Our executive team has over 200 years of combined oil and gas industry experience and reflects a positive mix of engineering, accounting, legal and business acumen.

It has been another exciting and rewarding year for Enerplus.   For the third consecutive year, as measured on a three-year rolling basis, we have achieved top tier performance for our unitholders.   We met or exceeded a number of our operational targets and completed the single largest acquisition in our history with the acquisition of the ChevronTexaco assets completed mid-year.   The key highlights of 2004 were:

•  21.5% total return for our Canadian unitholders and a 29.9% total return for our U.S. unitholders, as the appreciation in the Canadian dollar effectively increased distributions and the unit price when exchanged into U.S. dollars.

•  31% increase in funds flow from operations to $540.0 million and 14% increase per trust unit to $5.44 per
trust unit.

•  Distribution to unitholders of CDN$4.20 per trust unit representing a payout ratio of 79%.

•  Annual average production volumes of 75,130 BOE/day (comprised of 60% natural gas, 34% crude oil and 6% natural gas liquids) exceeded our production target for 2004 of 74,000 BOE/day and set a new record of annual production for the Fund.

•  Acquired 50.3 million BOE of proved plus probable reserves for $636 million.

•  Invested $206.8 million in development drilling and facility enhancements, participating in 367 net wells with a 99% success rate, both all-time highs for Enerplus.

•  Increased proved reserves by 12% to 279.1 MMBOE and proved plus probable reserves by 24% to 406.2 MMBOE inclusive of the addition of 48 MMBOE of probable reserves from our Joslyn lease.   Positive reserve additions from acquisition and development efforts were successful in replacing 209% of 2004 production on a proved basis, and 384% on a proved plus probable basis.

•  Achieved finding, development and acquisition costs ("FD&A") for the year of $11.34 per BOE on a proved plus probable basis and $15.83 per BOE on a proved basis, both calculated including future development capital.

•  Achieved FD&A for the year of $7.68 per BOE on a proved plus probable basis and $14.11 per BOE on a proved basis, both calculated excluding future development capital.

•  Reserves per debt-adjusted trust unit increased by over 6% year-over-year, while production per debt-adjusted trust unit decreased 4% over the same period.

•  Maintained one of the longest Reserve Life Indices ("RLI") in the sector at 14.0 years on a proved plus probable basis and 10.1 years on a proved basis.

•  Achieved a recycle ratio (operating income divided by FD&A) of 1.9x for 2004 and 1.8x on a three-year basis.

•  Negotiated a new $850 million unsecured, covenant-based, three-year committed bank credit facility.

•  Maintained a conservative balance sheet as evidenced by a net debt to trailing funds flow ratio of 1.1x.

Our capital spending on development drilling and facility enhancements was invested across a diversity of play types through both operated and partner-operated projects.   Approximately $137 million was invested in natural gas-related projects and $70 million in oil-related projects.

On operated gas projects, our investments in 2004 were largely focused on shallow gas development where we have significant expertise.   On non-operated deep gas projects we have utilized the expertise of our partners combined with our own to selectively participate in a number of deeper, higher impact gas developments.

A focus for our investment in oil projects has been, and continues to be, in the application of waterflood development.   We have achieved success in improving recoveries from mature oil properties that have significant oil in place.   In 2004 approximately 55% of our investment in oil projects was related to properties where effective waterflood management is a key driver.

Also, this past year we experienced a positive advancement in the development of our interest in the Joslyn lease.   This lease, in which we hold a 16% non-operated working interest, is located in the oil sands fairway of Alberta.   In 2004 steaming commenced in the initial pilot well pair and a number of technical and regulatory milestones were achieved to move this investment toward commercial production.   As a result of the progress on the Joslyn lease, independent engineering evaluations have resulted in the addition of 47.7 million barrels of probable bitumen reserves to our reserve base.   While there are still a number of technical, regulatory and operational challenges to be met relative to realizing the potential of this investment, we are excited about the progress made to date.   Commercial production is expected to commence in 2006, a full year ahead of schedule.

In addition to our development activities, we were successful in adding over 50 million BOEs of proved plus probable reserves through acquisitions, most notably the ChevronTexaco and Ice Energy acquisitions.   The properties contain significant development opportunities that will allow us to apply some of our key technical strengths. Both of these transactions were completed in a highly competitive acquisition environment and required innovation to successfully complete.   In the case of the Ice Energy acquisition we were able to build off an initial equity investment that improved our economics in making the acquisition.   In the ChevronTexaco acquisition we formed a consortium of three parties that allowed each of the buying parties to achieve a strategic fit of properties to their respective risk profiles and technical strengths.

Commodity Prices

The price of oil continued to dominate the headlines relative to commodity prices.   Over the past year the WTI reference price averaged US$41.40 a barrel, a 33% increase over the 2003 average.   Continued disruption of supply due to civil unrest in various producing regions of the world coupled with increasing demand from developing nations, most notably China, have helped sustain the increase in oil prices. However, at the end of 2004 there was a significant differential in the price for heavier quality crude in North America from the higher quality crude compared to historical averages.   We believe the differential widened at year-end due to a number of factors, including seasonality of demand for heavier crude, refinery backups and the availability of diluent for blending requirements. Given an overall increase in the level of production forecast to be generated out of oil sands development in Canada coupled with declining U.S. domestic production, there are a number of options being pursued to expand delivery capacity for the heavier quality crude into the U.S. market. Enerplus is positioned to take advantage of this expanded market potential through our investment in the oil sands.

