management's discussion and analysis ("MD&A")

The following discussion and analysis of financial results is dated March 10, 2004 and is to be read in conjunction with the audited consolidated financial statements as at and for the years ended December 31, 2003 and 2002.   All amounts are stated in Canadian dollars unless otherwise specified.   All references to notes are to those included with the consolidated financial statements. In accordance with Canadian practice, production volumes, reserve volumes and revenues are reported on a gross basis, before deduction of Crown and other royalties, unless otherwise indicated.   Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE.   The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead.   Effective September 30, 2003, the Alberta Securities Commission implemented National Instrument 51-101 ("NI 51-101") "Standards of Disclosure for Oil and Gas Activities". See recent Canadian accounting related pronouncements for further information.

Throughout the MD&A, we use the term funds flow from operations ("funds flow") and cash available for distribution.   These terms as presented do not have any standardized meaning as prescribed by Canadian generally accepted accounting principles ("GAAP"), and therefore they may not be comparable with the calculation of similar measures for other entities.   Funds flow as presented is not intended to represent operating cash flows or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP.   All references to funds flow throughout this report are based on cash flow from operating activities before changes in non-cash working capital.   Cash available for distribution is calculated using funds flow less cash withheld for acquisitions and capital expenditures.  

2003 Overview

Successful acquisitions and development capital spending increased production, while high commodity prices, which were somewhat offset by the strengthening Canadian dollar, also helped to deliver positive returns for unitholders during 2003.   Increased levels of activity within the oil and gas industry pushed costs higher throughout the year, while the positive impact associated with the internalization of the management contract should provide long term benefits to the Fund and unitholders.

Highlights

• Our unitholders realized a 55.4% total return in 2003 (representing the appreciation in unit price plus distributions paid during the year).   This performance placed Enerplus third in a peer group of the eight largest conventional oil and gas trusts for 2003 and first on a three-year rolling basis for the second year in a row.

• Funds flow from operations, driven by strong oil and natural gas prices, increased 19% per trust unit.

• We paid $379.1 million to unitholders ($4.32 per trust unit) and retained $34.1 million ($0.39 per trust unit) for capital expenditures.   This represented a payout ratio of 92% (81% before taking into account the internalization of the management contract as described below).

• Net income per trust unit increased 80% mainly due to higher commodity prices and production levels compared to 2002.

• We exceeded our annual production target for 2003 with average production volumes of 69,414 BOE/day despite an ongoing divestment program.

• Enerplus continued its active development program, investing $157.7 million in development drilling and facility enhancements.   In 2003 we drilled 294 net wells with a 98% success rate.

• We spent $225.3 million acquiring oil and natural gas companies and properties during 2003.   The Fund's finding, development and acquisition costs ("FD&A") for the year (using the new NI 51-101 standards) was $11.60 per BOE and $8.54 per BOE on a three-year basis.

• We disposed of $73.2 million in non-core properties during the year.

• Our recycle ratio (netback divided by FD&A) was 1.8 for 2003 and 1.9 on a three-year basis.

• Proved and probable gross reserves declined less than 1% compared to last year.   Positive reserve additions from acquisition and development efforts were successful in replacing production and offsetting disposition activity for the year and negative revisions associated with NI 51-101.

• Enerplus had positive gross reserve revisions on a proved and probable basis of 1.3% or 4.0 million BOE.   Positive revisions of 14.2 million BOE associated with our development activities more than offset negative revisions of 10.2 million BOE associated with NI 51-101.   The majority of the NI 51-101 revisions were due to the new rule that disregards reserves extending beyond 50 years.

• Total gross proved reserves declined 13.6% compared to last year. Positive reserve additions from acquisitions and development were not sufficient to offset the negative effects of NI 51-101.

• Enerplus had negative reserve revisions on a proved basis of 10.7% or 31.0 million BOE.    Positive reserve revisions of 10.9 million BOE from development activities were overshadowed by 41.9 million BOE in negative revisions associated with NI 51-101.

• Enerplus' Reserve Life Index ("RLI") continued to be one of the longest in the sector at 10.1 years on a proved basis and 13.3 years on a proved plus probable basis.

• On April 23, 2003, the Fund internalized its management contract by acquiring the management company from El Paso Corporation for $55.1 million.

• Operating costs increased 14.8% in 2003 to $6.73/BOE as a result of increased costs for labour, utilities and supplies along with an overall increase due to activity levels within the oil and gas industry.

• We chose to adopt the accounting standard for stock based compensation and recorded a non-cash charge of $1.4 million to general and administrative expenses.

• We completed two equity offerings in 2003, issuing 9.3 million trust units for gross proceeds of $307.8 million ($291.8 million net of costs).

• On October 1, 2003 we issued US$54 million of senior unsecured notes with a 12-year amortizing term and a coupon rate of 5.46% representing a rate that was 1% higher than the 10-year U.S. treasury bond rate at the time.

• On January 7, 2004 we closed the acquisition of Ice Energy Limited ("Ice Energy") for total consideration of approximately $132.2 million.  

• We continue to maintain a conservative balance sheet as evidenced by a trailing net debt-to-funds flow ratio of 0.6x.

Results of Operations

Production

Daily production during 2003 averaged 69,414 BOE/day, an 11% increase over average production volumes of 62,784 BOE/day for 2002.   This increase is primarily due to the acquisitions of Celsius Energy Resources Ltd. ("Celsius"), which closed October 21, 2002, and PCC Energy Inc. and PCC Energy Corp. (collectively "PCC"), which closed March 5, 2003.

Enerplus' production is widely distributed across more than 300 producing areas in Alberta, Saskatchewan and British Columbia.   No single area accounts for more than 5% of total production. This diverse production base helps to reduce operating risks and provide more stable distributions over time.

Average production volumes for the years ended December 31, 2003 and 2002 are outlined below:

Enerplus' exit production for the month of December 2003 averaged 69,300 BOE/day.   This rate does not include production from the acquisition of Ice Energy, which closed January 7, 2004.   Ice Energy produced approximately 2,300 BOE/day at that time.

Our current 2004 production is weighted 62% natural gas, 32% crude oil, and 6% natural gas liquids.   We expect production for 2004 will average approximately 68,300 BOE/day.   This estimate incorporates the Ice Energy acquisition, as well as production declines and forecast development capital expenditures throughout 2004, but is before the effects of any future acquisitions or dispositions.

