Exhibit 99.3

MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”)

The following discussion and analysis of financial results is dated February 27, 2008 and is to be read in conjunction with the audited consolidated financial statements as at and for the years ended December 31, 2007 and 2006. 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 revenues are reported on a gross basis, before deduction of Crown and other royalties, unless otherwise stated. In addition to disclosing reserves under the requirements of NI 51-101, we also disclose our reserves on a company interest basis which is not a term defined under NI 51-101. This information 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.

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 information and statements.

NON-GAAP MEASURES

Throughout the MD&A we use the term “payout ratio” to analyze operating performance, leverage and liquidity. We calculate payout ratio by dividing cash distributions to unitholders (“cash distributions”) by cash flow from operating activities (“cash flow”), both of which appear on our consolidated statements of cash flows. The term “payout ratio” does not have a standardized meaning or definition as prescribed by GAAP and therefore may not be comparable with the calculation of similar measures 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.

2007 OVERVIEW

Cash flow from operating activities totaled $868.5 million in 2007, essentially flat over 2006. Higher realized crude oil prices, cash gains generated from our price risk management program and a decrease in our non-cash working capital helped to mitigate the impact of lower production, reduced natural gas prices and increased operating costs. Monthly cash distributions remained constant at $0.42 per trust unit throughout 2007 for an annual total of $5.04 per trust unit.

Our 2007 development capital spending totaled $387.2 million, resulting in the drilling of 252 net wells with a 99% success rate. On January 31, 2007 we acquired gross-overriding royalty interests in the Jonah natural gas field in Wyoming U.S. (“Jonah”) for approximately $61 million. In the second quarter we acquired the Kirby Oil Sands Partnership (“Kirby”), an operated Steam Assisted Gravity Drainage (“SAGD”) project, for $203.1 million ($148.3 million in cash and $54.8 million in equity). An equity offering consisting of 4.25 million trust units for gross proceeds of $210.6 million was also completed in conjunction with the Kirby acquisition.

During 2007 production averaged 82,319 BOE/day, in-line with our third quarter guidance of 82,500 BOE/day and 4% below our 2006 production of 85,779 BOE/day. Reduced development capital spending, unplanned downtime, lower initial production rates on our third well per section Bakken oil wells and natural reservoir declines are the primary reasons for the decrease.

On June 22, 2007 the Federal Government enacted a new tax on publicly traded income trusts and limited partnerships (specified investment flow-through entities, or “SIFTs”) effective January 1, 2011. As a result we recorded a $78.1 million future income tax expense. We are currently evaluating alternatives to determine the optimal structure for Enerplus post 2010 to maximize the return to investors. However, we see value in the remaining three-year tax exemption period through 2010 and currently look to maintaining our current structure during this period unless there are compelling reasons to change.  In the fourth quarter of 2007 the Alberta Government also announced proposed changes to the provincial royalty program effective January 1, 2009 which have not yet been enacted into law.

On February 13, 2008 we successfully closed the largest transaction in our 22 year history, acquiring Focus Energy Trust (“Focus”) for total consideration of $1.7 billion including approximately $340 million of assumed debt. Under the plan of arrangement, Focus unitholders received 0.425 of an Enerplus trust unit for each Focus trust unit. We believe the combined entity is well positioned for future growth with a strong balance sheet and production expected to be approximately 98,000 BOE/day in 2008.

HIGHLIGHTS

• Cash flow from operating activities totaled $868.5 million in 2007, essentially flat over 2006.

• Distributions have remained constant at $0.42 per trust unit for the past 28 months resulting in annual cash distributions of $5.04 per trust unit.

• Net income totaled $339.7 million, a decrease of $205.1 million from 2006.

• Our payout ratio increased slightly to 74% from 71%.

• Our price risk management program realized cash gains of $13.6 million or $0.45/BOE on our commodity financial contracts, an increase compared to cash losses of $34.3 million or $1.10/BOE in 2006.

• General and Administrative (“G&A”) expenses were $2.26/BOE, 6% lower than our guidance of $2.40/BOE and 18% higher than $1.91/BOE in 2006.

• Operating costs were $9.12/BOE for 2007, slightly below our third quarter guidance of $9.20/BOE and a year-over-year increase of 14%.

• On January 31, 2007 we acquired an overriding royalty interest in the Jonah field in Wyoming for total consideration of approximately $61.0 million.

• In the second quarter we acquired Kirby for a total purchase price of $203.1 million, consisting of $148.3 million in cash and $54.8 million in equity.

• In conjunction with the Kirby acquisition, on April 10, 2007 an equity offering was completed consisting of 4.25 million trust units raising gross proceeds of $210.6 million.

• Our development capital spending of $387.2 million was in-line with our guidance of $390.0 million and resulted in drilling of 252 net wells with a 99% success rate.

• Production averaged 82,319 BOE/day, in-line with our third quarter guidance of 82,500 BOE/day.

• Our proved plus probable finding, development and acquisition costs (“FD&A”) costs on our conventional oil and gas activities were $19.79/BOE for the year and when we include our oil sands activities, FD&A costs were $27.69/BOE.

• Reserve additions from development capital spending and acquisitions replaced 90% of 2007 production on a proved plus probable basis and 67% on a proved basis.

• Our conventional recycle ratio (operating income divided by FD&A) was 1.5x on a three-year basis and 1.6x for 2007 using proved plus probable reserves.

