shallow gas zones are typically less than 800 metres in depth, upper Cretaceous in age with Milk River, Medicine Hat and Second White Specks as the key producing zones. Development in these regions typically consists of infill drilling the giant blanket sands as opposed to seeking smaller, individual natural gas pools. Wells typically cost $170,000 to drill and complete, and produce approximately 70 Mcf/day with 180 MMcf of reserves (although actual results will vary across the asset base).   

Key Shallow Gas Properties

Shallow Gas Production

Shallow gas is also our most active drilling area where we have typically participated in over 200 net wells per year.   In 2004, we invested $57.1 million to add 3,100 BOE/day at an average on-stream cost of $18,400/BOE/day.   We drilled over 220 conventional gross wells (two to eight wells per section) in seven different areas.   We also successfully tested a high density shallow gas infill program by drilling 75 gross wells at up to 16 wells per section in five different areas.   The success of this high density infill program confirmed significant infill drilling potential which will support continued drilling activity at the current levels for several years to come.   We also pursued an active re-frac program whereby existing wells are restimulated to increase productivity.   Optimization efforts relating to handling lower pressure and/or higher watercut wells and increased compression and facility debottlenecking programs were also pursued.  

In 2005, approximately $54 million will be invested to drill in the area of 400 gross wells (225 net) within this property base including approximately 90 high density gross shallow gas wells.  

Our success in this area involves our ability to execute large, multi-well development programs cost effectively and to manage these low-pressure operations post-drilling.   An understanding of tight shallow gas reservoirs and the effective use of production optimization techniques contribute to our success in this area.   We are currently working with other operators in the area where we hold non-operated interests to share our knowledge and encourage more rapid development to enhance stakeholder returns for all parties.

Shallow Gas production has grown significantly over time through acquisitions and development

Waterflood Development

Waterflood development is another core competency of Enerplus. In 2004, we expanded our opportunity to apply our knowledge with the purchase of the Virden properties, acquired in the ChevronTexaco transaction. Crude oil production attributable to both operated and non-operated waterfloods increased in 2004 to exit the year at 20,500 BOE/day and now represents about 25% of our current production. Remaining proved plus probable reserves are over 100 million barrels and the remaining reserve life index is 15.7 years.   This asset base provides 25% of our corporate reserves as well as long-term sustainable cash flow and significant leverage to improved recovery.  

We operate 12 major waterflood areas with an average working interest of over 80%. Our major operated fields contain over 1 billion barrels net of original oil in place with an average recovery to date of approximately 25% and a current expected ultimate recovery of approximately 30%.   We plan to continue our rigorous reservoir and waterflood management activities given that a one percent increase in ultimate recovery across these fields would increase recoverable reserves by 10 MMbbls.

Effective waterfloods require significant cross-functional technical expertise and information sharing to enhance reservoir understanding and management.   Reservoir surveillance, operational attention and cost management are key components to a successful waterflood operation.   We consistently enhance the operation of our waterfloods by expanding existing floods as well as implementing grassroots efforts such as Medicine Hat Glauconitic "C".   We unitized and implemented new waterflood operations at Medicine Hat Glauconitic "C" over the last several years resulting in 10.4 MMbbls of reserve adds and improved production performance.

Major Waterflood Areas

Med Hat Glauconotic "C"

In a waterflood, water is injected into the producin ormation to supplement original reservoir pressure and provide a drive mechanism to move additional oil to the producing well. This supplemental drive typically increases recovery from 10 - 20% to 20 - 40% of the original oil in place. The water that is produced with the oil is recycled and re-injected into the reservior.

2004 Activities

As a result of robust oil prices and attractive opportunities within our asset base, we invested $38.7 million in 2004 to pursue infill drilling, optimization activities on producing wells, water injection enhancements and debottlenecking of facilities.   A total of 45 gross wells (26.6 net) were drilled along with significant facility and optimization projects in Giltedge, Joarcam, Medicine Hat Glauconitic "C" and Pembina 5-Way.   Our program resulted in production increases of 1,500 BOE/day with an average on-stream cost of $25,800/BOE/day.   

We will continue to build on our recent successes during 2005 with a planned capital program of approximately $55 million directed at additional infill drilling and other optimization opportunities.   Significant programs include:

•  Infill development program at Pembina ($12 million);

•  Development and expansion of the Joarcam oil play ($9 million);

•  Expansion of the newly acquired Sunburst oil play in north Bantry ($7 million);

•  Development of the newly acquired Virden waterflood assets ($6 million);

•  Horizontal well development in several southeast Saskatchewan oil fields ($4 million);

•  Infill drilling and further optimization at Giltedge ($2.5 million).

