MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")

The following discussion and analysis of financial results is dated February 24, 2005 and is to be read in conjunction with the audited consolidated financial statements as at and for the years ended December 31, 2004 and 2003.   All amounts are stated in Canadian dollars unless otherwise specified.   All note references relate to the notes 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 stated.   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.   Use of BOE in isolation may be misleading.  

Throughout the MD&A, we use the terms 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.   Funds flow is used by management to analyze operating performance, leverage and liquidity.   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.  

2004 Overview

We started 2004 with the acquisition of Ice Energy Limited ("Ice Energy") for $130.5 million in January which secured development opportunities in Saskatchewan and Alberta shallow gas areas.   In June, we completed the single largest acquisition in our 19-year history with the acquisition of certain properties from ChevronTexaco Corporation ("ChevronTexaco") for $467.2 million.   This acquisition added additional shallow gas and crude oil waterflood opportunities to our asset base. Against this backdrop of acquisition activity, we posted a record year for capital expenditures on our existing properties spending $206.8 million on development projects and drilling 367 net wells with a success rate of 99%.

Production increased 8% year-over-year, reflecting the partial-year impact of the acquisitions and the results of our capital program.   Our average selling price per BOE also increased 11% in 2004 on the strength of higher crude oil prices and slightly higher natural gas prices.   The combination of higher production and higher prices helped fuel an increase in revenues. In addition, we experienced an increase in operating costs and general and administrative costs as a result of the higher activity levels and corresponding competitive pressures within the industry for services as well as higher performance based compensation costs.   For 2004, our funds flow from operations increased to $540.0 million from $413.2 million in 2003.   Our payout ratio decreased to 79% as we held distributions per trust unit constant throughout 2004 and chose to reinvest the additional funds flow into acquisitions and capital
development opportunities.

Highlights

•  Our Canadian unitholders realized a 21.5% total return in 2004 (representing the appreciation in unit price plus distributions paid during the year).   This performance placed Enerplus first on a three-year rolling basis for the third year in a row in a peer group of the eight largest conventional oil and gas trusts.

•  Our U.S. unitholders realized a 29.9% total return in 2004, as the appreciation in the Canadian dollar effectively increased distributions and the unit price when exchanged into U.S. dollars.  

•  Funds flow from operations, driven by strong oil and natural gas prices and higher production, increased 31% to $540.0 million and 14% per trust unit to $5.44 per trust unit.

•  We paid $426.7 million to unitholders ($4.20 per trust unit) and retained $113.3 million ($1.11 per trust unit) for capital development opportunities.   This represented a payout ratio of 79%.

•  Our average annual production volumes of 75,130 BOE/day exceeded our production target for 2004 of 74,000 BOE/day, and set a new record of annual production for the Fund.

•  On January 7, 2004 we closed the acquisition of Ice Energy for total consideration of $130.5 million.  

•  On June 30, 2004 we completed the acquisition of properties from ChevronTexaco for total consideration of $467.2 million, which added 33.4 million BOE of proved plus probable reserves and approximately 11,500 BOE/day of production.

•  In connection with the ChevronTexaco acquisition we completed an equity offering, issuing 8.8 million trust units for gross proceeds of $301.8 million ($286.2 million net of costs).

•  Net income was slightly higher than the prior year, however on a trust unit basis it decreased 10% as a result of our equity issue that increased the number of units outstanding.

•  Enerplus continued its active development program, investing $206.8 million in development drilling and facility enhancements.   In 2004 we participated in 367 net wells with a 99% success rate.

•  Proved reserves increased 12% to 279.1 MMBOE and proved plus probable reserves increased 24% to 406.2 MMBOE supported by the addition of 47.7 MMBOE of probable reserves from our Joslyn lease.   Positive reserve additions from acquisition and development efforts were successful in replacing 209% of 2004 production on a proved basis, and 384% on a proved plus probable basis.

•  The Fund's finding, development and acquisition costs ("FD&A") for the year were $11.34 per BOE on a proved plus probable basis and $15.83 per BOE on a proved basis including future development capital.

•  Enerplus' Reserve Life Index ("RLI") continued to be one of the longest in the sector at 14.0 years on a proved plus probable basis and 10.1 years on a proved basis.

•  Our recycle ratio (operating income divided by FD&A) was 1.9x for 2004 and 1.8x on a three-year basis using proved plus probable reserves.

•  Operating costs increased 6% in 2004 to $7.14/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.

