In 2006, cash flow, net income and cash distributions to unitholders increased.

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

The following discussion and analysis of financial results is dated February 21, 2007 and is to be read in conjunction with the audited consolidated financial statements as at and for the years ended December 31, 2006 and 2005. All amounts are stated in Canadian dollars unless otherwise specified. All references to GAAP refer to Canadian generally accepted accounting principles. 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. Oil and natural gas reserves and production are presented on a company interest basis which is not a term defined or recognized under NI 51-101. Therefore, our company interest reserves may not be comparable to similar measures presented by other issuers. 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. Certain prior year amounts have been restated to reflect current year presentation.

The following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A for our disclaimer on forward-looking statements.

NON-GAAP MEASURES

Historically we used the non-GAAP measure funds flow from operations (or "funds flow") to analyze operating performance, leverage and liquidity. We are now utilizing the GAAP measure cash flow from operating activities ("cash flow") instead of funds flow. The difference is that cash flow from operating activities includes changes in non-cash working capital and appears on our Consolidated Statements of Cash Flows.

We also historically used the non-GAAP measure cash available for distribution. We are now using cash distributions to unitholders ("cash distributions") which also appears on our Consolidated Statements of Cash Flows. Cash available for distribution was based on the twelve month production period January through December wherein the related distributions were paid with a two month lag or March through February respectively. Cash distributions include amounts paid or declared during the calendar year which relate to the twelve month production period December through November wherein the related distributions are paid February through January.

Our payout ratio was previously calculated as cash available for distribution divided by funds flow; however, as a result of the above-mentioned changes, our payout ratio is now calculated as cash distributions divided by cash flow from operating activities. This reflects the proportion of cash flow paid out to investors and not reinvested in the business. The term payout ratio does not have a standardized meaning as prescribed by GAAP and therefore may not be comparable with the calculation of a similar measure by other entities.

Refer to the Liquidity and Capital Resources section of the MD&A for further information on cash flow, cash distributions and payout ratio.

Update on Canadian Government Announcement on intention to tax trusts

On October 31, 2006, the Canadian federal government (the "Government") announced plans to introduce a tax on publicly traded income trusts. For existing income trusts, such as Enerplus, the new tax measures would be effective for 2011, provided we comply with the "normal growth" parameters regarding equity growth until that time. A "Notice of Ways and Means Motion" was passed in Parliament shortly after the Government announcement. This notice was a one-page summary of the Government's proposal and it did not identify any specific amendments to the Income Tax Act.

On December 15, 2006 the Government announced safe harbour guidance regarding "normal growth" for equity capital. The safe harbour amount will be measured by reference to the individual trust's market capitalization as of the end of trading on October 31, 2006 (which was approximately $7.5 billion for Enerplus). For the period from November 1, 2006 to December 31, 2007 a trust's safe harbour amount will be 40 percent of the October 31, 2006 market capitalization benchmark and for each of the years 2008 through and including 2010 will be 20 percent of the benchmark, cumulatively allowing growth of up to 100 percent until 2011. In addition, we understand that trusts will be able to issue equity to retire debt existing on October 31, 2006 without eroding their safe harbour limits.

On December 21, 2006, the Government released more detailed draft legislation with respect to the proposed amendments to the Income Tax Act and requested comments from stakeholders. In late January 2007, the House of Commons Standing Committee on Finance held special hearings on the proposed tax and the draft legislation. At this time we are unable to determine the impact, if any, these hearings may have on the proposed legislation or the timing of when the proposed legislation could be passed in Parliament.

Should the tax legislation become substantially enacted, future income taxes may be adjusted to include temporary differences between the accounting and tax bases of the trust's assets and liabilities. In addition, reserves reported under NI 51-101 may be adjusted to include an estimate of the tax effect on our estimated future revenues from our reserves. We will assess alternative organizational structures during the four-year transition period. We are confident we have the team, the assets, and the opportunities to prosper regardless of our organizational structure.

2006 Overview

During 2006 we executed our largest capital program to date, spending $491.2 million. The increased capital spending resulted in average production of 85,779 BOE/day, exceeding our guidance of 85,500 BOE/day. Both general and administrative costs ("G&A") and operating costs were higher than guidance due to cost escalation associated with the high level of industry activity.