Pricing and Price Risk Management

Our earnings, cash flow and financial condition are dependent on the prices we receive for our natural gas and crude oil production.   Natural gas and crude oil prices have fluctuated widely during recent years.

The following table compares the Fund's average selling prices for 2003 with those of 2002.   It also compares the benchmark price indices for the same periods.

At the outset of 2003, the AECO benchmark natural gas price was $6.46/Mcf.   After an early start to winter and heavy draws on storage, prices increased to $10.14/Mcf in March.   Gas prices fell back to $7.00/Mcf in the second quarter and remained above $6.00/Mcf for the balance of the summer.   These strong summer prices were supported by concerns that storage could not be adequately filled for winter.   By September, these concerns subsided and prices declined slightly to approximately $5.60/Mcf for the fourth quarter.   Overall, AECO gas prices were 65% higher in 2003 compared to 2002.   

As indicated by the current market for future prices (the "forward market"), AECO natural gas prices are expected to average $6.50/Mcf for 2004.   Concerns remain that North American gas production may not keep pace with demand.   The tight balance between supply and demand is expected to create volatility whenever there are unexpected changes to weather, storage or economic activity.

The crude oil benchmark West Texas Intermediate ("WTI") price entered 2003 at US$32.70/bbl.   Hostilities in Iraq and cold winter weather pushed the price to levels as high as $36.00/bbl for the first quarter.   Oil prices declined rapidly to the $28.00 to $30.00 range upon the resolution of the war in the second quarter.   Despite earlier speculation of a further price collapse following the war, crude oil prices held these levels throughout the remainder of 2003.   Iraq production was not restored as rapidly as expected, and crude and refined product inventories remained below normal levels.   There were only three months in 2003 that the WTI crude oil price averaged less than US$30.00/bbl.    Overall, WTI prices were 19% higher in 2003 compared to 2002.

The forward market currently predicts crude oil prices to average US$33.50/bbl for 2004. Increasing demand from China, Nigerian unrest, problems in Venezuela and OPEC talk of quota reductions are keeping upward pressure on the price of oil.   Production is increasing from non-OPEC sources such as the former Soviet Union and offshore Africa, however the production response has not been enough to replenish inventory levels.

Unfortunately, the strengthening Canadian dollar against the U.S. dollar reduced prices received for the Fund's crude oil and a portion of its natural gas.    Most of Canada's crude oil and natural gas is exported to the U.S. and is priced with reference to the U.S. dollar denominated benchmarks.   The CDN$/US$ exchange rate entered 2003 at $0.65 and averaged $0.66 in the first quarter.   After April, the Canadian dollar began to strengthen against its U.S. counterpart, mirroring the performance of the Euro and many other world currencies.   By December the Canadian dollar was averaging $0.76.   The U.S. faced challenges related to its weakening economy, high government debt and ongoing issues with respect to terrorism.   Higher interest rates in Canada relative to the U.S. increased demand for the Canadian dollar.   Overall, the Canadian dollar increased 13% in 2003.   Although the WTI crude oil price increased 19% in 2003, the Canadian dollar equivalent price received by the Fund, after adjusting for the exchange rate, increased only 6%.

The current forward market predicts a CDN$/US$ exchange rate of $0.75 for 2004.   Recent signs of economic strength in the U.S. and signs of economic weakness north of the border have stalled the rally in the Canadian dollar.

Enerplus maintains a commodity price risk management program.   It is designed to provide price protection on a portion of our future production.   Typically, a portion of the pricing upside is surrendered in return for protection against a significant downturn in prices.   The program is intended to provide a measure of stability to our cash distributions and support towards realizing positive economic returns from our capital development and acquisition activities.   We plan to continue this program in 2004.   At the current time we do not have any CDN$/US$ exchange rate hedges associated with our revenues.   However, we may consider hedging a portion of our foreign exchange exposure in the future.  

As energy prices exceeded some of our hedged prices during 2003, we realized a cost of $45.8 million compared to an $8.7 million cost in 2002, as outlined below:

Enerplus' commodity risk management positions as at December 31, 2003 are described in Note 8.   The fair value of the financial forward contracts at December 31, 2003 represented unrealized costs of $19.2 million on crude oil and $15.5 million on natural gas with reference to year-end prices and forward markets.

Enerplus has physical and financial contracts in place for the following production volumes:

We also fixed the cost of 5 megawatt hours ("MWh"), representing 30% of the power consumption by our Alberta operated properties at a price of $49.75/MWh for 2004.   The fair value of this instrument at December 31, 2003 reflects an unrealized gain of $0.2 million.

Enerplus' risk management program will reduce, but not eliminate, the effects of changing prices and exchange rates.   Our funds flow remains sensitive to changes as demonstrated by the following table:    

These sensitivities reflect all commodity contracts as described in Note 8.   They apply to commodity prices, production, interest and exchange rates within the context of current market rates.   To the extent the market price of crude oil or natural gas change to levels that are above the ceiling or below the floor price limits set by existing commodity contracts, the above sensitivities will no longer be relevant.

Revenues

Crude oil and natural gas revenues after hedging were $890.0 million for 2003, which represents a 43% increase over revenues of $621.5 million for 2002.   This was a result of higher production volumes and higher commodity prices. The increase was partially reduced by additional hedging costs as shown in the table below:

Royalties

Royalties are paid to various government entities and other land and mineral rights owners.   In 2003 royalties were $190.4 million compared to $131.8 million during 2002.   The increase is due to higher production and commodity prices during 2003.   Royalties, as a percentage of oil and gas sales before hedging, remained relatively constant between 2003 and 2002 at 20% and 21% respectively.   Enerplus expects royalties to remain at approximately 20% in 2004.  

operating expenses

Operating expenses for the year ended December 31, 2003 were $170.5 million or $6.73/BOE compared to $134.4 million or $5.86/BOE in 2002.   Enerplus, along with most of the industry, experienced increased operating costs as a result of high levels of activity.   In particular, we experienced increased costs for labour, utilities and supplies.   As well, additional prior year charges on our partner-operated properties were recorded during the year, most notably during the fourth quarter.   Given the costs experienced during 2003, we expect 2004 operating costs to be approximately $6.75/BOE.