•  General and administrative ("G&A") expenses increased to $1.23/BOE as a result of increased cost pressures associated with retaining skilled staff, increased performance based compensation and increased
compliance requirements.

•  Our commodity price risk management costs were $96.2 million ($3.50/BOE) during 2004 primarily due to record high crude oil prices that exceeded the call levels on our derivative instruments.  

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

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

Results of Operations

Production

Daily production during 2004 averaged 75,130 BOE/day, an 8% increase over average production volumes of 69,414 BOE/day for 2003.   This increase was primarily due to the acquisitions of Ice Energy, which closed January 7, 2004 and ChevronTexaco, which closed June 30, 2004.

Our average production during 2004 was weighted 60% natural gas and 40% liquids on a BOE basis.   Furthermore, production was widely distributed across more than 300 producing areas in Alberta, Saskatchewan, British Columbia and Manitoba.   No single area accounted for more than 7% of total production. With this diverse production base there is less risk that operational problems with a single property will have a material impact on our production and funds flow.

Average production volumes for the years ended December 31, 2004 and 2003 are outlined below:

Enerplus' exit production for the month of December 2004 averaged approximately 80,000 BOE/day.   We expect production for 2005 will average 75,500 BOE/day.   This estimate takes into account natural reservoir declines and forecast development expenditures of $275 million.   The estimate is before the effects of any future acquisitions, however, it assumes we will dispose of non-core properties throughout the first quarter of 2005 for proceeds of approximately $60 million.   These non-core properties are currently producing approximately 2,500 BOE/day.

Similar to our experience in 2004, we expect a greater portion of our 2005 capital program to be implemented in the latter part of the year, helping to increase our forecast exit production to approximately 77,500 BOE/day without consideration of any acquisitions or further divestments.

Pricing

Our earnings, funds flow and financial condition are dependent on the prices received 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 2004 with those of 2003.   It also compares the benchmark price indices for the same periods.

At the outset of 2004, the AECO benchmark natural gas price was approximately $7.00/Mcf due to winter demand, however milder weather caused the prices to retreat to around $6.00/Mcf.   Storage gas was purchased in the initial summer months of April and May at similarly high prices, but once it became evident there would be no difficulty in returning storage to normal levels, the price fell to a low of $5.00/Mcf in September.   Winter weather speculation combined with the strength in the crude oil market returned prices to average greater than $7.00/Mcf during the last quarter of 2004.   Overall, the average annual AECO gas price was only 1% higher in 2004 compared to 2003.

Our natural gas selling price increased 4% over the prior year as a result of a portion of our gas being sold directly into U.S. destinations such as Chicago, which benefited from the 3% increase in Canadian dollar NYMEX pricing during 2004.   As well, the netbacks we received from our aggregator sales were higher due to the increase in the NYMEX benchmark price.

As indicated by the current market for future prices (the "forward market"), AECO natural gas prices are currently expected to average $6.85/Mcf for 2005.   Concerns remain that North American gas production may not keep pace with demand although, in the near term, North American storage remains ahead of historical averages.   The tight balance between supply and demand will continue to create volatility whenever there are unexpected changes to weather, storage or economic activity.

The crude oil benchmark West Texas Intermediate ("WTI") price entered 2004 at US$33.78/bbl, experienced a peak of US$55.17/bbl late in October and closed the year at US$43.45/bbl. Overall, WTI prices were 33% higher in 2004 compared to 2003.   Continued instability in the Middle East combined with growing demand from Asia served to keep prices above US$35.00/bbl throughout 2004.

Approximately 27% of our liquids production is classified as heavy and as a result, the widening heavy oil differentials impacted our average crude oil selling price for the year.   For example, the price discount to WTI for the Lloydminster Blend heavy oil stream increased from US$8.45/bbl to US$13.40/bbl in 2004.   These widening differentials caused our average crude oil prices to increase by only 21% compared to the WTI benchmark in Canadian dollars which increased 25%.  

The forward market currently predicts crude oil prices will average US$47.82/bbl for 2005.   Increasing demand from China, political and labour unrest in Venezuela and Nigeria, as well as continued price support from OPEC, keeps upward pressure on the price of oil despite some indication of adequate short-term storage.

Throughout 2004 the Canadian dollar strengthened 7% against the U.S. dollar.   The strengthening CDN$/US$ exchange rate reduced prices received for our crude oil and a portion of our 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 Canadian dollar's strengthening against its U.S. counterpart mirrored the performance of the Euro and many other world currencies during the year.   The CDN$/US$ exchange rate entered 2004 at approximately $0.77, and hit a high of $0.85 in November as the U.S. continued to face challenges related to its high government debt and ongoing issues with respect to terrorism.   In addition, higher interest rates in Canada relative to the U.S. increased demand for the Canadian dollar.