Compared to 2005, cash flow increased 11% to $863.7 million, net income increased 26% to $544.8 million, and cash distributions increased 23% to $614.3 million. Increased production, crude oil prices and lower risk management costs were partially offset by reduced natural gas prices and increased costs, resulting in the year-over-year increases in cash flow and net income. Monthly cash distributions remained constant at $0.42 per trust unit throughout 2006.

Our trust unit price declined in the last quarter of 2006 due to the Government's proposed tax on income trusts and, to a lesser extent, in response to weakening crude oil and natural gas prices. Our Canadian unitholders realized a negative 0.3% total return while our U.S. unitholders realized a 0.1% total return in 2006 (representing the change in unit price plus distributions paid during the year).

Highlights

• Cash flow increased 11% to $863.7 million from $774.6 million in the previous year.
• Cash distributions increased in 2006 by 23% to $614.3 million or 11% per unit to $5.05 per unit (based on weighted average trust units outstanding) compared to 2005.
• Actual monthly distributions per trust unit remained constant throughout 2006 at $0.42 resulting in annual cash distributions of $5.04 for each unitholder.
• Average selling price per BOE decreased 4% to $50.23 due to weaker natural gas prices.
• Our largest development capital program to date of $491.2 million was essentially in line with our target of $485.0 million.
• The additional development capital spending during 2006 resulted in production that averaged 85,779 BOE/day exceeding our annual target of 85,500 BOE/day.

• Net income increased 26% to $544.8 million. On a trust unit basis this resulted in an increase of 13% to $4.48 per unit reflecting the increase in trust units outstanding.
• Our payout ratio increased to 71% from 64% in 2005 as we distributed more of our cash flow from operating activities to our unitholders.
• Operating costs were $8.02/BOE in 2006, 8% higher than $7.45/BOE in 2005.
• G&A costs were $1.91/BOE, higher than our guidance of $1.85/BOE and 37% higher than $1.39/BOE in 2005.
• Our realized commodity price risk management cash costs were $34.3 million ($1.10/BOE) during 2006, a 76% reduction compared to $142.6 million ($4.90/BOE) during 2005.

• Drilling efforts resulted in a success rate of over 99% with participation in 361 net wells.
• Our finding, development and acquisition costs ("FD&A") for the year were $23.19/BOE on a proved plus probable basis and $28.82/BOE on a proved basis.
• Proved plus probable reserves decreased 1% to 443.3 MMBOE and proved reserves decreased 4% to 299.8 MMBOE.
• Reserve additions from development capital spending and acquisitions replaced 82% of 2006 production on a proved plus probable basis and 57% of production on a proved basis.
• Our 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, including both conventional and non-conventional reserves.
• Our recycle ratio (operating income divided by FD&A) was 1.6x on a three-year basis and 1.4x for 2006 using proved plus probable reserves.
• We continue to maintain a conservative balance sheet as evidenced by a net debt to trailing 12 month cash flow ratio of 0.8x.

Results of Operations

Production

Daily production during 2006 averaged 85,779 BOE/day, slightly above our guidance of 85,500 BOE/day and 8% higher than 79,727 BOE/day in 2005. The increase was primarily due to our U.S. acquisitions in the second half of 2005 which added an incremental 8,121 BOE/day of production in 2006 along with our development capital program which added an additional 5,633 BOE/day of production in 2006. These increases were offset in part by natural reservoir declines experienced throughout the year.

Average production during the year was weighted 53% to natural gas and 47% to liquids on a BOE basis. Average production volumes for the years ended December 31, 2006 and 2005 are outlined below:

We exited the year with production of approximately 87,500 BOE/day based on December's production, in line with our target of 88,000 BOE/day.

We expect 2007 annual production volumes to remain essentially flat year-over-year, averaging 85,000 BOE/day, weighted 54% to natural gas and 46% to liquids. As a result of the timing of our planned development capital program, we expect to exit 2007 with production of approximately 86,000 BOE/day. This does not contemplate any potential acquisitions or dispositions.