If successful, a number of these programs have significant expansion potential in the years ahead.

Waterflood Production - we have mitigated declines and grown our waterflood production through acquisitions, development and optimization efforts  

Joint Venture Deep Gas

Joint Venture deep gas includes our positions in Deep Basin and the northern and southern Foothills of Alberta that are dominated by deep, expensive and high-impact gas opportunities.   While these areas can be technically challenging, they offer attractive economics and long-life production that is ideal for a trust.   We have pursued a strategy of selectively aligning with top-tier operators through minor working interest positions to mitigate risk and leverage off existing outside technical expertise.   We have benefited from this strategy as we have grown our production in these properties from 18 MMcf/day (3,000 BOE/day) in 2000 to almost 50 MMcf/day (8,200 BOE/day) by year-end 2004.   This region represents about 10% of our total production and 9% (37 MMBOE) of our proved plus probable reserves and has an attractive RLI of 11.7 years.  

Joint Venture Deep Gas

2004 Activities

We continued to participate in deep gas development in 2004 investing $21.4 million with partners to drill 84 gross (6.5 net) wells and expand and optimize critical gathering systems.   These expenditures resulted in approximately 1,700 BOE/day of new production at an attractive on-stream cost of $12,600/BOE/day.   The potential impact of these wells is shown in the table below that highlights the production, cost and economics ($/BOE/day) associated with some of the top producing wells we participated in over the last two years.   Net exposure on some wells exceeds $1 million but initial production levels can be in excess of 10 MMcf/day gross.   The Blackstone well, where we hold a 10% interest, was one of the top producing wells drilled in western Canada in 2003.  

JV DEEP BASIN / FOOTHILLS REGION TOP GROSS PRODUCING WELLS - 2003 and 2004

Key to our success in this region has been the selection of partners and limiting our working interest exposure on any one prospect.   This has allowed us to mitigate the risk in this area while providing meaningful participation.   We have made investments in a wide geographical area covering a variety of play types. This breadth of exposure has provided valuable experience and technical information, building our own internal capabilities.

Joint Venture Deep Gas Properties

Mount Benjamin

Deep Gas plays in the Foothills of Alberta can be complex and technically challenging such as this thrust sheet play in Mount Benamin operated by Petro_canada. These Foothill plays can also be very rewarding with average initial production rates of over 10MMCF/day in this area.

We plan to continue to participate with our partners in 2005 and expect to invest $25 million in drilling 80 gross wells (5 net) over the year.   We will also continue to evaluate other opportunities to expand this aspect of our portfolio given the attractive economics and success we have enjoyed.    

Joint Venture Deep Gas production has grown significantly through acquisitions and development .

POSITIONING FOR THE FUTURE

SAGD Development

The oil sands industry is forecast to be the growth engine for Canada's future oil production.   Expectations of continued robust development are accelerating given the large resource base, strong oil prices and a desire for security of supply by OECD countries.   Given their long life and typically flat production profiles, oil sands projects are also ideal investments for income trusts.   

Enerplus is unique as we are the only oil and gas trust participating in both conventional production and oil sands development through our 16% working interest ownership in Oil Sands Lease #24 ("Joslyn Creek" or "Joslyn").  

The lease is located in the Athabasca Oil Sands fairway of northeastern Alberta near other significant oil sands projects and has both steam assisted gravity drainage ("SAGD") and mining potential.

In 2002, we made a strategic investment in anticipation of the growing oil sands opportunity in western Canada.   While a number of challenges remain outstanding before the project is commercial, progress to date is ahead of expectations and the strategic rationale of adding low-cost, long-life reserves at an attractive point in the value creation process is being confirmed.   To date, we have invested a total of $29 million through 2004 including our initial investment of $16.4 million and additional expenditures for resource quantification, engineering, regulatory approvals and the currently producing SAGD Phase I.   Going forward, Joslyn will be developed by way of two additional phases of SAGD recovery and potentially four phases of oil sands mining recoveries.   Collectively the SAGD potential could be as much as 40,000 bbls/day (6,400 bbls/day net) and the mining potential could offer Enerplus attractive options to either participate in or monetize the mining interests over time.

Operator Expectations for Joslyn Lease Development

•  Enerplus owns a 16% working interest in the Joslyn project.

•  Start up for SAGD refers to initial steaming, with full production expected 12 to 18 months following.   Start up for mining refers to initial extraction, with full production expected six months following.