General and Administrative Expenses

General and administrative ("G&A") expenses were $25.4 million or $1.00/BOE for the year ended December 31, 2003 compared to $16.0 million or $0.70/BOE for 2002.   Compensation costs that included performance bonuses, an executive retention plan and the expensing of unit rights increased costs during 2003 compared to 2002.   A portion of these costs arose as a result of the internalization of the management contract.

Included in compensation costs is $1.6 million related to a long-term executive incentive and retention plan called the Full Value Unit Plan ("FVUP").   The FVUP is based on the Fund's relative performance and total return over a three-year period compared to other senior conventional oil and gas trusts.   The current performance periods of the plan end December 31, 2004 and December 31, 2005.   No actual payments are required until one year after the performance periods.

We adopted the Canadian Institute of Chartered Accountants ("CICA") standard for expensing stock based compensation during 2003, and recorded a non-cash charge of $1.4 million or $0.05/BOE to G&A with respect to our trust unit rights incentive plan. This non-cash charge is based on the excess of the trust unit price over the exercise price of the rights at December 31, 2003 for rights granted in 2003 amortized over the vesting period.   The trust unit price at December 31, 2003 was $39.35. Adoption of this standard had a negligible impact on net income and net income per unit in the previous three quarters.

The following table summarizes the cash and non-cash expenses recorded in G&A:

Pursuant to the full cost accounting guideline, we also capitalized $11.8 million of G&A costs in 2003 compared to $9.1 million in 2002. The majority of these capitalized costs represent charges for staff involved in development and acquisition activities.

Enerplus expects total G&A costs to be approximately $1.15/BOE during 2004.    The forecasted increase reflects rising costs that are a result of high levels of industry activity and the increasing cost of compliance with recent regulatory requirements arising from the Sarbanes-Oxley Act and similar legislation in Canada.   It also reflects increased staff levels and the recruitment of more specialized technical staff.   This estimate assumes that non-cash charges for the trust unit rights plan will be similar to those experienced during 2003.   The actual expense with respect to the trust unit rights plan and the FVUP in 2004 will be dependent on the performance of the Fund and the trust unit price throughout the year.

Management Fees and Internalization expense

Effective April 23, 2003, all external management fees were eliminated with the purchase of Enerplus Global Energy Management Company ("EGEM") from an indirect subsidiary of El Paso Corporation ("El Paso").   Under the terms of the transaction, El Paso agreed to fix the management fees for the period January 1, 2003 to April 23, 2003 at an amount of $3.2 million.   In addition, the amount recorded as management fee expense was reduced by $0.2 million to reflect the amortization of the note payable to EGEM as more fully described in Note 6.

We expensed all of the costs associated with the management internalization totaling $55.1 million during the second quarter of 2003.   This treatment is in accordance with Emerging Issues Committee Abstract 138, " Internalization of the Management Function in Royalty and Income Trusts ", issued by the CICA.

Had we not completed this transaction, the management fees for 2003 would have been approximately $29.7 million.   As a result, the internalization transaction represents an attractive pay-out of less than two years.   Going forward, there will be no management or performance fees payable.

Interest Expense

Interest expense increased to $19.7 million in 2003 from $18.1 million in 2002.   Higher average debt outstanding combined with higher average interest rates during 2003 resulted in the increase over 2002.    At December 31, 2003, 43% of Enerplus' debt was based on fixed interest rates while 57% was floating.   These instruments are more fully described in Note 3 and Note 8.   During 2004 we anticipate interest rates to remain consistent with rates experienced during 2003.

Foreign exchange

Enerplus incurred a $0.9 million foreign exchange gain in 2003 compared to a $0.2 million loss in 2002.   The foreign exchange gain resulted primarily from translation of the US$54 million senior unsecured notes to the exchange rate in effect at December 31, 2003.   This unrealized gain was partially offset by realized exchange losses on day-to-day transactions denominated in U.S. dollars.   See Note 9.

Depletion, depreciation and amortization

Depletion, depreciation and amortization ("DD&A") of property, plant and equipment is recognized using the unit-of-production method based on proved reserves calculated in accordance with NI 51-101.   Future costs for restoration and abandonment of well sites and facilities are estimated and amortized over the life of the properties on a unit-of-production basis as part of depletion, depreciation and amortization expense.

DD&A increased to $244.9 million or $9.67/BOE in 2003 from $213.9 million or $9.33/BOE in 2002. Higher production volumes during 2003 as well as revisions to reserves resulting from NI 51-101 have increased the total amount of DD&A expense.   Proved reserves decreased approximately 13.6% under NI 51-101.

The Fund has prospectively adopted CICA Accounting Guideline 16 "Oil and gas accounting - full cost."   Pursuant to the guideline, the Fund places a limit on the aggregate carrying value of property, plant and equipment (the "impairment test").   An impairment loss exists when the carrying amount of the Fund's property, plant and equipment exceeds the estimated un-discounted future net cash flows associated with the Fund's proved reserves.   If an impairment loss is determined to exist, the costs carried on the balance sheet in excess of the discounted future net cash flows associated with the Fund's proved and probable reserves are charged to income.

No impairment existed at December 31, 2003 or January 1, 2003 using reserves determined under NI 51-101 and management's estimates of future prices.   No impairment existed during 2002 under the previous Accounting Guideline 5.   Our future price estimates are more fully discussed in Note 2.

Taxes

Capital taxes, consisting of the Federal Large Corporations Tax and the Saskatchewan Resource Surcharge, increased to $6.2 million in 2003 compared to $5.5 million in 2002.   Commencing in 2004, the Federal Large Corporations Tax will be eliminated over the next five years, as a result of legislative changes.   Given our current capital structure, capital taxes are expected to be $7.0 million in 2004.

Future income taxes arise from differences between the accounting and tax bases of the operating companies' assets and liabilities. In the Fund's structure, payments are made between the operating companies and the Fund, ultimately transferring both income and future income tax liability to the unitholders.   Therefore, it is our opinion that no cash income taxes are expected to be paid by the operating companies in the future, and as such, the future income tax liability recorded on the balance sheet will be recovered through earnings over time.