• We added 6.8 million barrels of probable reserves relating to our Joslyn steam assisted gravity drainage project.

• Proved plus probable reserves decreased 1% to 440.2 MMBOE and proved reserves decreased 3% to 289.9 MMBOE.

• Our Reserve Life Index (“RLI”) continued to be one of the longest in the sector at 14.8 years on a proved plus probable basis and 10.3 years on a proved basis, including both conventional and non-conventional reserves.

• On February 13, 2008 we acquired Focus creating an entity with a combined market capitalization of approximately $7.6 billion.

• In conjunction with the Focus acquisition we increased our bank credit facility from $1.0 billion to $1.4 billion on February 13, 2008.

• We continue to maintain a conservative balance sheet with a net debt to trailing 12 month cash flow ratio of 0.8x at December 31, 2007.

RESULTS OF OPERATIONS

Production

Production during 2007 averaged 82,319 BOE/day, in-line with our third quarter guidance of 82,500 BOE/day and 4% lower than 85,779 BOE/day in 2006. Our 2007 production was impacted by the fact that we spent $104 million or 21% less development capital than the prior year. In addition we experienced unexpected down time and turn-around activities at partner operated facilities. Our third well per section program at our U.S. Bakken property had lower initial production rates than originally forecast; however the program continues to deliver attractive economics and reserves. These decreases were partially offset by production from our acquisition of Jonah that closed January 31, 2007.

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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, 2007 and 2006 are outlined below:

Daily Production Volumes	2007		2006		% Change
Natural gas (Mcf/day)		262,254		270,972		(3	)%
Crude oil (bbls/day)		34,506		36,134		(5	)%
Natural gas liquids (bbls/day)		4,104		4,483		(8	)%
Total daily sales (BOE/day)		82,319		85,779		(4	)%

We exited the year with production of approximately 79,800 BOE/day based on December’s average production rate, 4% below our exit target of 83,000 BOE/day. Approximately 2,000 BOE/day of the decrease related to a previously announced fire that occurred at our Giltedge property on November 30, 2007. We expect production from this property to be back on-line by mid-2008. We have both business interruption insurance and property insurance which we anticipate will mitigate the majority of these losses. The remainder of the 1,200 BOE/day difference related to tie-in delays primarily on non-operated capital projects at year end and pipeline problems at our non-operated Mitsue property.

Considering our acquisition of Focus that closed on February 13, 2008 and our current development capital program, we expect 2008 annual production volumes to average 98,000 BOE/day, weighted 60% to natural gas and 40% to liquids. We expect to exit 2008 with production of approximately 100,000 BOE/day. This guidance does not contemplate any other 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 2007 with those of 2006. It also compares the benchmark price indices for the same periods.

Average Selling Price(1)	2007		2006		% Change
Natural gas (per Mcf)	$	6.45	$	6.81		(5	)%
Crude oil (per bbl)	$	65.11	$	61.80		5	%
Natural gas liquids (per bbl)	$	51.35	$	50.90		1	%
Per BOE	$	50.48	$	50.23		-	%

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

Average Benchmark Pricing	2007		2006		% Change
AECO natural gas - monthly index (CDN$/Mcf)	$	6.61	$	6.99		(5	)%
AECO natural gas - daily index (CDN$/Mcf)	$	6.45	$	6.53		(1	)%
NYMEX natural gas - monthly NX3 index (US$/Mcf)	$	6.92	$	7.26		(5	)%
NYMEX natural gas - monthly NX3 index: CDN$ equivalent (CDN$/Mcf)	$	7.44	$	8.25		(10	)%
WTI crude oil (US$/bbl)	$	72.34	$	66.22		9	%
WTI crude oil: CDN$ equivalent (CDN$/bbl)	$	77.78	$	75.25		3	%
CDN$/US$ exchange rate		0.93		0.88		6	%

Natural Gas

Natural gas prices started 2007 in a weak position due to a mild December 2006. However cold weather across key consuming regions of the United States from the latter part of January 2007 through to March resulted in increased prices. Early forecasts for an active hurricane season led to an expectation that strong prices would carry into and through the summer. However, this past year marked a changing dynamic in global liquefied natural gas (“LNG”) trade, with cargos more readily shifting between Asia, Europe, and North America depending on spot market prices and access to storage. Accordingly, low demand in Europe pushed significant volumes of LNG to North America from March through August. This LNG, along with continued strong North American production, resulted in high U.S. and Canadian storage balances by the end of the summer which depressed prices. Natural gas prices during the year traded within a band that saw highs of approximately $8.00/Mcf during the winter and lows of around $5.00/Mcf at the end of the summer injection season. This was a narrower band than was experienced during 2006 where natural gas prices fluctuated between $12.00/Mcf and $4.00/Mcf.

Our natural gas portfolio in 2007 was comprised of aggregator, AECO, and downstream direct sales. In 2007 we sold 40% of our natural gas on the daily AECO market and 40% on the monthly AECO market, as well as 20% against the day and month NYMEX indices. During 2007 we realized an average price for our natural gas sales of $6.45/Mcf (net of transportation costs), a decrease of 5% from $6.81/Mcf realized in 2006. This reduction is comparable to the price decreases realized in each of: the AECO monthly index which decreased by 5%; the AECO daily index which decreased by 1%; and the NYMEX monthly index (converted to CDN$/Mcf) which decreased by 10%.