Pricing

The prices received for our natural gas and crude oil production directly impact our earnings, cash flow and financial condition. The following table compares our average selling prices for 2006 with those of 2005. It also compares the benchmark price indices for the same periods.

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

Natural Gas

Natural gas prices were in a downward trend during 2006, influenced initially by demand loss, the residual high storage inventories after a warm winter, and strong drilling. In July 2006, prices received some support due to above normal temperatures in key consuming regions of the United States, and forecasts for a strong hurricane season. Year-over-year the natural gas storage surplus continued to build and those hurricanes that did develop were moderate. This ultimately drove the AECO monthly index price to a low for the year of $4.45/Mcf in October, with the daily spot price dropping to $3.25/Mcf in the same month. Spot and forward prices recovered significantly as winter approached, with spot prices rising briefly above $8.00/Mcf before the warmer than normal November and December, caused by an El Nino weather pattern, pushed the daily spot price back to $6.07/Mcf on December 31, 2006.

Our natural gas portfolio is comprised of aggregator, AECO, and downstream direct sales. In 2006 we sold 42% of our natural gas on the daily AECO market and 42% on the monthly AECO market, as well as 16% against the day and month NYMEX indices. During 2006 we realized an average price for our natural gas sales of $6.81/Mcf (net of transportation costs), a decrease of 19% from the $8.41/Mcf realized in 2005. This reduction is comparable to the price decreases realized in each of: the AECO daily index which decreased by 25% year over year; the AECO monthly index which decreased by 18%; and the NYMEX monthly index (converted to CDN$/Mcf) which decreased by 20%.

Crude Oil

World crude prices continued to be influenced by a tight supply-demand balance through the first half of 2006, continuing the upward trend in prices experienced during 2005. WTI spot prices peaked in July during the Israel-Hezbollah conflict at US$77.03/bbl. With strong inventories, forecasts for warmer than normal conditions for the winter, and a strengthening supply picture, prices fell thereafter through the second half of 2006. The WTI spot price hit a low of US$55.81/bbl in November, representing a 28% reduction from the July high.

Our crude oil portfolio in 2006 was approximately 70% light/medium and 30% heavy. The average price received for our crude oil (net of transportation costs) was $61.80/bbl during 2006, a 10% increase over 2005. Similarly, the West Texas Intermediate ("WTI") crude oil benchmark price, after adjusting for the change in the US$ exchange rate, also increased by 10% year over year. Although we added more light sweet crude oil to our portfolio in 2006 compared to 2005, this benefit was offset by widening heavy crude oil differentials during the year.

The Canadian dollar strengthened 6% against the U.S. dollar during 2006 compared to 2005 based on the annual average exchange rate. As most of our crude oil and a portion of our natural gas are priced in reference to U.S. dollar denominated benchmarks, this movement in the exchange rate reduced the Canadian dollar prices that we would have otherwise realized.

Price Risk Management

While the overall energy outlook remains generally bullish long term, there remains uncertainty as to the direction prices might move in 2007. Both natural gas and crude oil prices have the potential to fall further in 2007 given current levels of inventory, aggressive drilling in the U.S. for gas and across the globe for crude oil and some uncertainty with respect to the world economy.

We have developed a price risk management framework to respond to the volatile price environment in a prudent manner. Consideration is given to our overall financial position together with the economics of our acquisitions and capital development program. Consideration is also given to the upfront costs of our risk management program as we seek to limit our exposure to price downturns while maintaining participation should commodity prices increase.

Given our price risk management framework we have entered into additional commodity contracts during the fourth quarter and subsequent to year end. These contracts are designed to protect a portion of our natural gas revenue for the period January 2007 through March 2008 and to protect a portion of our crude oil revenue for the period January 2007 through December 2007. We have also hedged electricity volumes for the period January 2007 through September 2008 to protect against rising electricity costs in the Alberta power market. See Note 10 for a detailed list of our current price risk management positions.

The following is a summary of the physical and financial contracts in place at February 13, 2007 as a percentage of our forecasted net production volumes:

Based on weighted average price, before premiums, and average production of 85,000 BOE/day.
Assumes production mix of 54% gas, 42% oil and 4% NGL.