For the year ended December 31, 2003, a future income tax recovery of $73.0 million was recorded in income compared to $35.4 million in 2002.   The increased recovery in 2003 was mainly the result of legislative changes to reduce future income tax rates.   Our expected future income tax rate incorporating these changes is approximately 35% compared to 42% at December 31, 2002.   Of the $73.0 million recovery, $35.8 million was attributed to the reduction in the future tax rate.       

Annual Netbacks

Net Income and Funds Flow From Operations

Higher production volumes and more favourable commodity prices helped to increase oil and natural gas sales and net income for 2003 compared to 2002.   These increases were somewhat offset by the one time management internalization costs of $55.1 million.   The following table summarizes net income, funds flow from operations and other key measures for the last three years.

Quarterly Financial Information

Revenues, including the effects of hedging and the strengthening Canadian dollar, decreased each quarter in 2003 due to the gradual decline of realized prices on oil and gas sales.   Net income for the fourth quarter of 2003 was negatively impacted as realized commodity prices were comparatively lower and additional operating and G&A costs were recorded.

Summary Fourth Quarter Information

Average daily production for the fourth quarter of 2003 was 69,841 BOE/day, an increase of 5% from the same period in 2002 due to the acquisition of PCC and a successful capital expenditure program.   Operating expenses increased to $51.3 million or $7.98/BOE during the fourth quarter primarily due to prior year charges on partner operated properties.   G&A expenses were $8.0 million or $1.25/BOE for the fourth quarter as charges for unit based compensation with respect to our trust unit rights incentive plan and additional performance based compensation costs were recorded.

Cash Available for distribution

We make monthly cash distributions to our unitholders based upon the net cash flow from our oil and gas operations. A portion of this cash flow is typically withheld to fund a portion of our acquisition and development activities. For the year ended December 31, 2003, we generated $413.2 million in funds flow from operations. Of this amount (together with certain funds described in the following table), $ 379.1 million ($4.32 per trust unit) was paid to unitholders and $34.1 million ($0.39 per trust unit) was retained.

We monitor the distribution payout policy with respect to forecasted cash flows, debt levels and spending plans. The level of cash retained typically varies between 10% and 25% of annual cash flow, however we are prepared to adjust the payout levels in an effort to balance the investor's desire for distributions with the Fund's requirement to maintain a prudent capital structure.

The following table reconciles Enerplus' funds flow from operations with the cash available for distribution to unitholders.

Note A:      According to the previous royalty agreement with Enerplus Resources Corporation ("ERC"), the royalty paid to the Fund was calculated on a cash basis. As a consequence, the change in the accrued net revenues of ERC for 2002 were added back to funds flow from operations for purposes of this reconciliation.   Subsequent to December 31, 2002 the Fund amended the royalty agreement with ERC to allow for the royalty to be paid on an accrued basis.

Note B:       The Consolidated Statement of Cash Flows reflects cash payments to unitholders during the calendar year.   The cash available for distribution of $379.1 million in 2003 can be reconciled

to the cash paid to unitholders of $372.6 million in the Consolidated Statement of Cash Flows by subtracting the February 2004 payments to unitholders and adding the February 2003 payments to unitholders.

Capital Expenditures

Enerplus spent $ 312.1 million on capital expenditures and acquisitions net of divestitures in 2003 compared to $361.7 million in 2002.   Enerplus financed its capital expenditures through bank borrowing, new equity issues and by withholding a portion of cash otherwise available for distribution.

As discussed in Note 7, our most significant acquisition during 2003 was PCC for $166.9 million.   In addition, we purchased oil and gas properties at Joarcam, Hanna and Freda Lake for $58.4 million

Total capital expenditures in 2004, including directly related administrative costs, are expected to be approximately $170 million.   Of this amount, we expect to spend about $150 million on oil and natural gas drilling, facilities and development activities.   This includes approximately $110 million for natural gas development most notably at Hanna Garden, Bantry, Shackleton, Verger, Medicine Hat and Deep Basin.   In addition, we plan to initiate our natural gas from coal development opportunities at Joffre and Trochu.   Oil development costs are expected to be approximately $30 million for 2004.   The majority of these funds will be used to expand our facilities at Giltedge, Joarcam and Medicine Hat. We also plan to spend approximately $6 million to further develop our pilot project at Oil Sands Lease #24.   Finally, land and seismic expenditures are expected to be approximately $4 million .

Enerplus routinely evaluates its property portfolio and disposes of non-core properties with limited contribution to cash flow or upside development potential. In 2003, we sold $73.2 million worth of non-core properties representing production of approximately 3,003 BOE/day. We expect to continue the process of acquiring new properties and rationalizing marginal properties in 2004.

Liquidity and Capital Resources

Long-term debt at December 31, 2003 was $338.1 million, representing $69.8 million and $268.3 million of Canadian dollar equivalent debt related to the US$54 million and US$175 million s enior unsecured notes, respectively .   Offsetting this debt was cash of $80.4 million, as the proceeds from the December equity issue were not fully deployed until Ice Energy was acquired on January 7, 2004.   At December 31, 2003 long-term debt net of cash was $257.7 million.   After giving effect to the Ice Energy acquisition, total debt outstanding was $389.9 million.

We have a conservative balance sheet as demonstrated below:

Long-term debt is measured net of cash.

We use EBITDA to determine the ability of the Fund to generate cash from operations. It is calculated from the consolidated statement of income as revenue less operating expenses, general and administrative expenses, management fees and internalization costs.   This measure does not have any standardized meaning as prescribed by GAAP and may not be comparable to similar measures presented by other entities.

At year end, Enerplus' total borrowing base limit was $850 million consisting of senior unsecured notes of $341.1 million and bank facilities of $508.9 million.   The bank facilities consist of a demand operating line of $31.7 million and a $477.2 million, 364 day revolving committed facility.   We had $508.9 million of available borrowing capacity, and an additional $80.4 million in cash at year-end.   After giving effect to the acquisition of Ice Energy on January 7, 2004 we had $457.1 million of available borrowing capacity.

In the event that the revolving bank line is not extended at the end of the 364-day revolving period, no principal payments are required during the first year of the term period. However, we would be required to maintain certain mini

mum balances on deposit with the syndicate agent.   Principal payments on Enerplus' senior unsecured notes are required commencing in 2010 and 2011 and are more fully discussed in Note 3.

