Oil and Gas Reserves

2004 was the second year under National Instrument 51-101 ("NI 51-101") which was introduced last year in an effort to improve and standardize reserve reporting within the industry. Our 2004 year-end reserve report was notable on a number of fronts including:

• Record level of proved plus probable reserves of 406 million BOE, a 24% increase over last year due to an active acquisition year (49 million BOE net of divestments) and the addition of 48 million BOE of probable reserves associated with the Joslyn lease.

• Replaced 384% of production through accretive acquisitions and internal development on a proved plus probable basis and 209% on a proved basis.

• Proved reserves increased 30 million BOE or 12% from 249 million BOE to 279 million BOE. This was a result of our acquisitions, capital program and better performance in our base production that allowed a portion of our probable reserves to be reclassified as proved producing. The success of our internal development efforts, especially our 16 well per section shallow gas program, was a key contributing factor.

• Attractive FD&A costs given the robust commodity and acquisition market of $11.34/BOE using NI 51-101 methodology and $7.68/BOE under the historic methodology which excludes changes in future
development capital.

• An attractive recycle ratio of 1.9x.

• Increased Net Asset Value per unit due to higher production and reserve levels and higher future
price expectations.

• 9 million BOE net reserve additions as a result of our active internal development program excluding acquisitions, divestments and Joslyn.

Reserve Reporting and Determination Methodologies

Two external, independent third party engineering firms were used to evaluate and review our reserves this year. Sproule Associates Limited ("Sproule"), our historical independent engineering evaluators, evaluated our conventional reserves. Gilbert Laustsen Jung Associates Ltd. ("GLJ") evaluated the Joslyn SAGD bitumen reserves as they have previously performed such evaluations for the operator of the Joslyn project. Sproule evaluated 88% of the total proved plus probable value (discounted at 10%) of the Fund's year-end reserves, exclusive of the Joslyn SAGD project and, in keeping with NI 51-101, has reviewed the remainder of the reserves internally evaluated by Enerplus. GLJ evaluated the SAGD potential within the Joslyn lease using the Sproule forecast price and cost assumptions as of January 1, 2005 to maintain consistency.

The following tables report company interest reserves that include gross working interest reserves and owned royalty interest reserves using forecast prices. In addition, net and gross reserve information using forecast prices is contained under the "Supplementary Information" section of this report. Our reserve statement, which includes complete disclosure of our oil and gas reserves and other oil and gas information, as contained within our Annual Information Form will be available on our website at www.enerplus.com and on our SEDAR profile at www.sedar.com prior to March 31, 2005. Additionally, the Annual Information Form will be part of our Form 40-F that will be filed with the SEC and available on www.edgar.com prior to March 31, 2005.

Probable reserves are risked by our third party engineering firms or our own internal evaluators under the review of the third party engineering firm. Care should be used when comparing U.S. and Canadian style reserves and production reporting between companies. In the U.S., reserve estimates are calculated using prices and costs held constant at amounts in effect at the date of the reserve report. Also in the U.S. only proved reserves are reported. Proved reserve standards in the U.S. may not be comparable to the Canadian standards. Generally, Canadian standards for reporting proved reserves may be more conservative than U.S. standards for reporting proved reserves. In the U.S., only net reserves are typically reported.

As this is the second year under NI 51-101 regulation, our reserve summary and reserve reconciliation tables do not attempt to break out differences attributable to NI 51-101 since both years are using the same methodology. FD&A calculations, however, continue to include three-year average costs which incorporate 2002 year-end reserves which were not determined using NI 51-101. Given the new rules, comparisons year-over-year can be difficult. To assist investors this year, we will continue to provide FD&A calculated using NI 51-101 and using the historic method that ignores future development capital ("FDC"). In 2005, we will have three years of reserves prepared under NI 51-101 guidelines and therefore will no longer include the historic methodology.

All evaluations of future net production revenues set forth in the tables are stated without provision for income taxes, abandonment costs on wells and facilities where reserves are not assigned or associated general and administrative costs. The present value of all future cash flows at December 31, 2004 was based upon crude oil and natural gas pricing assumptions prepared by Sproule. These prices were applied to both the reserves evaluated by Sproule and GLJ. The base reference prices and exchange rates used by Sproule are detailed below:

Reserve Summary

The following table sets out our company interest volumes by production type and reserve category under a forecast price scenario. Under different price scenarios, these reserves could vary as a change in price can affect the economic limit and reserves associated with a property.

Reserve Reconciliation

The following tables reconcile the reported volumes of company interest reserves from December 31, 2003 to December 31, 2004 and highlight which production type and reserves categories contributed to the change.