The current forward market predicts a CDN$/US$ exchange rate of $0.81 for 2005.   Recent economic weakness in Canada's export sector as a result of the rapid appreciation of the Canadian dollar has dampened the likelihood that the Canadian government will be able to continue to increase interest rates relative to the U.S.  

Price Risk Management

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 to reduce the cost of protection against a significant downturn in prices.   The program is intended to provide a measure of stability to our cash distributions and balance sheet.   The program also helps realize the positive economic returns from our capital development and acquisition activities.  

Our commodity price risk management program incurred cash costs of $96.2 million during 2004 compared to $45.8 million during 2003.   The increase in cash costs during 2004 compared to 2003 was primarily due to our three-way crude oil contracts.   Record high oil prices exceeded our calls, which were priced at approximately US$30/bbl.   At the time we entered into the crude oil three-way contracts we, along with the forward markets, did not expect oil prices to increase much beyond US$30/bbl for an extended period.   We also incurred cash costs on our natural gas contracts, but to a lesser extent than we experienced in 2003 ($19.9 million in 2004 compared to $30.8 million in 2003).   Although some of our natural gas swaps were out-of-the-money for portions of the year, gas prices tended to fluctuate within the price range of many of our derivative instruments.

We continue to adjust our risk management strategies in response to the high cash costs experienced in 2004. We view the program as insurance given the historical volatility associated with oil and gas prices.   As we enter 2005, we are less concerned with utilizing "costless" instruments where the cost of the downside protection is covered entirely by the value of selling calls (upside price participation). We are more inclined to buy put protection or put spread protection and absorb the upfront costs associated with these contracts.   We are also more cautious about selling calls (upside price participation) too early, as the market has proven it can move dramatically higher than the range of expectation that had been established 12 to 24 months earlier. Within the context of these refinements, we intend to continue our commodity price protection program in 2005.   At the current time we do not have any CDN$/US$ exchange rate hedges associated with our revenues.  

The method we use to report the effects of our commodity price risk management program has changed to reflect the new accounting pronouncements regarding hedging relationships, which we have adopted prospectively as of January 1, 2004. Enerplus designated derivative instruments such as swaps, purchased puts and costless collars as qualified hedges for accounting purposes.   These instruments are evaluated quarterly to ensure they effectively hedge the underlying commodity.   All of our other financial instruments such as three-way option contracts including the purchased puts imbedded within the three-way options, and the calls or puts we sell, do not qualify as effective hedges for accounting purposes.   The implications of qualifying or not qualifying for hedge accounting is discussed more fully below.

The following table summarizes the effects that our financial contracts have had on income for the years ended December 31, 2004 and 2003.

* The new accounting rules were adopted prospectively, therefore only cash costs are reflected in 2003.

The unrealized cost of financial contracts of $21.3 million for the year ended December 31, 2004 represents the change in the fair value of financial contracts not qualifying for hedge accounting and results in a non-cash charge to earnings.  

The amortization of deferred financial assets is also a result of our adopting the new accounting rules for hedging relationships.   On January 1, 2004, all of our three-way financial contracts ceased to qualify for hedge accounting.   As a result, we recorded a deferred financial asset representing the fair value of these contracts on that day.   We are amortizing this asset to income over the life of the underlying contracts for which the deferred asset relates.   The asset has been included in deferred charges and amortization of this asset was $17.9 million for the year ended December 31, 2004, representing another non-cash charge to earnings.

The cash costs associated with financial contracts that do not qualify for hedge accounting are segregated from the costs of financial contracts that do qualify for hedge accounting.   During the year ended December 31, 2004 we realized cash costs of $78.0 million for financial contracts that do not qualify for hedge accounting as a result of commodity prices exceeding the ceiling price limits on many of our three-way contracts.  

Cash costs for financial contracts that qualify for hedge accounting decreased to $18.2 million for the year ended December 31, 2004 compared to $45.8 million for the year ended December 31, 2003.   This is a result of our three-way crude oil and natural gas contracts no longer qualifying for hedge accounting during 2004, compared to 2003 when all of our financial contracts qualified for hedge accounting.  