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Natural Gas Prices

Crude Oil

Crude prices were weak in the first quarter of 2007, with a low of US$50.48/bbl. Prices rose steadily through the remaining months reaching a high of US$98.18/bbl in mid November. In terms of market fundamentals, OPEC kept its supply constant, non-OPEC production was lower than expected and growth demands in Asia remained strong. As a result, global crude and refined product inventories declined. In addition there was growing concern global production was reaching its peak. These fundamentals placed steady upward pressure on crude oil prices through the year.

Our crude oil portfolio in 2007 was approximately 74% light/medium and 26% heavy. The average price received for our crude oil (net of transportation costs) was CDN$65.11/bbl during 2007, a 5% increase over 2006. The West Texas Intermediate (“WTI”) crude oil benchmark price, after adjusting for the change in the US$ exchange rate, increased 3% year-over-year. On average for 2007, the slight narrowing of the light to heavy differential had a positive effect on our overall crude oil and gas sales. However, in the fourth quarter of 2007, and in particular in December, absolute heavy oil differentials to WTI widened significantly due to a number of factors, including: outages of refineries with heavy oil conversion capabilities; drawdown of inventories prior to year end; and operational issues on key intra-Alberta and export pipelines. These differentials reverted to historical levels in January 2008.

Crude Oil Prices

The Canadian dollar opened 2007 at an exchange rate of $0.86/US$ and strengthened throughout the year hitting a high in November of $1.09/US$ and ending the year at $0.99/US$. On average it strengthened 6% against the U.S. dollar during 2007 compared to 2006 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.

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Historically we have not attempted to hedge against fluctuations in the foreign exchange value of our oil and gas sales. In the fourth quarter of 2007 we entered into a foreign exchange swap on our US$54 million debentures which effectively fixed the principal repayments at a CDN/US dollar exchange rate of 1.02.

Price Risk Management

While we believe that the overall energy outlook remains generally bullish long term, the threat of a U.S. recession reducing demand for crude oil and natural gas requires prudent management of our commodity price exposure.

We have developed a price risk management framework to respond to the volatile price environment in a measured 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 and maintain participation in upside potential should commodity prices increase.

Consistent with our price risk management framework, we entered into additional commodity contracts during the fourth quarter of 2007 and during the first quarter of 2008. These contracts are designed to protect a portion of our natural gas sales for the period January 2008 through March 2009 and to protect a portion of our crude oil sales for the period January 2008 through December 2009. We have also hedged electricity volumes for the period January 2008 through December 2009 to protect against rising electricity costs in the Alberta power market. See Note 12 for a detailed list of our current price risk management positions including positions we assumed through the Focus acquisition.

The following is a summary of the financial contracts in place at February 20, 2008, including positions entered into by Focus, expressed as a percentage of our forecasted net production volumes:

	Natural Gas (CDN$/Mcf)									Crude Oil (US$/bbl)
	January 1, 2008 - March 31, 2008			April 1, 2008- October 31, 2008			November 1, 2008 - March 31, 2009			January 1, 2008 - June 30, 2008			July 1,  2008 - December 31, 2008			January 1, 2009 - December 31, 2009
Floor Prices (puts)	$	8.28		$	7.06		$	8.18		$	70.91		$	72.09		$	77.63
% (net of royalties)		18	%		24	%		4	%		35	%		35	%		10	%
Fixed Price (swaps)	$	8.73		$	7.16		$	-		$	79.95		$	79.97		$	-
% (net of royalties)		11	%		16	%		-	%		17	%		19	%		-	%
Capped Price (calls)	$	10.12		$	8.22		$	10.10		$	85.09		$	85.48		$	92.98
% (net of royalties)		19	%		24	%		4	%		23	%		22	%		10	%

Based on weighted average price (before premiums), estimated average annual production of 98,000 BOE/day and assuming a 19% royalty rate.

Accounting for Price Risk Management

During 2007, our commodity price risk management program generated cash gains of $23.6 million on our natural gas contracts and cash losses of $10.0 million on our crude oil contracts. The natural gas cash gains are due to contracts in place during 2007 that provided floor protection as the price of natural gas declined. The crude oil cash losses are due to crude oil prices rising above our swap positions. In comparison, our 2006 commodity price risk management program resulted in cash losses of $7.1 million on our natural gas contracts and $27.2 million on our crude oil contracts.

At December 31, 2007 the fair value of our natural gas and crude oil derivative instruments, net of premiums, represents a gain of $9.7 million and a loss of $52.5 million, respectively. The natural gas gain is recorded as a current deferred financial asset on our balance sheet and the crude oil loss is recorded as a current deferred financial credit. In comparison, at December 31, 2006 the fair value of our natural gas and crude oil derivative instruments represented gains of $12.7 million and $10.9 million respectively, both of which were recorded on our balance sheet as deferred financial assets. The change in the fair value of these financial contracts year-over-year resulted in unrealized losses of $3.0 million for natural gas and $63.4 million for crude oil. 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 non-cash gain in earnings. See Note 3 for details.

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The following table summarizes the effects of our financial contracts on income for the years ended December 31, 2007 and 2006.

