Diversified by Property and Commodity

As Canada’s largest conventional oil and gas income fund, Enerplus is focused in western Canada with a diverse set of assets producing both oil and natural gas. During 2003, we produced in excess of 69,400 BOE/day and invested over $150 million of development capital. Employing a complement of technical, operating and administrative staff, Enerplus has proven itself as an effective and efficient operator and developer over the last 18 years.

Enerplus is focused on value creation activities with specific expertise in shallow natural gas, crude oil waterfloods and foothills development through our joint venture partnerships. Overall, we brought on 11,000 BOE/day for an average on-stream cost of $14,336 per daily barrel in 2003 with a majority of this capital invested in our core areas. We have the advantage of a large and diversified asset base that mitigates risk and supports more stable cash distributions. With interests in approximately 4,000 net operated wells and 1,200 net partner-operated wells, we have a window into activity throughout the basin that allows us to participate in attractive emerging areas and provides a wider spectrum of acquisition opportunities.

ENERPLUS ENJOYS A BALANCED PRODUCTION MIX THAT HELPS TO MITIGATE THE PRICE RISK OF ANY ONE COMMODITY

Our asset base contains a healthy mix of operated and non-operated properties, producing a combination of natural gas, light and heavy oil and natural gas liquids. We make a concerted effort to have diverse exposure to both crude oil and natural gas to limit the price risk associated with any one commodity. While our recent focus has been on acquiring and developing natural gas assets, we will also continue to develop and add to our oil producing areas.

SINCE NO ONE PROPERTY REPRESENTS MORE THAN 5% OF OUR TOTAL PRODUCTION, THE RISK OF A SIGNIFICANT PRODUCTION INTERRUPTION IS LOW

Long Life Assets

ENERPLUS ENJOYS ONE OF THE LONGEST RESERVE LIFE INDICES IN THE SECTOR. THIS HELPS SUSTAIN DISTRIBUTIONS OVER THE LONG-TERM

Enerplus has maintained one of the longest proved and probable reserve life indices in the sector at 13.3 years.

OUR LONG RLI IS A COMPETITIVE ADVANTAGE AS IT REFLECTS A LOWER DECLINE RATE ON OUR EXISTING PRODUCTION, REDUCING THE DEVELOPMENT CAPITAL NEEDED FOR REINVESTMENT TO MAINTAIN PRODUCTION

This allows us to more prudently develop our properties over time, thereby reducing the risk of over committing capital before a project is proven. Traditional exploration and production companies are driven to accelerate production to maximize cash flow for reinvestment and typically have a much shorter RLI. At times, they also have a greater risk of over committing on a project in an effort to accelerate production additions. We believe our lower risk approach provides more stable cash flow and distributions over the long-term which is critical to our yield-oriented business model.

In 2002, Enerplus reorganized its operations into four operated and one joint venture business unit. This organizational structure provides improved operational and technical focus resulting in superior operating and capital efficiencies. It supports the opportunity for growth in each of the business unit areas. Each of the five business units represents its own profit centre with a complement of engineers, geologists, operators, landmen and support personnel.

ENERPLUS FOCUSES ON OPPORTUNITIES WHERE WE HAVE A COMPETITIVE ADVANTAGE

Enerplus focuses its acquisition and capital development program on areas where we enjoy a competitive technical or operating advantage. These areas include shallow natural gas, crude oil waterfloods and deep foothills natural gas and have resulted in production increases that help to offset the natural decline of our asset base. Our strategy has been to develop a strong position in each asset class through both operated and non-operated interests. This focus provides meaningful direction to our ongoing acquisition and divestment efforts as we continually upgrade our asset base.

As a result of these efforts, Enerplus has maintained an attractive finding, development and acquisition cost (“FD&A”) on a proved plus probable basis over time. Our three-year FD&A cost using the new NI 51-101 methodology is among the best in our sector at $8.54 per BOE or $7.86 per BOE using the historical methodology.

WE ALSO ENJOYED AN ATTRACTIVE RECYCLE RATIO OF 1.8 IN 2003 USING OUR NETBACK DIVIDED BY OUR FD&A COSTS

This metric is indicative of the value created by our investment activities. The higher the recycle ratio, the better the profitability, with a recycle ratio below one representing negative value creation.

While overall corporate performance is reflected by the above FD&A and recycle ratios, the activities which are driving this performance centre around shallow gas, crude oil waterfloods and foothills gas development projects which are detailed following.

SHALLOW NATURAL GAS DEVELOPMENT

SHALLOW NATURAL GAS PRODUCTION HAS GROWN 600% OVER THE LAST FIVE YEARS TO ALMOST 70 MMCF/DAY (11,500 BOE/DAY) PRIMARILY THROUGH ACQUISITIONS, DEVELOPMENT DRILLING AND OPTIMIZATION TECHNIQUES

Enerplus has created significant value over the last five years from our shallow natural gas areas. Natural gas production from this asset base has grown 600% in the last five years to approximately 70 MMcf/day (11,500 BOE/day) primarily through targeted acquisitions, development drilling and optimization techniques. Enerplus has drilled in excess of 800 shallow gas wells over the last five years. In 2003, we drilled 250 shallow natural gas wells and spent approximately $42 million to bring on 2,150 BOE/day at an average on-stream cost of $19,488/BOE/day.