Accounting for Price Risk Management

During 2006, our commodity price risk management positions incurred cash costs of $27.2 million on crude oil contracts and $7.1 million on natural gas contracts compared to cash costs of $91.0 million and $51.6 million respectively during 2005. The decrease in crude oil cash costs is due to the expiration of contracts on June 30, 2006 that had ceiling prices between US$35.35/bbl and US$45.80/bbl on 4,500 bbls/day. The decrease in natural gas cash costs is the result of lower natural gas prices experienced during 2006 and the expiration of old contracts.

The unrealized gain on our financial contracts of $81.0 million for the year ended December 31, 2006 represents the change in the fair value of financial contracts since December 31, 2005. As the forward markets for natural gas and crude oil fluctuate, and new contracts are executed and existing contracts are realized, changes in fair value are reflected as a non-cash charge or increase to earnings. At December 31, 2006 the fair value of our financial contracts net of premiums is $23.6 million and is recorded on the balance sheet as a deferred financial asset. See Note 2 for details.

Effective December 31, 2005, we elected to stop designating our commodity financial contracts as hedges. As a result we recorded a deferred credit representing the fair value of these contracts on that day, with an offset recorded as a deferred financial asset that is amortized to income over the life of the underlying contracts. These costs of $49.9 million are fully amortized at December 31, 2006. See Note 2 for details.

The following table summarizes the effects of our financial contracts on income for the years ended December 31, 2006 and 2005.

Cash Flow Sensitivity

The sensitivities below reflect all commodity contracts as described in Note 10 and are based on current forward markets for 2007 at February 13, 2007. To the extent the market price of crude oil and natural gas change significantly from current levels, the sensitivities will no longer be relevant as the effect of our commodity contracts will change.

⁽¹⁾ Assumes constant working capital and 123,151,000 units outstanding.

The impact of a change in one factor may be compounded or offset by changes in other factors. This table does not consider the impact of any inter-relationship among the factors.

Revenues

Crude oil and natural gas revenues for the year ended December 31, 2006 were $1,572.7 million ($1,595.3 million, net of $22.6 million of transportation costs) compared to $1,523.7 million ($1,550.6 million, net of $26.9 million of transportation costs) during 2005. Increased crude oil volumes from our 2005 acquisitions along with higher realized oil prices were offset primarily by the decrease in natural gas prices. The result was an increase of 3% or $49.0 million in revenue net of transportation costs.

⁽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. Royalties in 2006 and 2005 were approximately 19% of oil and gas sales, net of transportation costs. Overall, royalties decreased marginally in 2006 to $293.2 million compared to $297.0 million during 2005 primarily as a result of the decrease in natural gas prices experienced over the period.

For 2007 we expect royalties to remain at approximately 19% of oil and gas sales, net of transportation costs, however this may change as a result of the Alberta government's stated intention to review the oil and gas royalty regime. Alberta royalties represented approximately 70% of our total royalties incurred during 2006 (2005 - 87%).

Operating Expenses

Operating expenses for the year ended December 31, 2006 were $8.02/BOE or $251.2 million. This represents a 3% increase over our guidance of $7.80/BOE and an 8% increase from $7.45/BOE in 2005. Cost pressures associated with the high level of industry activity have increased operating costs during 2006. The areas that were most impacted by these activity levels included scheduled facility maintenance and well servicing.

During the fourth quarter we experienced increases as a result of the timing of certain well servicing and facility maintenance programs. As well, we experienced higher natural gas processing fees at certain facilities.

We anticipate continued increases in operating costs in 2007 due to general cost escalation. As a result, we expect costs to average $8.45/BOE, representing an increase of 5% per BOE compared to 2006. Although we are seeing evidence that the cost inflation in our industry has moderated, it is too soon to tell if this trend is sustainable.

General and Administrative Expenses

G&A expenses were $1.91/BOE or $59.9 million for the year ended December 31, 2006. On a BOE basis G&A was 3% higher than our guidance of $1.85/BOE and 37% higher than $1.39/BOE 2005.