Risk Management Costs
($ millions, except per unit amounts)	2007					2006
Cash gains/(losses):
Natural gas	$	23.6		$	0.25/Mcf	$	(7.1	)	$	(0.07)/Mcf
Crude oil		(10.0	)	$	(0.79)/bbl		(27.2	)	$	(2.06)/bbl
Total cash gains/(losses)	$	13.6		$	0.45/BOE	$	(34.3	)	$	(1.10)/BOE
Non-cash (losses)/gains on financial contracts:
Change in fair value - natural gas	$	(3.0	)	$	(0.03)/Mcf	$	50.6		$	0.51/Mcf
Change in fair value - crude oil		(63.4	)	$	(5.03)/bbl		30.4		$	2.30/bbl
Amortization of deferred financial assets		-		$	- /BOE		(49.9	)	$	(1.59)/BOE
Total non-cash (losses)/gains	$	(66.4	)	$	(2.21)/BOE	$	31.1		$	0.99/BOE
Total (losses)	$	(52.8	)	$	(1.76)/BOE	$	(3.2	)	$	(0.11)/BOE

Cash Flow Sensitivity

The sensitivities below reflect all commodity contracts as described in Note 12 (including those entered into by Focus) and are based on 2008 forward markets as at February 20, 2008. 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.

Sensitivity Table	Estimated Effect on 2008 Cash Flow per Trust Unit (1)
Change of $0.15 per Mcf in the price of AECO natural gas	$	0.08
Change of US$1.00 per barrel in the price of WTI crude oil	$	0.06
Change of 1,000 BOE/day in production	$	0.10
Change of $0.01 in the US$/CDN$ exchange rate	$	0.12
Change of 1% in interest rate	$	0.07

(1) Assumes constant working capital and 129,813,000 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, 2007 were $1,517.1 million ($1,539.2 million, net of $22.1 million of transportation costs), a decrease of 4% or $55.6 million compared to $1,572.7 million ($1,595.3 million, net of $22.6 million of transportation costs) during 2006. Decreased production and lower natural gas prices were partially offset by an increase in realized crude oil prices.

Analysis of Sales Revenue(1)($ millions)	Crude oil			NGLs			Natural Gas			Total
2006 Sales Revenue	$	815.0		$	83.3		$	674.4		$	1,572.7
Price variance(1)		41.8			0.7			(33.8	)		8.7
Volume variance		(36.7	)		(7.1	)		(20.5	)		(64.3	)
2007 Sales Revenue	$	820.1		$	76.9		$	620.1		$	1,517.1

(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. Royalties in 2007 and 2006 were approximately 19% of oil and gas sales, net of transportation costs. Overall, royalties decreased marginally in 2007 to $285.1 million compared to $296.6 million during 2006 primarily as a result of the decrease in natural gas revenue experienced over the period.

We expect royalties to be approximately 19% of oil and gas sales, net of transportation costs for 2008.

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Alberta Royalty Review

On October 25, 2007 the Alberta government announced the 'New Royalty Framework' ("NRF"), an updated royalty regime proposed to be effective January 1, 2009 which is intended to increase Government royalty revenue by 20%.  On conventional oil and gas production during 2007, Alberta Crown royalties were $122.1 million (43%) of our total royalties. Based on this royalty rate and in the context of our production and pricing experienced during 2007, we estimate that the NRF would have increased the royalties on our conventional production by approximately $15 to $20 million. The acquisition of Focus in 2008 will help to mitigate the effects of the Alberta royalty review as the production from Focus is concentrated in Saskatchewan and British Columbia.

The moderate royalty increase is a reflection of the NRF's sensitivity to our portfolio, which includes lower productivity wells combined with the low natural gas prices experienced in 2007. It is important to note that this context may not be indicative of the environment in 2009 when the NRF comes into effect. The fundamental design of the new Alberta regime (which increases royalty rates as commodity prices increase) has removed some of the price upside producers had previously factored into their risk assessments for capital investment. As a result, Alberta will not be as attractive to invest in as other jurisdictions that allow greater participation in price upside.

The Alberta government is currently working with industry to address "unintended consequences" of economic issues related to the NRF and as at the date of this MD&A the Alberta government had not yet made the necessary legislative and administration changes to implement the NRF. The NRF announcement can be found on the Alberta government’s website at www.gov.ab.ca.

Operating Expenses

Operating expenses during 2007 were $9.12/BOE or $274.2 million, representing a 1% decrease from our third quarter guidance of $9.20/BOE and a 14% increase from $8.02/BOE in 2006. Operating expenses for the year were lower than our guidance primarily due to lower than expected electricity charges during the fourth quarter. The increase in operating costs over 2006 was due to the combination of increased labour, well servicing, and repairs and maintenance costs along with lower production volumes during 2007. A field training initiative in 2007 directed at optimizing production and reducing the time required to drill, complete and bring new wells on stream also contributed to the year-over-year increase.

By combining the lower cost operating expenses associated with the Focus properties we expect operating costs for 2008 to average $8.65/BOE, representing a decrease of 5% per BOE compared to 2007.

General and Administrative Expenses (“G&A”)

G&A expenses were $2.26/BOE or $67.9 million for the year ended December 31, 2007, approximately 6% lower than our guidance of $2.40/BOE and 18% higher than $1.91/BOE in 2006.  G&A expenses were lower than our guidance primarily due to lower than anticipated long term cash compensation charges related to our performance trust unit plan (“PTU”) which is impacted by our trust unit price. The increase in general and administrative costs over 2006 was mainly due to increased overall salary and benefits as a result of continued wage inflation, increased staff and lower production volumes during 2007.