Payments with respect to the bank facilities, senior unsecured notes, and other third party debt have priority over claims of and future distributions to the unitholders.   Unitholders have no direct liability should cash flow be insufficient to repay this indebtedness.   The agreements governing these bank facilities and senior unsecured notes stipulate that if we exceed certain borrowing thresholds, default, or fail to comply with certain covenants, the ability of the operating companies to make payments to the Fund and consequently the Fund's ability to make distributions to the unitholders may be restricted.  

Our borrowing base is determined by the lenders' evaluation of the value of our proved oil and natural gas reserves.   The lenders have reserved the right to revise the commitment based on an annual independent assessment of the Fund's year end reserve information and the lenders' commodity price outlook.   Should the borrowing base be reduced below current outstanding debt levels, the Fund may need to obtain alternative financing, reduce distributions to unitholders, or dispose of properties.

We anticipate that we will continue to have adequate liquidity to fund future working capital and planned capital expenditures during 2004 through a combination of cash flow from operations and debt.   Most of Enerplus' $170.0 million capital budget for 2004 is discretionary and can be revised downwards in the event of a significant commodity price downturn or similar economic event.   We have historically demonstrated our ability to finance acquisitions and other future commitments through our debt facilities, distribution reinvestment plan and equity offerings.

Commitments

We have contracted to transport natural gas with various pipelines totaling 15 MMcf per day until 2008 and a further 5 MMcf per day until 2015.   These transportation contracts will cost approximately $5.6 million in 2004.

Enerplus has an office lease commitment that extends to November 30, 2009.   Annual costs of this lease commitment, which include rent and operating fees, amount to approximately $4.4 million. The Fund's commitments, contingencies, and guarantees are more fully described in Note 10.

We must continue to pay Crown royalties, surface rentals, mineral taxes and abandonment and reclamation costs with respect to our ongoing ownership of hydrocarbon production rights.   The amounts paid with respect to these burdens will depend on the future ownership, production, prices and legislative environment at the time.

Reserves producing approximately 33% of our current production are dedicated to certain aggregator sales arrangements.   Under these arrangements, we receive a price based on the average netback price of the pool, net of transportation costs incurred by the aggregator for the life of the reserves.

Enerplus has the following minimum annual commitments including long-term debt:

Trust Unit Information

We had 94,349,000 trust units outstanding at December 31, 2003 compared to 82,898,000 trust units at December 31, 2002, reflecting the two equity offerings completed during the year.   The weighted average basic number of trust units outstanding during 2003 was 86,202,000 (2002 - 71,946,000).  

In addition to the equity offerings during 2003, 1,515,000 trust units (2002 - 626,000) were issued pursuant to the Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan ("DRIP") and the trust unit options and rights plans.   This resulted in $40.4 million (2002 - $15.1 million) of additional equity to the Fund.   A total of 660,000 units with a value of $21.4 million were issued to acquire corporate and property interests during 2003 compared to 31,000 units with a value of $0.7 million issued during 2002.

Income Taxes

The following sets out a general discussion of the Canadian and U.S. tax consequences of holding Enerplus trust units as capital property. The summary is not exhaustive in nature and is not intended to provide legal or tax advice. Investors or potential unitholders should consult their own legal or tax advisors as to their particular tax consequences.

Canadian Taxpayers

The Fund qualifies as a mutual fund trust under the Income Tax Act (Canada) and accordingly, trust units of the Fund are qualified investments for RRSPs, RRIFs, RESPs, and DPSPs. Each year, the Fund is required to file an income tax return and any taxable income in the Fund is allocated to the unitholders.

In computing income, unitholders are required to include their pro-rata share of any taxable income earned by the Fund in that year. An investor's adjusted cost base ("ACB") in a trust unit equals the purchase price of the trust unit less any non-taxable cash distributions received from the date of acquisition. To the extent a unitholder's ACB is reduced below zero, such amount will be deemed to be a capital gain to the unitholder and the unitholder's ACB will be brought to $nil.

We paid $4.29 per trust unit in cash distributions to unitholders during the period February 2003 to January 2004. For Canadian tax purposes, 18% of these distributions, or $0.76 per trust unit was a tax deferred return of capital, 81% or $3.46 per trust unit was taxable to unitholders as other income, and 1% or $0.07 per trust unit was taxable dividend income.

For 2004, we estimate that 85% of cash distributions may be taxable and 15% may be a tax deferred return of capital.   Actual taxable amounts may vary depending on actual distributions which are dependant upon production, commodity prices and funds flow experienced throughout the year.  

U.S. Taxpayers

U.S. unitholders who receive cash distributions are subject to a 15% Canadian withholding tax, applied to the taxable portion of the distribution as computed under Canadian tax law. U.S. taxpayers may be eligible for a foreign tax credit with respect to Canadian withholding taxes paid.

The taxable portion of the cash distribution for U.S. tax purposes is determined by Enerplus in relation to its current and accumulated earnings and profits using U.S. income tax principles. The taxable portion determined is considered to be a dividend for U.S. tax purposes.   For most U.S. taxpayers, this should be a "Qualified Dividend" eligible for the reduced tax rate.   We believe Enerplus should not be classified as a Passive Foreign Investment Company for U.S. income tax purposes for 2002 and 2003.  

The non-taxable portion of the cash distribution is a return of the cost (or other basis). The cost (or other basis) is reduced by this amount for computing any gain or loss arising from disposition. However, if the full amount of the cost (or other basis) has been recovered, any further non-taxable distributions should be reported as gains.

We paid US$3.04 per trust unit to U.S. residents during the 2003 calendar year, of which 13% or US$0.38 per trust unit was a tax deferred return of capital and 87% or US$2.66 per unit was a taxable dividend.

For 2004, we estimate that 85% of cash distributions may be taxable and 15% may be a tax deferred return of capital. Actual taxable amounts may vary depending on actual distributions which are dependant upon production, commodity prices and funds flow experienced throughout the year.  

Critical accounting policies

The financial statements have been prepared in accordance with GAAP.   A summary of significant accounting policies is presented in Note 1.   A reconciliation of differences between Canadian and United States GAAP is presented in Note 12.   Most accounting policies are mandated under GAAP and we do not have the ability to select alternatives.   However, in accounting for oil and gas activities, we have a choice between two acceptable accounting policies: the full cost and the successful effort methods of accounting.