Enerplus' current commodity risk management positions are fully described in Note 12.   The following is a summary of the physical and financial contracts in place with floor protection and ceiling caps as a percentage of net
production volumes:

We also entered a swap contract to fix the price of electricity on 5 megawatt hours ("MWh"), representing 26% of the power consumption of our Alberta operated properties at a price of $49.99/MWh from January 1, 2005 to December 31, 2006.   The contract has been designated as a hedge and accounted for accordingly.   The fair value of this instrument at December 31, 2004 is negligible.   We may enter into additional electricity price swaps in 2005 to manage the cost of our operations.

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

These sensitivities reflect all commodity contracts as described in Note 12 and are based on current forward markets for 2005.   To the extent the market price of crude oil and 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 for the year ended December 31, 2004 were $1,124.6 million ($1,149.7 million, net of $25.1 million transportation) compared to $935.8 million ($958.9 million, net of $23.1 million transportation) during 2003.   The increase of $188.8 million or 20% is primarily due to higher crude oil and natural gas prices as well as higher crude oil and natural gas production resulting from the Ice Energy and ChevronTexaco acquisitions.

Analysis of Sales Revenue (1)

(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments

Royalties

Royalties are paid to various government entities and other land and mineral rights owners.   In 2004 royalties increased to $231.0 million compared to $190.4 million during 2003, both approximately 20% of oil and gas sales, net of transportation.   The increase is consistent with our revenue analysis of higher production and commodity prices during 2004. We expect royalties to remain at approximately 20% of gross oil and gas sales during 2005.  

Operating Expenses

Operating expenses for the year ended December 31, 2004 were $196.5 million or $7.14/BOE compared to $170.5 million or $6.73/BOE in 2003, representing a 6% increase on a BOE basis.   In particular, we experienced increased costs for well servicing, workovers and well maintenance as additional funds were spent to enhance production.   Operating costs on our partner operated properties also continued to increase as high commodity prices fueled demand for services and increased the overall cost of maintaining and enhancing production.   We expect 2005 operating costs to be approximately $7.45/BOE which represents an increase of 4% per BOE compared to 2004.

General and Administrative Expenses

General and administrative ("G&A") expenses were $33.9 million or $1.23/BOE for the year ended December 31, 2004 compared to $25.4 million or $1.00/BOE for 2003.   The increase in G&A costs during 2004 compared to 2003 can be attributed to both an increase in G&A cash costs along with an increase in non-cash charges.   Increased cost pressures associated with maintaining skilled technical and professional staff along with increased compliance and regulatory requirements such as the Sarbanes-Oxley Act increased cash costs from $0.95/BOE in 2003 to $1.06/BOE in 2004.  

Non-cash charges that relate to our trust unit rights incentive plan for the year ended December 31, 2004 were $4.7 million or $0.17/BOE compared to $1.4 million or $0.05/BOE for 2003.   This non-cash charge relates to trust unit rights issued after January 1, 2003 and is based on the excess of the trust unit price at December 31, 2004 of $43.60 over the exercise price of the right, amortized over the remaining vesting period.   This non-cash charge will increase or decrease along with the movement in the price of the underlying trust units. See Note 10.

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

We expect total G&A costs to be approximately $1.45/BOE during 2005, which includes non-cash charges for the trust unit rights plan similar to that experienced during 2004.   The forecasted increase reflects rising costs associated with recruiting, retaining and developing staff within a very competitive market place.   It also reflects the increasing costs of compliance with legal and regulatory changes such as the Sarbanes-Oxley Act and other similar
legislation in Canada.  

Management Fees and Internalization Expense

During 2004 no management fees were incurred compared to $58.1 million during 2003, which included $3.0 million in management fees and $55.1 million of internalization costs.   This is a result of the internalization of the management contract effective April 23, 2003.

Interest Expense

Interest expense increased to $20.7 million in 2004 from $19.7 million in 2003.   The increase is due to higher average debt outstanding during 2004 as a result of acquiring ChevronTexaco properties on June 30, 2004 offset by lower interest rates during the year.   At December 31, 2004, 24% of our debt was based on fixed interest rates while 76% was floating.   These instruments are more fully described in Note 12.

The Bank of Canada ("BOC") prime rate increased 25 basis points on October 19, 2004 to 4.25%, however the BOC has deferred further interest rate increases due to the strengthening Canadian dollar and its negative impact on the economy. We anticipate interest rates to remain at current levels during 2005.  