Rising natural gas prices have provided a dual benefit to shallow gas development in that it has generated both higher cash flows on current production and provided compelling economics for infill drilling. Our ability to execute cost-effective, multi-well shallow gas drilling programs has been instrumental to our success.

We see additional drilling and development opportunities in the years ahead and plan to spend approximately $38 million on shallow gas opportunities in 2004. As part of this investment, we plan to follow-up on successful increased density drilling initiated in 2003 and will also continue traditional infill drilling and optimization activities throughout our asset base.

Area	Capital Spending ($millions)	IP Rate (BOE/day)	Initial On-Stream Cost $/BOE/Day
Bantry/Countess	$18.2	870	$20,920
Medicine Hat/Fox Valley	12.3	400	30,750
Hanna Garden	6.1	280	21,786
Verger	5.3	600	8,833
Total	$41.9	2,150	$19,488

 

 

 

WATERFLOOD DEVELOPMENT

SINCE 2001, PRODUCTION HAS GROWN AS A RESULT OF OUR WATERFLOOD DEVELOPMENT AND ACQUISITION ACTIVITIES, MORE THAN OFFSETTING NATURAL PRODUCTION DECLINES

Enerplus operates 15 crude oil waterfloods with over one billion barrels of original oil reserves in place that produced approximately 18,000 BOE/day in 2003. These assets provide significant opportunity to enhance production and increase the recoverable portion of these reserves. Since 2001, production has gradually grown as a result of our development and acquisition activities, more than offsetting natural production declines. Last year, we spent $31.8 million on major development projects and brought on 1,965 BOE/day for an average on-stream cost of $16,183 BOE/day.

GIVEN THE LARGE ORIGINAL OIL IN PLACE, EACH ADDITIONAL ONE PERCENT IMPROVEMENT IN RECOVERY HAS THE POTENTIAL TO ADD 10 MILLION BARRELS OF RECOVERABLE OIL RESERVES

With an average recovery factor of 19% to date, over 80% of the original oil remains unrecovered. Typically these fields have higher operating costs given the significant water handling and electrical costs involved. However, effective management of these costs can increase profitability and extend the economic life of the field.

Enerplus has developed a core competency in waterflood application and we plan to spend an additional $27 million on these opportunities in 2004. An example of this competency is our successful acquisition and waterflood implementation at the Medicine Hat Glauconitic “C” property where we anticipate incremental reserve recovery of 1.3 MMBOE. We are currently performing integrated field reviews and operating cost reviews on all our waterfloods to ensure optimal recovery, production rates and decreased costs are achieved from this resource base.

 

Area	Capital Spending ($millions)	IP Rate (BOE/day)	Initial On-Stream Cost $/BOE/Day
East Central Alberta	$14.9	980	$15,204
Northern	4.5	285	15,789
Joarcam/ Medicine Hat	6.3	360	17,500
Gleneath	3.1	180	17,222
Pembina	3.0	160	18,750
Total	$31.8	1,965	$16,183

 

 

 

JOINT VENTURE FOOTHILLS DEVELOPMENT

 

WHILE OPERATED PROPERTIES HAVE CREATED SIGNIFICANT VALUE FOR THE FUND, WE RECOGNIZE THE BENEFIT OF PARTICIPATING WITH EXPERIENCED PARTNERS ON MORE EXPENSIVE, TECHNICALLY CHALLENGING PLAYS

 

Enerplus has developed a significant non-operated production base of over 8,000 BOE/day from the deep foothills area of Alberta. This has been accomplished principally through strategic acquisitions and drilling participation with top tier operators. While operated properties have created significant value for the Fund, we recognize the benefit of participating with experienced partners on more expensive, technically challenging areas. This allows us to limit our risk on any single development project and minimize our overhead. We also gain valuable experience and exposure to a broad, attractive opportunity set that we can potentially apply to our operated properties.

 

Our strategy has been beneficial as we participated in approximately 95 gross wells (7 net wells) in 2003 for total costs of $21.4 million with 2,410 BOE/day of initial production at an attractive cost of $8,880/BOE/day. Overall, we expect to spend up to $20 million during 2004 in this area.

 

Area	Capital Spending ($millions)	IP Rate (BOE/day)	Initial On-Stream Cost $/BOE/Day
Deep Basin	$10.8	1,330	$8,120
Northern Foothills	8.4	980	8,571
Southern Foothills	2.2	100	22,000
Total	$21.4	2,410	$8,880