For the year ended December 31, 2007 our G&A expenses included non-cash charges for our trust unit rights incentive plan of $8.4 million or $0.28/BOE compared to $6.3 million or $0.20/BOE for 2006. These amounts relate solely to our trust unit rights incentive plan and are determined using a binomial lattice option-pricing model. The volatility of our trust unit price combined with the increased number of rights outstanding associated with additional employees increased the non-cash cost of the plan. Although non-cash charges have increased as a result of the option pricing model, the proportion of rights that are “in-the-money” has decreased in comparison with 2006. See Note 10 for further details.

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

General and Administrative Costs ($ millions)	2007		2006
Cash	$	59.5	$	53.6
Trust unit rights incentive plan (non-cash)		8.4		6.3
Total G&A	$	67.9	$	59.9

(Per BOE)	2007		2006
Cash	$	1.98	$	1.71
Trust unit rights incentive plan (non-cash)		0.28		0.20
Total G&A	$	2.26	$	1.91

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In 2008 we expect total G&A costs to decrease slightly to approximately $2.20/BOE, including non-cash G&A costs of approximately $0.20/BOE.

Interest Expense

With the adoption of the new accounting standards on January 1, 2007 interest expense includes interest on long-term debt, the premium amortization on our US$175 million senior unsecured notes, unrealized gains and losses resulting from the change in fair value of our interest rate swaps as well as the interest component on our cross currency interest rate swap (see Note 8).

Interest on long-term debt during 2007 totaled $41.9 million, a $9.7 million increase from $32.2 million in 2006. The increase was due to higher average indebtedness and a higher weighted average interest rate of 5.1% during 2007 compared to 4.8% in 2006.

The following table summarizes the cash and non-cash interest expense recorded.

Interest Expense ($ millions)	2007			2006
Interest on long-term debt	$	41.9		$	32.2
Unrealized gain		(8.3	)		-
Total Interest Expense	$	33.6		$	32.2

At December 31, 2007 approximately 18% of our debt was based on fixed interest rates while 82% had floating interest rates.

Capital Expenditures

During 2007 we spent $387.2 million on development capital and facilities, which is $104.0 million or 21% less than 2006. Spending in 2007 was in-line with our guidance of $390.0 million. Development capital spending was lower in 2007 as we spent less on natural gas development due to decreasing natural gas prices and increasing drilling and servicing costs. Development in 2007 focused primarily on Bakken oil and waterfloods. We achieved a 99% success rate with our drilling program on 252 net wells drilled during 2007.

Property acquisitions were $274.2 million during 2007 compared to $51.3 million in 2006. The majority of our 2007 acquisitions related to the purchase of Kirby for total consideration of $203.1 million and the purchase of gross-overriding royalty interests in the Jonah area for approximately $61.0 million. Property dispositions were $9.6 million during 2007 compared to $21.1 million in 2006. Our 2007 divestments included $5.6 million of property interests in the Thorhild area and the sale of 36,000 net acres of undeveloped land in North Dakota for approximately $3.6 million. Divestments in 2006 primarily related to the $19.7 million sale of a 1% working interest in the Joslyn property.

Capital Expenditures ($ millions)	2007			2006
Development expenditures	$	321.3		$	380.5
Plant and facilities		65.9			110.7
Development Capital		387.2			491.2
Office		6.5			5.0
Sub-total		393.7			496.2
Acquisitions of oil and gas properties(1)		274.2			51.3
Dispositions of oil and gas properties(1)		(9.6	)		(21.1	)
Total Net Capital Expenditures	$	658.3		$	526.4
Total Capital Expenditures financed with cash flow	$	221.7		$	249.4
Total Capital Expenditures financed with debt and equity		443.2			296.5
Total non-cash consideration for property dispositions		(6.6	)		(19.5	)
Total Net Capital Expenditures	$	658.3		$	526.4

(1)Net of post-closing adjustments.

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The following is a summary by play type of our development capital expenditures during 2007 and 2006, as well as our current expectations for 2008 including Focus.

Play type ($ millions)	2008 Estimate		2007		2006
Shallow Gas and CBM	$	128	$	39.3	$	94.0
Crude Oil Waterfloods		105		54.2		66.0
Deep Tight Gas		53		34.7		34.1
Bakken Oil		47		106.2		116.7
Other Conventional Oil and Gas		142		113.9		141.3
Oil Sands		105		38.9		39.1
Total	$	580	$	387.2	$	491.2

We currently expect total development capital expenditures in 2008 to be approximately $580 million. Conventional development capital is presently anticipated to be approximately $475 million with a slight bias to oil related projects over natural gas projects. Oil sands development capital is currently projected to be approximately $105 million.

Oil Sands

Our Joslyn and Kirby development projects have not commenced commercial production. As a result all associated costs, net of revenues generated, are capitalized and excluded from our depletion calculation. During 2007 we capitalized costs of $35.2 million on Joslyn and $205.4 million on Kirby, inclusive of acquisition costs, development capital spending, salaries and benefits, engineering and planning. At December 31, 2007 capitalized costs life-to-date for Joslyn were $116.4 million and for Kirby were $205.4 million for a combined total of $321.8 million.

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, 2007 DDA&A of $15.43/BOE is comparable to $15.38/BOE during the year ended December 31, 2006.

No impairment existed at December 31, 2007 using year-end reserves and management’s estimates of future prices. Our future price estimates are more fully discussed in Note 4.