Foreign exchange

We experienced a foreign exchange gain of $5.0 million during the year ended December 31, 2004 compared to a gain of $0.9 million in 2003.   The majority of the gain during 2004 was a result of non-cash items related to the appreciating Canadian dollar and its impact when translating our US$54 million senior unsecured notes.   We realized minimal foreign exchange gains or losses on day-to-day transactions denominated in U.S. dollars.   See Note 9 for details regarding the cash and non-cash gains.

Capital Expenditures

During the year ended December 31, 2004 we spent $ 813.6 million on capital expenditures and acquisitions net of dispositions compared to $312.1 million in 2003.   As discussed in Notes 6 and 7, our most significant acquisitions during 2004 relate to the ChevronTexaco properties purchased for $467.2 million and the corporate acquisition of Ice Energy for $130.5 million .   Our capital expenditures were financed through bank borrowing, a new equity issue and by withholding a portion of cash otherwise available for distribution.

The following is a summary by major property of our largest capital expenditures during 2004 and 2003.  

Total capital expenditures in 2005, including directly related administrative costs, are expected to be approximately $275 million.   Of this amount, we expect to spend about $245 million on oil and natural gas drilling, facilities and development activities, and approximately $30 million to further develop our pilot project at Joslyn Creek.   Of the $245 million approximately $135 million will be spent on natural gas development including $25 million on coalbed methane development at Joffre, Trochu and Bashaw.   Conventional oil development costs are expected to be approximately $100 million, and land and seismic expenditures are expected to be approximately $10 million .

In 2004, we sold $31.7 million worth of non-core properties and we expect to continue the process of acquiring new properties and rationalizing marginal properties in 2005.   During the first quarter of 2005 we expect to sell approximately $60 million of non-core properties that are currently producing approximately 2,500 BOE/day.

ASSET RETIREMENT OBLIGATIONS

We retroactively adopted Canadian Institute of Chartered Accountants ("CICA") Handbook section 3110 "Asset Retirement Obligations" on January 1, 2004 and accrued a $63.9 million liability in this regard for December 31, 2003.   We based our estimated costs for abandonment on the costs provided by the Alberta Energy and Utilities Board ("EUB") in their liability rating.   During the course of the year, the EUB increased their estimates for abandonment and reclamation costs, which we have incorporated in our asset retirement obligation estimate as at December 31, 2004.   The change in EUB estimates resulted in $23.1 million being added to the liability.   Acquisition and development activity during the year added another $20.7 million to asset retirement obligations.   As at December 31, 2004 our asset retirement obligation was $106.0 million.   See Notes 2 and 4.

Depletion, depreciation, amortization and Accretion ("DDA&A")

DDA&A of property, plant and equipment is recognized using the unit-of-production method based on
proved reserves.  

For the year ended December 31, 2004, DDA&A increased to $11.87/BOE compared to $9.67/BOE during the year ended December 31, 2003.   The increase is due to the acquisitions of ChevronTexaco properties and Ice Energy, as well as higher production volumes and an increase in the asset retirement obligation.   Furthermore, proved reserves used in the depletion calculation decreased due to the adoption of National Instrument 51-101 ("NI 51-101") at December 31, 2003.   As a result, DDA&A recorded during the year ended December 31, 2004 was significantly higher than the comparable period of 2003, which was based on reserves prior to the adoption of NI 51-101.

No impairment existed at December 31, 2004 using year-end reserves and management's estimates of future prices.   Our future price estimates are more fully discussed in Note 5.  

Taxes

Capital taxes, consisting of the Federal Large Corporations Tax ("LCT") and the Saskatchewan Resource Surcharge, increased slightly in 2004 compared to 2003.   The increase is due to an increase in total debt and equity levels, as a result of acquisitions, offset by a reduction in the tax rate for LCT.   Given our current capital structure, capital taxes are expected to be $6.0 million in 2005.

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

For the year ended December 31, 2004, a future income tax recovery of $76.8 million was recorded in income compared to $71.6 million in 2003.   The increased recovery in 2004 was mainly the result of increased net income of the Fund during 2004.   Our expected future income tax rate incorporating these changes is approximately 34% compared to 35% at December 31, 2003.  

Selected Financial Results

(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments

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 2004 compared to 2003.   The following table summarizes net income, funds flow from operations and other key measures for the last three years.

(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments

Funds flow from operations for the year ended December 31, 2004 was $540.0 million or $5.44 per trust unit compared to $413.2 million or $4.79 per trust unit for 2003.   The increase in funds flow from operations was a result of higher commodity prices and production during 2004 compared to 2003, offset in part by the cash losses from our commodity price risk management program, along with higher operating and G&A costs.   As well, the internalization of the management contract, which occurred during 2003, reduced the comparative period results for the year ended December 31, 2003.