Proved Plus Probable Reserves - Company Interest Volumes (forecast prices)
	light & medium oil Mbbls	heavy oil Mbbls	bitumen Mbbls	total oil Mbbls	natural gas liquids Mbbls	natural gas Bcf	total MBOE
Proved Plus Probable Reserves at Dec. 31, 2003	86,115	32,755	-	118,870	17,313	1,151.3	328,066
Acquisitions	17,716	3,141	-	20,857	808	171.8	50,292
Divestments	(44)	(425)	-	(469)	(29)	(4.4)	(1,227)
Discoveries	391	-	-	391	60	1.2	658
Extensions	977	(820)	47,747	47,904	295	17.9	51,183
Technical Revisions	(10,931)	8,733	-	(2,198)	(1,124)	(62.3)	(13,707)
Economic Factors	900	200	-	1,100	100	4.2	1,900
Improved Recovery	1,490	344	-	1,834	255	86.8	16,555
Production	(6,395)	(2,956)	-	(9,351)	(1,610)	(99.2)	(27,498)
Proved Plus Probable Reserves at Dec. 31, 2004	90,219	40,972	47,747	178,938	16,068	1,267.3	406,222

Net Present Value

These schedules have been prepared on the basis that no cash income tax will be paid by Enerplus or our operating subsidiaries in the future. Under our current structure and existing tax legislation, annual taxable income is transferred from our operating entities to the Fund through interest, royalty and other payments. We, in turn, make distributions to our unitholders and therefore currently do not incur any cash income tax. As a result, after-tax future net revenues from oil and gas reserves are equal to before tax future net revenues from oil and gas reserves.

The following table shows the net present value of future net revenue from Enerplus' reserves using the forecast prices shown. The estimated future net revenues disclosed do not represent the fair market value of Enerplus' reserves.

Net Asset Value

Enerplus' net asset value is measured with reference to the present value of all future net revenue from our reserves as estimated by our independent reserve engineers, Sproule and GLJ, plus land values, adjusted for working capital and long-term debt at year-end. This calculation can vary significantly depending on the oil and natural gas price assumptions used by the independent reserve engineers. In addition, this calculation ignores "going concern" value and assumes only the reserves identified in the reserve reports with no further acquisitions, despite our 19 year history of replacing production through acquisitions and development.

Finding, Development and Acquisition Costs

Despite rising costs, Enerplus maintained an attractive FD&A cost and more importantly, an attractive recycle ratio in 2004 and on a three-year average. Given the high commodity price environment and a robust merger and acquisition market, costs have been escalating across the industry for both acquisitions and internal development projects. Despite these increasing FD&A cost pressures, high commodity prices still provide compelling recycle ratios. Our one-year and three-year recycle ratios are a healthy 1.9x and 1.8x respectively.

FD&A costs under NI 51-101 include FDC. This provides a more representative view of the full cost of reserve additions, as it accounts for future costs to bring the reserves to market. Under the historic method, FD&A costs are understated as reserves are included without taking into account the future capital expenditures required to fully develop the reserve base. We have included the historic method only for comparison purposes to prior year results before the use of NI 51-101.

We focus on FD&A in lieu of finding and development costs ("F&D") only as it is a more comprehensive measure given the significance of acquisitions to our ongoing business model. We calculate FD&A costs using the NI 51-101 methodology for F&D by including the year-over-year change in FDC. This provides a more representative view of the true cost of reserve additions. Note however, that the aggregate of the development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

This year there was a significant increase in FDC due to the Joslyn oil sands project, our 16 well per section drilling program and future development activities associated with our acquisitions. The change in FDC associated with conventional reserves increased $121 million with approximately $50 million attributable to recent acquisitions (ChevronTexaco and Ice Energy) and a significant portion attributable to increased density shallow gas drilling from 2005 through 2017. Joslyn added another $266 million in FDC which provides SAGD development through
Phase IIIB.

(1) As the negative proved revisions during 2003 were greater than the reserve additions, the FD&A cost for 2003 is not determinable.

(2) FD&A calculated over a three-year period.

(1) 2003 reserve volumes are adjusted to negate the impacts of NI 51-101.

(2) Calculated as FD&A over a three-year period.

RECYCLE RATIO

Recycle ratio is the product of operating income divided by FD&A. This measure is indicative of the value creation within the business although it does not include all costs.

PRODUCTION AND RESERVES PER TRUST UNIT

The following tables set out our production and reserves per debt-adjusted trust unit for the three years ended 2004. It is important to note that these measures do not reflect the value of the cash distributions of $11.84 per trust unit paid to unitholders during the three-year period.

Both production and reserves per trust unit have been relatively stable for the last three years, although they can vary from year to year based on a number of factors. Over the long-term, we strive to maintain or increase these metrics, however, this remains a challenge in the context of the current industry environment due to:

• the increasing future value of each underlying barrel of oil and Mcf of gas;

• the current competitive environment for oil & gas assets;

• the depleting nature of our reserve base;

• the increasing costs associated with developing new production; and,

• timing delays between capital investments, equity financings and the ultimate realization of production and reserves from these efforts

Production per debt-adjusted trust unit is measured in respect of the average production for the year, and the weighted average number of trust units outstanding during the year. The measurements are then debt-adjusted by assuming additional trust units are issued at quarter-end unit prices to replace long-term debt outstanding at each quarter-end. The average number of trust units created over the four quarters is then added to the weighted average number of trust units to obtain the debt-adjusted number of trust units for the year.

Reserves per debt-adjusted trust unit is measured in respect of year-end proved plus probable reserves and the number of units outstanding at year-end. To eliminate the temporary timing effects of financing decisions, we have debt-adjusted these measurements by assuming we issue additional trust units at year-end prices to replace year-end long-term debt.

*2002 includes proved plus risked probable reserves