Asset Retirement Obligations

We have estimated our total future asset retirement obligations based on our net ownership interest in wells and facilities, along with the estimated cost and timing to abandon and reclaim wells and facilities in future periods. Our asset retirement obligation was $165.7 million at December 31, 2007 compared to $123.6 million at December 31, 2006. The majority of the $42.1 million increase was due to increased cost estimates as a result of enhanced regulatory requirements on abandonment and reclamation activities. The remainder of the change was due to retirement costs incurred, offset by accretion expense for the year. See Note 5 for further details.

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

($ millions)	2007		2006
Amortization of the asset retirement cost	$	11.4	$	12.6
Accretion of the asset retirement obligation		6.7		6.2
Total Amortization and Accretion	$	18.1	$	18.8
Asset Retirement Obligations Settled	$	16.3	$	11.5

Actual asset retirement costs are incurred at different times compared to the recording of amortization and accretion charges. Actual asset retirement costs will be incurred over the next 66 years with the majority between 2038 and 2047. For accounting purposes, the asset retirement cost is amortized using a unit-of-production method based on proved reserves before royalties while the asset retirement obligation accretes until the time the obligation is settled.

Taxes

Canadian Government’s tax changes

On June 22, 2007 Bill C-52, which contained legislative provisions to implement the proposals to tax publicly traded income trusts in Canada became law. As a result, our second quarter future income tax provision included a future income tax expense of $78.1 million related to this legislation. This non-cash expense related to temporary differences between the accounting and tax basis of the Fund’s assets and liabilities at that time and had no immediate impact on cash flow.

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On December 14, 2007, Bill C-28, which contained legislative provisions to implement corporate income tax rate reductions announced in the October 30, 2007 fall economic statement, became law. The general corporate tax rate will decrease by 1.0% in 2008 from 20.5% to 19.5%. There are additional rate reductions scheduled until the target federal tax rate of 15.0% is reached as of January 1, 2012. These rate reductions will also apply to the SIFT tax on income trusts. As a result, our fourth quarter future income tax provision includes a future income tax recovery of $22.6million related to this legislation.

Future Income Taxes

Future income taxes arise from differences between the accounting and tax basis of assets and liabilities. A portion of the future income tax liability that is recorded on the balance sheet will be recovered through earnings before 2011. The balance will be realized when future income tax assets and liabilities are realized or settled.

As a result of the SIFT tax, all entities within our organization are now subject to future income taxes whereas prior to the SIFT tax enactment only incorporated entities in our organization were subject to future income taxes. As a result our future income tax recovery was $1.0 million for the year ended December 31, 2007 compared to a recovery of $112.0 million for the same period in 2006. The changes in future income taxes compared to 2006 are primarily a result of the following:

• The SIFT tax resulted in a future income tax expense of $78.1 million in the second quarter of 2007; and

• Corporate income tax rate changes enacted during the year have resulted in a year-to-date future tax recovery of $22.6 million compared to a $35.5 million recovery in 2006.

After consideration of the above items, the future income tax provisions were comparable between the periods.

Current Income Taxes

In our current structure, payments are made between the operating entities and the Fund which ultimately transfers both income and future income tax liability to our unitholders. As a result, no cash income taxes have been paid by our Canadian operating entities. However, effective January 1, 2011 we will be subject to the SIFT tax should we remain a trust.

The amount of current taxes recorded throughout the year on our U.S. operations is dependent upon the timing of both capital expenditures and repatriation of the funds to Canada. Our U.S. taxes as a percentage of cash flow, assuming constant working capital, were 11% in 2007 compared to our guidance of 10%. We expect the current income and withholding taxes to average approximately 20% of cash flow from U.S. operations in 2008 based on our current development capital program and assuming all funds are repatriated to Canada after U.S. development capital spending. The increase for 2008 is a result of plans for reduced development capital spending in the U.S. during the year.

During 2007 our U.S. operations incurred income related taxes in the amount of $23.0 million compared to $18.2 million in 2006. The increase in current taxes is due to an increase in net income combined with a modest decrease in drilling and completion expenditures for the year.

Tax Pools

We estimate our tax pools at December 31, 2007 to be as follows:

Pool Type ($ millions)	Trust		Operating entities		Total
COGPE	$	470	$	100	$	570
CDE		-		340		340
UCC		-		600		600
Tax losses and other		30		600		630
Foreign tax pools		-		140		140
Total	$	500	$	1,780	$	2,280

We acquired approximately $200 million in tax pools related to the Focus acquisition (net of any pools required to offset partnership deferrals).

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Net Income

Net income in 2007 was $339.7 million or $2.66 per trust unit compared to $544.8 million or $4.48 per trust unit in 2006. The $205.1 million decrease in net income was primarily due to a $111.0 million decrease in future income tax recovery, a $49.6 million increase in cash and non-cash risk management costs, a $55.6 million decrease in oil and gas sales (net of transportation costs) and a $22.9 million increase in operating costs, partially offset by an increase in other income of $12.5 million and decreased DDA&A charges of $17.9 million.

Cash Flow from Operating Activities

Cash flow from operating activities in 2007 was $868.5 million or $6.80 per trust unit compared to $863.7 million or $7.10 per trust unit in 2006. The decrease on a per unit basis is largely due to the April 2007 equity offering, which was primarily used to purchase Kirby, a development project that is not currently generating cash flow.