Net income for the year ended December 31, 2004 was $258.3 million or $2.60 per trust unit compared to $248.0 million or $2.88 per trust unit for 2003.   The increase in net income for the year ended December 31, 2004 was due to higher commodity prices and production, no management fees due to the internalization completed in 2003, as well as an increase in our future tax recovery.   This was offset by increases in operating costs, depletion expense and G&A costs, as well as changes in accounting for our derivative instruments.   The decrease in net income per trust unit was due to an increase in the weighted average number of trust units outstanding.

Quarterly Financial Information

Overall oil and gas sales have increased due to higher prices and production both through acquisitions and capital development throughout the last two years, offset by an increased Canadian/U.S. dollar exchange rate.   Net income has been affected by the fluctuations in oil and gas sales, the increase in risk management costs, the strengthening Canadian dollar, the internalization of the management contract during 2003, increasing operating costs, increased future tax recovery and changes to accounting policies adopted during 2003 and 2004.

(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments

Summary Fourth Quarter Information

In comparing the fourth quarter of 2004 with the same period in 2003:

•  Funds flow from operations increased 71% to $149.4 million and 46% on a BOE basis as a result of higher production and selling prices;

•  Average daily production increased 17 % due to the acquisition of Ice Energy and the ChevronTexaco properties as well as a successful capital development program;

•  The average selling price per BOE increased 35% due to stronger crude oil and natural gas prices;

•  Operating expenses decreased 13% to $6.93/BOE as the fourth quarter of 2003 was impacted by a number of one-time prior period charges;

•  G&A expenses increased 35% to $1.59 /BOE, as the fourth quarter of 2004 was impacted by increased charges for unit based compensation related to the higher trust unit price and performance achieved
by the Fund;

•  Net income increased 182% to $114.5 million; and

•  Development capital spending increased 78% as we had a larger development program in 2004, and more of that program was directed to the fourth quarter in response to drilling plans, rig availability and weather related timing.

  (1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments

Cash Available for Distribution

We make monthly cash distributions to our unitholders based upon net funds flow from our crude oil and natural gas operations. A portion of funds flow is typically retained to fund some of our acquisition and development activities. For the year ended December 31, 2004, we generated $540.0 million in funds flow from operations. Of this amount, $426.7 million ($4.20 per trust unit) was paid to unitholders and $113.3 million ($1.11 per trust unit) was retained .

We monitor the distribution payout with respect to forecasted funds flows, debt levels and spending plans. The level of cash retained typically varies between 10% and 30% of annual funds 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.

  * Cash available for distribution will differ from Cash Distributions to Unitholders on the Consolidated Statements of Cash Flows due to the timing of distribution declaration and actual payments.

Liquidity and Capital Resources

Long-term debt at December 31, 2004 was $585.0 million , an increase of $246.9 million from December 31, 2003.   The increase in debt is primarily the result of the ChevronTexaco and Ice Energy acquisitions, which were funded by both bank debt and equity.   Furthermore, long-term debt levels at the end of 2003 were lower than normal due to an equity issue that closed December 17, 2003 in advance of the Ice Energy acquisition.  

Long-term debt at December 31, 2004 is comprise d of $251.7 m illion of bank indebtedness and $65.0 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 .  

Working capital declined at December 31, 2004 compared to the prior year.   At the end of December 31, 2003 we had cash of $80 million from an equity issue that had closed just prior to year-end.   In addition, working capital was reduced as a result of new accounting pronouncements during 2004 with respect to derivative instruments.   The fair value of the instruments that do not qualify as hedges have been recorded as deferred credits and are included in current liabilities, however these costs will fluctuate depending on the commodity prices at the time of settlement and will be paid from future production which is not yet recorded in the financial statements.  

We continue to maintain a conservative balance sheet as demonstrated below:

  Long-term debt is measured net of cash.

In November 2004, Enerplus finalized a new $850 million bank credit facility (the "Bank Credit Facility") through its wholly-owned subsidiary EnerMark Inc.   The Bank Credit Facility is an unsecured, covenant-based, three-year committed credit agreement with nine North American banks.   We have the ability to extend the facility each year or repay the entire balance at the end of the three-year term.   As at December 31, 2004, we had $598.3 million of available borrowing capacity under this facility. This bank debt carries floating interest rates that are expected to range between 65 and 87.5 basis points over Bankers Acceptance rates, depending on Enerplus' ratio of senior debt to earnings before interest, taxes, depreciation, amortization and other non-cash items.