The Fund follows the full cost method of accounting for oil and natural gas activities.   Using the full cost method of accounting, all costs of acquiring, exploring and developing oil and natural gas properties are capitalized, including unsuccessful drilling costs and administrative costs associated with acquisitions and development.   Under the successful efforts method of accounting, all exploration costs, except costs associated with drilling successful exploration wells, are expensed in the period in which they are incurred. The difference between these two methodologies is not expected to be significant to the Fund's net income or net income per unit as the Fund participates in low risk development drilling that has traditionally achieved high success rates.

Under the Fund's full cost method of accounting, an impairment test is applied to the overall carrying value of property, plant and equipment, for a Canada-wide cost centre with the reserves valued using estimated future commodity prices at period end.   Under the successful efforts method of accounting, the costs are aggregated on a property by property basis.   The carrying value of each property is subject to an impairment test.   Each policy may generate a different carrying value of property, plant and equipment and a different net income depending on the circumstances at period end.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with GAAP requires management to make certain judgements and estimates.   Changes in these judgements and estimates could have a material impact on our financial results and financial condition.   The process of estimating reserves is critical to several accounting estimates.   It requires significant judgements based on available geological, geophysical, engineering and economic data.   These estimates may change substantially as data from ongoing development and production activities becomes available, and as economic conditions impacting oil and gas prices, operating costs and royalty burdens change.   Reserve estimates impact net income through depletion, the determination of future site restoration and the application of an impairment test.   The reserve estimates are also used to assess the borrowing base for the Fund's credit facilities.   Revisions or changes in the reserve estimates can have either a positive or a negative impact on net income or the borrowing base.

Management's estimates of oil and natural gas prices in determining future cash flows are also critical as these prices are used in the cost centre impairment test.   The carrying amount of property, plant and equipment as well as amounts recorded for depletion can be affected by the future price estimates.   

RECENT CANADIAN ACCOUNTING and related PRONOUNCEMENTS

Standards of Disclosure for Oil and Gas Activities

Effective September 30, 2003, the Alberta Securities Commission implemented NI 51-101, "Standards of Disclosure for Oil and Gas Activities".     NI 51-101 is effective for fiscal years that include or end December 31, 2003.   The instrument imposes more standardized and more conservative guidelines for reserve estimates.   Definitions for disclosure of reserves, net asset value, netbacks and finding and development costs are also provided in the instrument.   We have adopted NI 51-101 at December 31, 2003, and as a result have realized a decrease in proved reserves and a minimal impact on proved plus probable reserves.   Depletion expense increased for the year due to lower proved reserves, however there was no impact from the impairment test.

Continuous Disclosure Obligations

The Ontario Securities Commission has issued National Instrument 51-102 ("NI 51-102"), "Continuous Disclosure Obligations", effective for interim MD&A disclosures for the first quarter ending March 31, 2004.   The instrument outlines enhanced requirements for disclosure in annual and interim financial statements, MD&A and Annual Information Form ("AIF").   The instrument also proposes shorter reporting deadlines for annual and interim financial statements, MD&A and AIF.   We have substantially adopted NI 51-102 for the year ended December 31, 2003.

Full Cost Accounting Guideline

The Canadian Institute of Chartered Accountants ("CICA") issued Accounting Guideline 16, "Full Cost Accounting" for years beginning on or after January 1, 2004.   The new guideline updates reserve definitions to include the standards of NI 51-101, sets criteria for accounting for disposals of properties and defines the method to be used to deplete and depreciate capitalized costs.   The guideline also sets standards for presentation and disclosure under full-cost accounting.   We have chosen early adoption of this guideline, prospectively, for the year ended December 31, 2003 to reflect the changes to oil and gas reserve measurement that have resulted from NI 51-101.   Adoption of the guideline has not materially affected the Fund.

Unit Based Compensation

In September 2003, the CICA amended Handbook section 3870, "Stock Based Compensation and Other Stock Based Payments".   The amendment requires that companies recognize an expense in the financial statements for stock based payments based on the fair value method beginning January 1, 2004.   We have prospectively adopted this standard for the year ended December 31, 2003 in accordance with early adoption provisions.   Enerplus used the intrinsic method to calculate this expense as certain features of the trust unit rights incentive plan prevented the use of traditional option pricing models.   The trust unit rights incentive plan is described more completely in Note 1 and Note 3.   Pursuant to the early adoption provisions, we were required to calculate and record an expense for any rights issued on or after January 1, 2003.   The net income of the Fund decreased by $1.4 million as a result of adopting this standard.

Disclosure of Guarantees

The CICA issued Accounting Guideline 14, "Disclosure of Guarantees" in February 2003.   This guideline requires disclosure of all guarantees, their fair value and a description of their nature in the notes to the financial statements.   The new guideline is effective for fiscal years beginning on or after January 1, 2003.   Adoption did not affect the financial results of the Fund for 2003 .  

Hedging Relationships

In November 2002, the CICA published an amended Accounting Guideline 13, "Hedging Relationships". The guideline establishes conditions where hedge accounting may be applied.   It is effective for years beginning on or after July 1, 2003.   The guideline will have an impact to the Fund's net income and net income per trust unit, as the 3-way option contracts for oil and natural gas as described in Note 7 will not qualify for hedge accounting.   Where hedge accounting does not apply, any changes in the fair values of the option contracts relating to a period can either reduce or increase net income for that period.   We expect to adopt this standard January 1, 2004.   Had this standard been adopted for our 2003 fiscal year the impact would have reduced our net earnings by $1.5 million.

Asset Retirement Obligations

In December 2002, the CICA issued Handbook Section 3110, "Asset Retirement Obligations".   This standard requires recognition of a liability representing the fair value of the future retirement obligations associated with property, plant and equipment. This fair value is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The standard is effective for all fiscal years beginning on or after January 1, 2004.   We will adopt the standard January 1, 2004. Had this standard been adopted for our 2003 fiscal year the impact would have increased our net earnings by $0.7 million. Other accounting standards issued by the CICA during the year ended December 31, 2003 are not expected to materially impact the Fund.