Gas prices, by comparison, increased more moderately year-over-year with the NYMEX Henry Hub price averaging US$6.09 per MMBtu in 2004 versus US$5.54 in 2003 and the AECO monthly reference price averaging CDN$6.79 per MMBtu in 2004 compared to CDN$6.70 in 2003.   Gas storage levels through the winter heating season have been maintained above historical averages and market concerns over shortages from a cold winter draw have dissipated.   Over the long-term we believe concerns over declining gas production in North America are valid, especially in view of the energy requirements associated with oil sands development. However, we could face volatility of prices in the near-term.

As we believe there will be continued volatility in commodity prices, we will continue to manage our exposure to downside commodity price risk through the use of financial instruments. We believe our risk management strategy provides support to our unitholder distributions and our development economics. However, as we have experienced losses due to the rapid increase in crude oil prices, we are more inclined to absorb the cost of downside risk protection without offsetting the cost of that protection through the sale of upside price participation.  

2005 Outlook

We expect many of the challenges that faced us in 2004 will continue throughout 2005. These include increased competition for oil and gas assets, skilled professionals and industry services along with the potential for interest rate increases and concerns over the strength of the U.S. economy.   Our key strategies to meet these challenges are:

•  pursue conventional oil and gas property acquisitions that will be accretive to our unitholders and provide further development opportunities;

•  develop our shallow gas, waterflood and non-operated deep gas projects to add new opportunities;

•  develop our interests in the oil sands and CBM projects;

•  seek opportunities to expand our interests in oil and gas related projects beyond western Canadian conventional oil and gas;

•  seek and establish strategic relationships with junior oil and gas companies whose growth strategies provide us with strategic opportunities;

•  continue to develop skill sets to support our technical requirements and provide compensation based
upon performance;

•  maintain a strong balance sheet targeting a debt to funds flow ratio of under 1.5x;

•  manage downside commodity price risk;

•  promote and sustain strong corporate governance;

•  promote and sustain safe and responsible development of our resources.

We expect to invest $275 million in 2005 on our development activities with approximately 55% directed toward gas projects and 45% directed toward oil projects.   Shallow natural gas and waterflood development will continue to play a significant role in our development plans.   We expect to spend $54 million on further shallow gas development including the drilling of approximately 225 net wells and $55 million on waterflood development activities.   In doing so, we will be capturing some of the value potential we recognized in our acquisitions of the ChevronTexaco assets and Ice Energy.   We will continue to participate alongside our partners in deep gas development investing $25 million in 80 wells.   Spending related to positioning for the longer term will include $30 million in the Joslyn project and $27 million to participate in drilling over 120 wells to develop coalbed methane.

Based upon our development plans, we expect to average approximately 75,500 BOE/day of production in 2005, with a similar weighting to natural gas and crude oil as experienced in 2004.   This expected level of production is net of the disposition of non-core oil and gas properties currently producing approximately 2,500 BOE/day, which are targeted to close in Q1 and before any additional oil and gas property acquisitions.   As activity levels in the industry remain high, competition for services and skills remains strong and regulatory compliance costs increase, we are expecting an increase in both our operating expenses and general administration expenses on a per BOE basis.   I encourage our readers to review the "Management's Discussion and Analysis" ("MD&A") section of our annual report for a fulsome discussion of our guidance in respect of these costs and other factors that will affect our financial performance in 2005.

In our third quarter report I advised that the Federal Government of Canada had put forward certain proposals that included a proposal that would have restricted the level of foreign ownership of trusts such as Enerplus.   I am pleased to report that Enerplus, together with other interested parties, successfully lobbied the federal government and this proposal has been removed from the pending legislation.   Again, I direct our readers to the "Income Taxes" section of our MD&A for further discussion of proposals impacting unitholders that are still contained in the pending legislation.   We also urge readers to review the discussion on non-resident ownership contained in the Risk Factors and Risk Management section of the MD&A.

Also, I am pleased to advise that Standard and Poor's have recently announced that Income Trusts will be eligible for inclusion in the S&P/TSX Composite Index in mid-2005. We fully expect Enerplus will qualify for inclusion at that time.

I extend my thanks to our entire team here at Enerplus for another successful year and the way we have conducted ourselves in our operations.   We are proud to again report to our stakeholders that we participate in the Canadian Association of Petroleum Producers' Stewardship program at the highest level ("platinum"), that we continue to promote safe and responsible resource development and that we are committed to improving the quality of life in the communities where we live and operate.

I also want to extend a special thanks to Mr. Derek Fortune who recently retired from our Board of Directors.   Mr. Fortune provided guidance and mentoring to Enerplus over a 12-year history and we thank him for his contribution to our success.

Next year at Enerplus we will celebrate our twentieth year of operation as an energy-based trust.   We have built a reputation on a basis of solid, long-term financial performance.   We look forward to continuing that performance and thank all of our stakeholders for investing with us.

Gordon J. Kerr

President & Chief Executive Officer