The new agreement increased our borrowing capacity and extended the term of our facility.   Furthermore, we are no longer restricted to borrowing base evaluations that are determined using the banks' commodity price outlook.   Although there are certain exceptions, we are generally required to maintain a debt to funds flow ratio of less than three times, and a debt to capitalization of less than 50%.  

The Bank Credit Facility and the Senior Unsecured Notes are the legal obligation of EnerMark Inc. and are guaranteed by Enerplus Resources Corporation and Enerplus Commercial Trust.   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 funds flow be insufficient to repay this indebtedness.   The agreements governing these bank facilities and senior unsecured notes stipulate that if we 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.  

Principal payments on Enerplus' senior unsecured notes are required commencing in 2010 and 2011 and are more fully discussed in Note 8.

On June 15, 2004, we completed an equity offering of 8.8 million subscription receipts at a price of $34.30 per subscription receipt.   Each subscription receipt entitled the holder to receive one trust unit of the Fund upon closing of the ChevronTexaco asset acquisition.   All subscription receipts were converted to trust units on June 30, 2004 and gross proceeds of the issue were $301.8 million ($286.2 million net of issuance costs).

We anticipate that we will continue to have adequate liquidity to fund future working capital and planned capital expenditures during 2005 through a combination of funds flow from operations, proceeds from dispositions and debt.   Most of Enerplus' $275 million capital budget for 2005 is discretionary and can be revised downward 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 a combination of debt, equity and funds flow
from operations.

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 2005.

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 $4.6 million. The Fund's commitments, contingencies, and guarantees are more fully described in Note 13.

We must continue to pay crown royalties and rentals, surface royalties and 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.

Natural gas reserves producing approximately 31% 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 104,124,000 trust units outstanding at December 31, 2004 compared to 94,349,000 trust units at December 31, 2003, reflecting the equity offering completed during the year.   The weighted average basic number of trust units outstanding during 2004 was 99,273,000 (2003 - 86,202,000).  

In addition to the equity offering during the year 957,000 trust units (2003 - 1,515,000) 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 $28.3 million (2003 - $40.4 million) of additional equity to the Fund.   A total of 25,000 units with a value of $0.9 million were issued to acquire corporate and property interests during 2004 compared to 660,000 units with a value of $21.4 million issued during 2003.

Income Taxes

The following is 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 $4.20 per trust unit in cash distributions to unitholders during the period February 2004 to January 2005. For Canadian tax purposes, 10% of these distributions, or $0.43 per trust unit was a tax deferred return of capital, 88% or $3.68 per trust unit was taxable to unitholders as other income, and 2% or $0.09 per trust unit was taxable
dividend income.

For 2005, we estimate that 95% of cash distributions may be taxable and 5% may be a tax deferred return of capital.   Actual taxable amounts may vary depending on actual distributions which are dependent upon production, commodity prices and funds flow experienced throughout the year.  

U.S. Taxpayers

During 2004 U.S. unitholders who received cash distributions were subject to at least 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 2004 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$3.22 per trust unit to U.S. residents during the 2004 calendar year, of which 6% or US$0.19 per trust unit was a tax deferred return of capital and 94% or US$3.03 per unit was a taxable qualified dividend.

On September 16, 2004, the Canadian Federal Government released draft legislation with respect to the March 2004 Budget.   The draft legislation amends certain provisions of the Income Tax Act that would affect the taxation of distributions to non-resident unitholders.

The draft legislation is expected to be passed into law during the first quarter of 2005.   As currently drafted, a 15% Canadian withholding tax will be applicable, effective January 1, 2005, to the non-taxable portion of distributions to non-resident unitholders (which is currently estimated to be 5% of distributions).   This is in addition to the existing 15% withholding tax on the portion of the distribution designated as income.   It is contemplated, however, that there will be a mechanism under which certain non-residents may recover all or a portion of such taxes where the ultimate disposition of the trust unit results in a loss for Canadian tax purposes.

For 2005, we estimate that 95% of cash distributions may be taxable to most U.S. investors and 5% 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 14.   Most accounting policies are mandated under GAAP.   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 majority of the Fund's drilling activity is in low risk development drilling that has traditionally achieved high success rates.

Under the 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.   Due to the timing of when activities occur compared to the reporting of those activities, management estimate and accrue operating results and capital spending.   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 asset retirement obligations and the application of an impairment test.   Revisions or changes in the reserve estimates can have either a positive or a negative impact on net income and the asset retirement obligation.