Risk Factors and risk management

Enerplus investors are participating in the net cash flow from a portfolio of western Canadian crude oil and natural gas producing properties. As such, the cash flow paid to investors and the value of Enerplus units are subject to numerous risk factors. These risk factors, many of which are associated with the oil and gas industry, include, but are not limited to, the following influences:

Commodity Price Risk

Enerplus' operating results and financial condition are dependent on the prices that it receives for its crude oil and natural gas production.    These prices may fluctuate widely in response to a variety of factors including global and domestic economic conditions, weather conditions, the supply and price of imported oil and liquefied natural gas, the production and storage levels of North American natural gas, political stability, transportation facilities, the price and availability of alternative fuels and government regulations.

We use financial derivative instruments and other hedging mechanisms to help limit the adverse effects of natural gas and oil price volatility.   However, we do not hedge all of our production, and expect there will always be a portion that remains unhedged.   Furthermore, we use financial instruments such as collars and three-way options that offer only limited protection within selected price ranges. To the extent price exposure is hedged, we may forego the benefits that would otherwise be experienced if commodity prices increase.

Operational Risk and Cost Control

The value of Enerplus trust units is based on the underlying value of the oil and gas reserves. Geological and operational risks can affect the quantity and quality of reserves and the cost of ultimately recovering those reserves. Lower oil and natural gas prices may increase the risk of write-downs of our oil and gas property investments.   As activity levels in the industry increase, upward pressure is placed on administrative and operating costs.   Higher costs will decrease the amount of cash flow received by the Fund and therefore, reduce distributions to unitholders.

We strive to acquire low risk, mature properties with a high proportion of proven reserves, high cash netbacks, long reserve lives and predictable production. Similarly, we generally participate in lower-risk development projects, while farming out or monetizing higher risk exploratory prospects.

Each year, a firm of independent engineers evaluates a significant portion of our proved and probable reserves. At December 31, 2003 approximately 86% of the reserves, comprised of our larger properties, were evaluated.   The remaining minor properties were evaluated internally and reviewed by the independent engineers.   The Reserves Committee of the Board of Directors has reviewed and approved the reserve report of the independent evaluators.

We strive to control costs through incentive-based compensation plans that reward employees for cost control and value-added initiatives.   We attempt to minimize costs by exploiting our purchasing strength with suppliers.    In 2004, Enerplus fixed the price on a portion of its Alberta electrical consumption.   We use detailed budgeting and accounting practices to monitor costs.   Multi-functional teams regularly perform integrated field reviews designed to reduce costs and increase revenues from our properties.

Despite these efforts, it can be difficult to control costs in the oil and gas industry, especially in periods of high commodity prices when the demand for goods and services is strong.    Oil and gas production involves a significant amount of fixed costs that are difficult to reduce without decreasing production.    In addition, approximately 40% of Enerplus' production is operated by third parties.   We have limited ability to influence costs on partner-operated properties.

Reserve Risk

Oil and natural gas reserves naturally deplete as they are produced over time. Our ability to replace production depends on our success in acquiring new reserves and developing existing reserves. Acquisitions of oil and gas assets depend on Enerplus' assessment of value at the time of acquisition. Incorrect assessments of value can adversely affect distributions to unitholders and the value of the trust units.   

Acquisitions are subject to investment guidelines, due diligence and review.   Major acquisitions are approved by the Board of Directors and where appropriate, independent reservoir engineer evaluations are obtained.   Enerplus has a diversified asset base that helps to limit the potential for a significant negative event.

Access to Capital Markets

Since Enerplus distributes the majority of its net cash flow to unitholders, we must finance a large portion of our acquisition and development activity through continued access to the equity and debt capital markets. As such, we are dependent on continued access to the capital markets to fund our activities directed towards maintaining and increasing value for our unitholders.

Enerplus has listings on the Toronto and New York stock exchanges and maintains an active investor relations program.

We maintain a prudent capital structure by retaining a portion of cash flow for capital spending and utilizing the equity markets when deemed appropriate.

Continued access to capital is dependant on our ability to maintain our track record of performance and to demonstrate the advantages of the acquisition or development program that we are financing at the time.

Non-Resident Ownership and Mutual Fund Trust Status

Since our listing on the New York Stock Exchange in November of 2000, we have seen increased trading volumes and levels of ownership by non-residents of Canada.   Based on information received from our transfer agent and financial intermediaries in February 2004, an estimated 64% of outstanding trust units are held by non-residents.   However, this estimate may not be accurate as it is based on certain assumptions and data from the security industry that does not have a well-defined methodology to determine the residency of beneficial holders of securities.

As a result of the current structure and assets of the Fund, Enerplus meets the requirements of an exception in the Income Tax Act (Canada) (the "Tax Act"), which would otherwise require a mutual fund trust not to be maintained primarily for the benefit of non-residents of Canada. Our trust indenture does not have a specific limit on the percentage of trust units that may be owned by non-residents.

As with other legislation or regulations affecting the Fund, there can be no assurance that the provisions of the Tax Act will be maintained in their current form, or if changed, how any transitional provisions may affect the Fund.  

At this time, management does not anticipate any legislative changes that would affect our status as a mutual fund trust, however, we have implemented provisions in our trust indenture to allow the Board of Directors to adopt non-resident ownership constraints if required in order to ensure Enerplus maintains its mutual fund trust status.

Environmental and Safety Risk ("E&S")

Environmental, health and safety risks influence our workforce as well as operating and capital costs. In addition, our industry is subject to numerous E&S laws and regulations.

Enerplus mitigates these risks by:

• Developing and adhering to standards, procedures and practices that protect the environment and the health and safety of our employees, contractors and the public, while meeting or exceeding government regulations and requirements.

• Requiring field employees and contractors to attend regular meetings and training programs to review health and safety regulations and workplace standards and procedures.

• Regularly conducting health and safety inspections and audits to ensure hazards are identified and controlled.

• Reviewing all safety incidents in order to prevent reoccurrence and raise safety awareness.

• Conducting environment inspections to ensure environmental liabilities are identified and corrected using Enerplus' well site and facility reclamation and abandonment program.

• Ensuring emergency response plans that meet all regulatory requirements are in place and practiced regularly to prevent and deal with incidents quickly and effectively.