The highly competitive marketplace resulted in challenges to recruit and retain skilled professionals. For the year ended December 31, 2006 compensation and long-term incentives increased approximately $14.0 million or $0.45/BOE compared to the same period in 2005. Other increases included additional technology and information systems, our commitment to education funding for SAIT Polytechnic, along with ongoing regulatory compliance requirements.

For the year ended December 31, 2006, our G&A expenses included non-cash charges for our trust unit rights incentive plan of $6.3 million or $0.20/BOE compared to $3.0 million or $0.11/BOE for 2005. These amounts are determined using a binomial lattice option-pricing model. The increased volatility of our trust unit price combined with the increased number of rights outstanding, as a result of an increase in the number of employees, have impacted the non-cash cost of the plan.

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

In 2007 we expect total G&A costs to be approximately $2.40/BOE, including non-cash G&A costs of approximately $0.30/BOE. The forecasted increase reflects cost pressures to recruit and retain a technically skilled labour force. It also includes increased costs associated with ongoing regulatory compliance and costs associated with planning and responding to the proposed tax on trusts.

Interest Expense

Annual interest expense increased by $6.4 million to $32.2 million compared to $25.8 million in 2005. This increase is due to higher average debt outstanding and rising interest rates during 2006. Our average borrowing rate, before the effects of hedging, for 2006 was 4.8% compared to 3.4% for 2005. At December 31, 2006, 20% of our debt was based on fixed interest rates while 80% was floating. These instruments are more fully described in Note 10.

Capital Expenditures

During the year ended December 31, 2006 we spent $491.2 million on development capital and facilities, our largest capital program to date. This was $6.2 million higher than our guidance of $485.0 million and $122.5 million or 33% higher than the $368.7 million spent in 2005. We achieved a 99% success rate with our drilling program as 361 net wells were drilled during 2006. Development in 2006 focused primarily on Bakken oil, shallow gas, coalbed methane, waterfloods, and our Joslyn oil sands property.

Property acquisitions were $51.3 million for the year ended December 31, 2006 compared to $119.9 million in 2005. Acquisitions during 2006 included $16.0 million for assets in the U.S., as well as $11.9 million and $11.7 million for properties at Copton and Gleneath respectively. There were no corporate acquisitions during 2006 whereas in 2005 we spent $584.1 million for the acquisitions of Lyco Energy Corporation and TriLoch Resources Inc. Property dispositions were $21.1 million for the year ended December 31, 2006 compared to $66.5 million for 2005. The majority of our 2006 divestments related to the sale of a 1% working interest in the Joslyn property in the amount of $19.7 million compared to the 2005 non-core divestment program which raised $66.5 million.

⁽¹⁾Net of post-closing adjustments.

The following is a summary by major property of our largest development capital expenditures during 2006 and 2005.

We expect total development capital expenditures in 2007 to be approximately $410 million. We plan to spend approximately $70 million on Bakken oil development, $65 million on waterflood development, $43 million on shallow natural gas and coalbed methane development and $40 million on oil sands development. We expect other conventional development costs to be approximately $192 million during 2007.

Depletion, Depreciation, Amortization and Accretion ("DDA&A")

DDA&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on proved reserves. For the year ended December 31, 2006 DDA&A increased to $15.38/BOE compared to $13.27/BOE during the year ended December 31, 2005. The increase was due to the inclusion of a full year of operations from our U.S. properties which were acquired in the latter half of 2005.

No impairment existed at December 31, 2006 using year-end reserves and management's estimates of future prices. Our future price estimates are more fully discussed in Note 3.

Asset Retirement Obligations

We have estimated our total future asset retirement obligations based on our net ownership interest in wells and facilities, estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. Our asset retirement obligation was $123.6 million at December 31, 2006 compared to $110.6 million at December 31, 2005. The increase of $13.0 million was due to our acquisition and development activity during the year combined with changes in estimated future liabilities. The remainder of the change was due to retirement costs incurred offset by accretion expense for the year. See Note 4.

The following chart compares the amortization of the asset retirement cost, accretion of the asset retirement obligation, and asset retirement obligations settled.

Actual asset retirement costs will be incurred at different times compared to the recording of amortization