Management calculates its asset retirement obligation based on the estimated costs to abandon and reclaim its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods.   The fair value estimate is capitalized to property, plant and equipment as part of the cost of the related asset and amortized over its useful life.  

Management's estimates of oil and natural gas prices are also critical as these prices are used to determine the carrying amount of property, plant and equipment, amounts recorded for depletion, impairment in the cost centre, and the change in fair value of financial contracts that do not qualify for hedge accounting.  

RECENT CANADIAN ACCOUNTING and related PRONOUNCEMENTS

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 and amortized over the same period as the underlying asset. The standard is effective for all fiscal years beginning on or after January 1, 2004.   We adopted the standard
January 1, 2004.   See Notes 2 and 4.

Hedging Relationships

In November 2002, the CICA published an amended Accounting Guideline 13 ("AcG-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 impacted the Fund's net income and net income per trust unit, as certain financial instruments for oil and natural gas do not qualify for hedge accounting.   See Note 12. Where hedge accounting does not apply, any changes in the fair values of the financial instruments relating to a period can either reduce or increase net income for that period.   We adopted this standard January 1, 2004, which has resulted in a reduction in our pre-tax income of $39.2 million.  

Variable Interest Entities ("VIEs")

In June 2003 the CICA issued Accounting Guideline 15 ("AcG-15") "Consolidation of Variable Interest Entities".   AcG-15 defines VIEs as entities in which either; the equity at risk is not sufficient to permit that entity to finance its activities without additional financial support from other parties; or equity investors lack voting control, an obligation to absorb expected losses or the right to receive expected residual returns.   AcG-15 harmonizes Canadian and U.S. GAAP and provides guidance for companies consolidating VIEs in which it is the primary beneficiary. The guideline is effective for all annual and interim periods beginning on or after November 1, 2004.   We do not expect this guideline to have a material impact on the Fund.  

Earnings per Share

In July 2004 the CICA proposed to amend Handbook Section 3500 "Earnings per Share", to reflect similar amendments adopted by the International Accounting Standards Board and proposed by the U.S. Financial Accounting Standards Board.   The majority of the amendments relate to the treatment of mandatorily convertible instruments. The CICA expects changes to be effective for interim and annual periods relating to fiscal years beginning on or after January 1, 2005.   We currently do not have any mandatorily convertible instruments and therefore do not expect these amendments to have a material impact on the Fund.

Financial Instruments - Recognition and Measurement, Hedges, and Comprehensive Income

The Accounting Standards Board ("AcSB") has issued three exposure drafts on financial instruments which will apply to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006.   It will require the following:

•  all trading financial instruments will be recognized on the balance sheet and will be fair valued through the income statement;

•  all remaining financial assets will be recorded at cost and amortized through the financial statements;

•  a new statement for comprehensive income that will include certain gains and losses on translation of assets and liabilities; and

•  an update to AcG-13 to incorporate the fair value changes not recorded in the income statement to be recorded through the comprehensive income statement.

We have not assessed the future impact on the financial statements of the Fund at this time.  

Changes in Accounting Policies and Estimates and Errors

The AcSB has proposed a new Handbook section 1506 "Changes in accounting policies and estimates, and errors" to provide guidance around when and how an entity is permitted to change an accounting policy as well as establish appropriate disclosures to explain the effects of changes in accounting policy, estimates and corrections of errors.

Subsequent Events

The AcSB has proposed to extend the period during which subsequent events are required to be considered.   This period is between the balance sheet date and when the financial statements are authorized for issue. Furthermore, disclosure is required as to the date the financial statements were authorized for issue and who provided
that authorization.

Other accounting standards issued by the CICA during the year ended December 31, 2004 are not expected to materially impact the Fund.

Risk Factors and Risk Management

Enerplus investors are participating in the net funds flow from a portfolio of western Canadian crude oil and natural gas producing properties. As such, the funds 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 we receive for our 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.   Regulatory changes to reserve reporting practices can also result in reserve write-downs.   As activity levels in the industry increase, upward pressure is placed on administrative and operating costs.   Higher costs will decrease the amount of funds flow received by the Fund and therefore, reduce distributions to unitholders.

We strive to acquire low risk, mature properties with a high proportion of proved reserves, positive operating metrics, 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, 2004 approximately 88% of our major properties, representing proved plus probable net present value, discounted at 10%, 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, we fixed the price on a portion of our 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 diligen