Interest Rate Exposure

The Fund has exposure to movements in interest rates. Changing interest rates can affect borrowing costs and the trust unit price of yield-based investments such as Enerplus.

We monitor the interest rate forward market and have fixed the interest rate on approximately 43% of our debt through fixed rate senior unsecured notes and through interest rate swaps for terms of up to 3 years.

Enerplus has exposure to fluctuations in foreign currency as a result of the issuance of senior unsecured notes denominated in US dollars.

We have hedged our foreign currency exposure on US$175 million of senior unsecured notes using financial swaps that convert the US denominated debt to Canadian dollar debt with Canadian dollar interest obligations.   We have not hedged our foreign exchange exposure with respect to the US$54 million of senior unsecured notes issued in October 2003 which have US dollar interest payment obligations.

Enerplus also has indirect exposure to fluctuations in foreign currency as crude oil sales and a portion of natural gas sales are based on US dollar indices.   Our oil and gas revenues benefit from a weak Canadian dollar relative to the US dollar.

We have not entered into any foreign currency hedges with respect to oil and natural gas sales.   However, we are monitoring exchange rates, and may consider entering into hedging arrangements to reduce the impact of volatility in the exchange rate on a portion of our US dollar sales exposure in the future.

Counterparty Risk

We assume customer credit risk associated with oil and gas sales, financial hedging transactions and joint venture participants.

We have established credit policies and controls designed to mitigate the risk of default or nonpayment with respect to oil and gas sales, financial hedging transactions and joint venture participants.   Enerplus maintains a diversified sales customer base and we review our single-entity exposure on a regular basis.

Regulatory Risk

Government royalties, income tax laws, environmental laws and regulatory requirements can have a significant financial and operational impact on Enerplus.   As an oil and gas producer, we are subject to a broad range of regulatory requirements.   Similarly, as a mutual fund trust, Enerplus has a unique structure that is vulnerable to changes in legislation or income tax law.

Although we have no control over these regulatory risks, we continuously monitor changes in these areas through such activities as participating in industry organizations and conferences, exchange of information with third party experts and employing qualified individuals to assess the impact of such changes on the Fund's   financial and operating results.

Unitholder Liability

The law is uncertain on the question of whether unitholders could be held personally liable for the indebtedness of the Fund.   The Ontario government has introduced a bill to provide statutory protection for unitholders similar to the protection afforded shareholders in a corporation.   This legislation has not yet been passed and there is no guarantee the other provincial jurisdictions will enact similar statutory protection.

We mitigate this risk by conducting all of our active business through the Fund's corporate subsidiaries.   We limit the Fund to a narrow range of activities associated with the receipt of net cash flow from these operating corporations.

Business Prospects

Enerplus offers investors the benefits of owning a large, diversified portfolio of oil and natural gas properties without significant exposure to the exploration risks commonly associated with traditional exploration and production ("E&P") companies. As such, our business prospects are closely linked to the opportunities and challenges associated with oil and natural gas production.    In particular, Enerplus is strongly influenced by the price of crude oil and natural gas, both of which have been volatile in recent years.

In 2003, we delivered a 55.4% total return to unitholders through unit appreciation and monthly cash distributions.    Over the last three years, we have delivered a 43.5% total return to our unitholders.   Looking forward to 2004, our business plan features some of the same strategies that have supported our 18-year track record of success:

Growth

• replace production through a disciplined acquisitions strategy;

• focus on acquisitions where Enerplus has a competitive advantage;

• focus on larger acquisitions to avoid the competition for smaller packages;

• acquire properties with predictable production profiles, long reserve lives, high cash netbacks and opportunities for low risk development;

• consider diversification into other energy-related investments such as processing facilities;

• maintain a portfolio of future development opportunities within existing properties;

• maintain a work environment that attracts and retains qualified professionals;

Portfolio Optimization

• develop core competencies and focus our asset base where we have a competitive technical or operating advantage;

• utilize technologies and expertise to optimize the performance of existing properties through low-risk development, production enhancements and cost management;

• dispose of marginal non-core properties at attractive valuations;

Risk Management

• hedge oil and natural gas prices on a portion of future production to provide protection in the event of adverse price movements;

• hedge a portion of future electrical costs;

• focus on low-risk development;           

Corporate Governance

• apply high standards of corporate governance and ethics;

• apply standards and practices that protect the environment and the health and safety of our employees.

Financing

• utilize debt conservatively;

• diversify credit sources and payment terms;

• hedge interest rates associated with a portion of long-term debt;

• withhold 10% to 25% of cash flow from operations to contribute towards annual development expenditures;

• issue equity for acquisitions and growth opportunities in a manner that adds value to existing unitholders.

Summary 2004 Outlook

In recent years, our unitholders have enjoyed the benefits of a number of positive macro-economic trends, including:

• increasing prices for crude oil and natural gas;

• low interest rates fueling a demand for yield-based investments;

• an active acquisition market for oil & gas properties;

• a structural advantage when competing with E&P companies for acquisitions; and,

• until recently, a limited number of trusts were competing for these acquisitions.

Enerplus' strategy is to maintain our discipline and flexibility to take advantage of opportunities, even if some of these macro-economic trends temporarily turn negative for the sector.

The following chart summarizes Enerplus' 2004 outlook provided throughout this MD&A.   We do not attempt to forecast commodity prices, and as a result, we do not forecast future cash distributions to unitholders.   Readers are encouraged to apply their own price expectations to the following factors to arrive at an expected cash distribution.

Additional information

Additional information relating to Enerplus Resources Fund, including the Fund's Annual Information Form, is available under the Fund's profile on the SEDAR website at www.sedar.com

Forward-Looking Statements

This discussion and analysis contains forward-looking statements relating to future events or future performance. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expects", "projects", "plans", "anticipates" and similar expressions. These statements represent management's expectations or beliefs concerning, among other things, future operating results and various components thereof or the economic performance of Enerplus. Undue reliance should not be placed on these forward-looking statements which are based upon management's assumptions and are subject to known and unknown risks and uncertainties, including the business risks discussed above, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted. Enerplus undertakes no obligation to update publicly or revise any forward-looking statements contained herein and such statements are expressly qualified by the cautionary statement.