Selected Financial Results

	Year ended December 31, 2007									Year ended December 31, 2006
Per BOE of production (6:1)	Operating Cash Flow(1)			Non-Cash & Other Items			Total			Operating Cash Flow(1)			Non-Cash & Other Items			Total
Production per day								82,319									85,779
Weighted average sales price (2)	$	50.48		$	-		$	50.48		$	50.23		$	-		$	50.23
Royalties		(9.49	)		-			(9.49	)		(9.47	)		-			(9.47	)
Commodity derivative instruments		0.45			(2.21	)		(1.76	)		(1.10	)		0.99			(0.11	)
Operating costs		(9.11	)		(0.01	)		(9.12	)		(8.02	)		-			(8.02	)
General and administrative		(1.98	)		(0.28	)		(2.26	)		(1.71	)		(0.20	)		(1.91	)
Interest expense, net of interest income		(1.37	)		0.28			(1.09	)		(0.95	)		-			(0.95	)
Foreign exchange gain / (loss)		(0.06	)		0.30			0.24			0.02			-			0.02
Current income tax		(0.77	)		-			(0.77	)		(0.59	)		-			(0.59	)
Restoration and abandonment cash costs		(0.54	)		0.54			-			(0.37	)		0.37			-
Depletion, depreciation, amortization and accretion		-			(15.43	)		(15.43	)		-			(15.38	)		(15.38	)
Future income tax (expense) / recovery		-			0.04			0.04			-			3.58			3.58
Marketable securities(3)		-			0.47			0.47			-			-			-
Total per BOE	$	27.61		$	(16.30	)	$	11.31		$	28.04		$	(10.64	)	$	17.40

(1) Cash Flow from Operating Activities before changes in non-cash operating working capital.

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

(3) In addition to non-cash shares of marketable securities, a gain on sale of marketable securities was a cash item; however the cash item is included in cash flow from investing activities not cash flow from operating activities.

Selected Annual Canadian and U.S. Financial Results

The following table provides a geographical analysis of key operating and financial results for 2007 and 2006.

	Year ended December 31, 2007									Year ended December 31, 2006
(CDN$ millions, except per unit amounts)	Canada			U.S.			Total			Canada			U.S.			Total
Daily Production Volumes
Natural gas (Mcf/day)		251,561			10,693			262,254			265,019			5,953			270,972
Crude oil (bbls/day)		24,590			9,916			34,506			25,858			10,276			36,134
Natural gas liquids (bbls/day)		4,104			-			4,104			4,483			-			4,483
Total daily sales (BOE/day)		70,621			11,698			82,319			74,511			11,268			85,779
Pricing (1)
Natural gas (per Mcf)	$	6.45		$	6.55		$	6.45		$	6.79		$	7.78		$	6.81
Crude oil (per bbl)	$	62.27		$	72.17		$	65.11		$	59.36		$	67.93		$	61.80
Natural gas liquids (per bbl)	$	51.35		$	-		$	51.35		$	50.90		$	-		$	50.90
Capital Expenditures
Development capital and office	$	287.3		$	106.4		$	393.7		$	378.5		$	117.7		$	496.2
Acquisitions of oil and gas properties	$	213.3		$	60.9		$	274.2		$	35.3		$	16.0		$	51.3
Dispositions of oil and gas properties	$	(6.0	)	$	(3.6	)	$	(9.6	)	$	(21.1	)	$	-		$	(21.1	)
Revenues
Oil and gas sales (1)	$	1,230.4		$	286.7		$	1,517.1		$	1,301.0		$	271.7		$	1,572.7
Royalties	$	(226.4	)	$	(58.7	) (2)	$	(285.1	)	$	(244.4	)	$	(52.2	) (2)	$	(296.6	)
Commodity derivative instruments	$	(52.8	)	$	-		$	(52.8	)	$	(3.2	)	$	-		$	(3.2	)
Expenses
Operating	$	264.4		$	9.8		$	274.2		$	243.8		$	7.4		$	251.2
General and administrative	$	62.6		$	5.3		$	67.9		$	51.4		$	8.5		$	59.9
Depletion, depreciation, amortization and accretion	$	359.8		$	103.9		$	463.7		$	369.6		$	112.0		$	481.6
Current income taxes	$	-		$	23.0		$	23.0		$	-		$	18.2		$	18.2

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

(2)           Royalties include U.S. state production tax.

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Three Year Summary of Key Measures

Overall, lower production volumes have resulted in lower oil and gas sales and net income during 2007 as compared to 2006. The rise in crude oil prices during 2005, 2006 and 2007 contributed to higher oil and gas sales, however sales moderated in 2007 as a result of lower natural gas prices and production. The following table provides a summary of net income, cash flow and other key measures.

($ millions, except per unit amounts)	2007			2006			2005
Oil and gas sales(1)	$	1,517.1		$	1,572.7		$	1,523.7
Net income		339.7			544.8			432.0
Per unit (Basic) (2)		2.66			4.48			3.96
Per unit (Diluted)		2.66			4.47			3.95
Cash flow from operating activities		868.5			863.7			774.6
Per unit (Basic) (2)		6.80			7.10			7.10
Cash distributions		646.8			614.3			498.2
Per unit (Basic) (2)		5.07			5.05			4.57
Payout ratio		74	%		71	%		64	%
Total assets		4,303.1			4,203.8			4,130.6
Long-term debt, net of cash		725.0			679.7			649.8

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

(2) Based on weighted average trust units outstanding. Cash distributions to unitholders per unit will not correspond to actual distributions as a result of using the annual weighted average trust units outstanding.

