• Reserves at year-end set another record level with proved plus probable reserves of 449 million BOE, an increase of 43 million BOE (11%) over last year.
• Our internal development program generated the highest number of reserve additions in history with 25 million BOE of proved plus probable and 13 million BOE from economic factors (mainly forecast prices) totaling 38 million BOE, more than offsetting annual production of 29 million BOE.
• Our acquisitions activity resulted in 34 million BOE of net proved plus probable reserve additions after divestments of 8 million BOE.
• Reserve additions were realized from all major play types including shallow gas, waterfloods, CBM, deep gas and other conventional play types. Shallow gas was the top contributor to the reserve additions from our development efforts with approximately 7 million BOE on a proved plus probable basis.
• On a proved basis, our reserves increased by 34 million BOE (12%). Our proved reserves now account for approximately 70% of our total reserves.
• 9.5 million BOE of proved reserves were assigned to our Joslyn SAGD project and proved plus probable reserves in the project increased by 5.4 million BOE.
• Net acquisitions and development additions replaced 247% of 2005 production on a proved plus probable basis and 217% on a proved basis.
• FD&A costs increased both including FDC($17.18/BOE) and without FDC ($13.98/BOE) on a proved plus probable basis mainly due to higher acquisition costs. The Sleeping Giant field of Montana was our major acquisition target in 2005 and produces exceptionally high priced light oil with low operating costs. The relatively high FD&A cost of ownership in this field is justified by the high netback received from production. We still maintain an attractive three-year average FD&A cost with FDC of $13.46/BOE and $10.09/BOE without FDC.
• Our finding and development costs (including FDC) were $11.97/BOE due to the record additions achieved from our internal development program.
• Our recycle ratio was 1.7x decreasing slightly due to the higher cost of acquisitions used in calculating the ratio coupled with our 2005 operating income that does not reflect the higher quality of these acquisitions due to timing. Our three-year average recycle ratio remains attractive at 1.8x.

Reserve Reporting and Determination Methodologies
All reports, including our U.S. reserves, were evaluated using Canadian NI 51-101 rules. Three 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 Canadian conventional reserves. GLJ Petroleum Consultants Ltd. ('GLJ') evaluated the Joslyn SAGD bitumen reserves as they have previously performed such evaluations for the operator of the Joslyn project. DeGolyer and MacNaughton ('D&M') of Dallas, Texas, evaluated the reserves attributed to our assets in the United States.

Sproule evaluated 89% of the total proved plus probable value (discounted at 10%) of our Canadian conventional year-end reserves, in keeping with NI 51-101 and has reviewed the remainder of the reserves internally evaluated by Enerplus. Both GLJ and D&M evaluated 100% of the reserves in their respective areas. Both GLJ and D&M utilized Sproule's price forecast and cost assumptions as of December 31, 2005 in their evaluations 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, is available on our website at www.enerplus.com and on our SEDAR profile at www.sedar.com on March 10, 2006. 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-online.com on March 10, 2006.

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. Under U.S. reporting, reserve estimates are calculated using prices and costs held constant at amounts in effect at the date of the reserve report and typically only include net proved reserves. Additionally, 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.

All evaluations of future net production revenues set forth in the tables are stated after the provision for income taxes, and exclude abandonment costs on wells and facilities where reserves are not assigned or associated general and administrative costs. These schedules have been prepared on the basis that no cash income tax will be paid by Enerplus' Canadian operating subsidiaries in the future. Under our current mutual fund structure and existing tax legislation in Canada, 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 Canadian 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.

Our U.S. operations are subject to cash income taxes and as a result, our U.S. reserves are shown net of the taxes that we estimate would be payable after taking into account inter-company debt in our structure.

The present value of all future cash flows at December 31, 2005 was based upon crude oil and natural gas pricing assumptions prepared by Sproule. These prices were applied to the reserves evaluated by Sproule, GLJ and D&M. The base reference prices and exchange rates used by Sproule are detailed on the next page.

• "Extensions" from deep gas drilling in the Deep Basin and Moose (3.5 MMBOE).
• "Technical revisions" for bitumen reserves (5.4 MMBOE) from positive results of our delineation drilling.
• "Improved recovery" due to shallow gas infill drilling at Verger and Bantry (2.9 MMBOE) and oil infill drilling at Bantry North and Joarcam (2.8 MMBOE).
• "Economic factors" (13.2 MMBOE) were mainly due to changes in price forecasts for oil and gas which extend the life and recovery of an oil and gas field.