Oil Sands Development

SAGD is an exploitation process where two horizontal wells are drilled approximately five metres apart. Steam is injected into the reservoir through the upper wellbore permeating the oil sand, heating the oil and thus reducing its viscosity. The steam chamber grows over time, causing the heated oil to move down into the lower producing wellbore and be pumped to the surface.

2004 Activities

During 2004, a number of significant milestones were achieved in the development of the Joslyn lease including:

•  Completion of the SAGD Phase I well pair pilot during the third quarter as planned with production expected to reach the forecast target rate of 600 bbls/day gross (96 bbls/day net) in late 2005.

•  Further delineation of the resource potential through the drilling of another 280 core holes.   A majority of these were completed in early 2004 with results incorporated in the 2004 year-end reserve report. The remaining core holes were drilled in late 2004 as part of the 2004/2005 winter core hole program and are currently
being evaluated.

•  Acceleration of the Phase II development plans for a 10,000 bbl/day commercial SAGD project (1,600 bbls/day net to Enerplus). Over 70% of the facility engineering has been completed with drilling scheduled to begin in mid-2005. Production is expected in 2006, approximately one year ahead of schedule.

•  Addition of 48 MMBOE of probable SAGD reserves as assessed by third party engineering included in our
year-end reserve report. This represents 12% of our year-end reserves.  

•  Initiation of the regulatory application for SAGD Phase III, which is comprised of two 15,000 bbl/day expansions.  

•  Advancement of the mining potential.   Following completion of a preliminary feasibility study on the mining potential, the operator has awarded an engineering contract to AMEC Americas Ltd.   AMEC Americas will supply engineering support services needed to complete a regulatory application for the first two phases of mining development for total production of 100,000 bbls/day. The operator is expected to file the application in late 2005 or early 2006.

Current SAGD Developments

While the project is proceeding on or ahead of expectations, a number of challenges must be addressed before this project contributes meaningfully to our cash flow and distributions.   Key challenges include:

•  Achieving sustainable operating performance from the SAGD Phase I initial well pair and incorporating these learnings into SAGD Phase II as a commercial development.  

•  Obtaining regulatory approvals for Phase IIIA and B.

•  Understanding the marketing solutions for bitumen and implementing a long-term strategy to maximize product pricing and project returns.

•  Advancing the mining development plan, obtaining regulatory approvals and executing on the strategy. We will continue to monitor these advancements and evaluate the optimal strategy for capturing value for
our unitholders.

In 2005, we expect to complete another winter core-hole drilling program involving more than 180 gross delineation wells, increasing the Joslyn well database to more than 800 wells.   Our share of the 2005 capital and pre-commercial production operating expenditures is expected to be approximately $30 million.

Coalbed Methane

Coalbed methane has emerged as a bona fide resource play in western Canada with significant drilling and production now attributable to the play.   Enerplus is well positioned to participate in this development through our existing asset base.   We are pursuing three commercial scale CBM plays that are in the prolific central Alberta fairway and are evaluating pilot projects to determine the commercial viability in several other areas within our prospective land base.   We are also participating in an industry-wide effort to investigate the potential for enhanced CBM recovery.

CBM is an attractive trust asset in that it is typically widespread, shows good repeatability, lower risk and has a long reserve life.

CBM reserves are commonly combined with other more traditional shallow gas production to enhance the drilling economics in the area.   Our main focus is on the Horseshoe Canyon coals, although we are exploring several other coal formations in our piloting and evaluation efforts.

In 2004, we spent $9.3 million on CBM commercial development and piloting efforts that added 2 MMcf/day of gas at an on-stream cost of $28,200/BOE/day.   These costs included a high percentage of infrastructure costs which should moderate in 2005 and drive a lower on-stream cost.   Key commercial development areas include Joffre (non-operated) and Trochu (operated) acquired in the Ice Energy transaction as well as Bashaw (operated).   We are also piloting projects in Hanna Garden, Sylvan Lake and Bantry among others.   To evaluate the potential for CO 2 enhanced recovery of CBM, we are participating in an industry sponsored pilot with seven government agencies and six industry partners.

We will invest the majority of our 2005 CBM budget of $27 million in the commercial developments in Joffre, Trochu and Bashaw.   We will also continue the evaluation of CBM potential in other areas.   Overall, we plan to drill 121 gross wells (73 net) in 2005, increasing production from two to eight million cubic feet per day by year-end.   Should any of the pilot areas prove commercial, significant follow-on drilling potential would exist.

Coalbed Methane Projects