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Liquidity and Capital Resources

Sustainability of our Distributions and Asset Base

As an oil and gas producer we have a declining asset base and therefore rely on ongoing development activities and acquisitions to replace production and add additional reserves. Our future oil and natural gas production is highly dependent on our success in exploiting our asset base and acquiring or developing additional reserves. To the extent we are unsuccessful in these activities our cash distributions could be reduced.

Development activities and acquisitions may be funded internally by withholding a portion of cash flow or through external sources of capital such as debt or the issuance of equity. To the extent that we withhold cash flow to finance these activities, the amount of cash distributions to our unitholders may be reduced. Should external sources of capital become limited or unavailable, our ability to make the necessary development expenditures and acquisitions to maintain or expand our asset base may be impaired and ultimately reduce the amount of cash distributions.

Following the completion of the Focus acquisition, Enerplus has approximately $10 billion of safe harbor growth capacity within the context of the Government’s “normal growth” guidelines associated with Bill C-52. This amount is calculated in reference to the combined market capitalizations of Enerplus and Focus on October 31, 2006 and also includes equity that may be issued to replace existing debt of both entities at that time.

Distribution Policy

The amount of cash distributions is proposed by management and approved by the Board of Directors. We continually assess distribution levels with respect to forecasted cash flows, debt levels and capital spending plans. The level of cash withheld has historically varied between 10% and 40% of annual cash flow from operating activities and is dependent upon numerous factors, the most significant of which are the prevailing commodity price environment, our current levels of production, debt obligations, our access to equity markets and funding requirements for our development capital program.

Although we intend to continue to make cash distributions to our unitholders, these distributions are not guaranteed. To the extent there is taxable income at the trust level, determined in accordance with the Canadian Income Tax Act, the distribution of that taxable income is non-discretionary.

Cash Flow from Operating Activities, Cash Distributions and Payout Ratio

Cash flow from operating activities and cash distributions are reported on the Consolidated Statements of Cash Flows. During 2007 cash distributions of $646.8 million were funded entirely through cash flow of $868.5 million. Our payout ratio, which is calculated as cash distributions divided by cash flow, was 74% for 2007 compared to 71% in 2006.

Our cash outlays in 2007 were comprised of: $646.8 million of distributions to unitholders, $393.7 million of development capital and office expenditures, and $209.8 million of acquisitions (net of dispositions) for a total of $1,250.3 million. These cash outlays were financed with a combination of: $868.5 million from cash flow from operating activities, $199.6 million from the equity issue, $56.8 million from our distribution reinvestment plan and trust unit rights incentive plan and an increase in our credit facility of $148.8 million.

In aggregate, our 2007 cash distributions of $646.8 million and our development capital and office of $393.7 million totaled $1,040.5 million, or approximately 120% of our cash flow of $868.5 million. We rely on access to capital markets to the extent cash distributions and development capital exceeds cash flow. Over the long term we would expect to support our distributions and capital expenditures with our cash flow, however we would continue to fund acquisitions and growth through additional debt and equity. There will be years when we are investing capital in opportunities that do not immediately generate cash flow (such as our Joslyn and Kirby oil sands projects) where this relationship will vary. Despite our 2007 cash flow being less than the aggregate of our cash distributions and development capital, we continue to have conservative debt levels with a trailing twelve month debt-to-cash flow ratio of 0.8x at December 31, 2007.

For the year ended December 31, 2007 our cash distributions exceeded our net income by $307.1 million (2006 - $69.5 million). Net income includes $520.3 million of non-cash items (2006 - $344.7 million) such as DDA&A, changes in the fair value of our derivative instruments, and future income taxes that do not reduce our cash flow from operations. Future income taxes can fluctuate from period to period as a result of changes in tax rates (such as the enactment of the SIFT tax during the second quarter of 2007), changes in the inter-company royalty, interest and dividends from our operating subsidiaries paid to the Fund. In addition, other non-cash charges such as DDA&A are not a good proxy for the cost of maintaining our productive capacity as they are based on the historical costs of our PP&E and not the fair market value of replacing those assets within the context of the current environment.

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The level of investment in a given period may not be sufficient to replace productive capacity given the natural declines associated with oil and natural gas assets. In these instances a portion of the cash distributions paid to unitholders may represent a return of the unitholders’ capital.

The following table compares cash distributions to cash flow and net income.

($ millions, except per unit amounts)	2007			2006			2005
Cash flow  from operating activities	$	868.5		$	863.7		$	774.6
Cash Distributions		646.8			614.3			498.2
Excess of cash flow over cash distributions	$	221.7		$	249.4		$	276.4
Net income	$	339.7		$	544.8		$	432.0
Shortfall of net income over cash distributions	$	(307.1	)	$	(69.5	)	$	(66.2	)
Cash distributions per weighted average trust unit	$	5.07		$	5.05		$	4.57
Payout ratio (1)		74	%		71	%		64	%

 (1)   Based on cash distributions divided by cash flow from operating activities.

It is not possible to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities in the oil and gas sector due to the nature of reserve reporting, natural reservoir declines and the risks involved with capital investment. Therefore we do not disclose maintenance capital separately from development capital spending.

Asset Retirement Costs

Actual asset retirement costs incurred in the period are deducted for purposes of calculating cash flow. Differences between actual asset retirement costs incurred and the amortization and accretion of the asset retirement obligation are discussed in the Asset Retirement Obligations section of the MD&A and Note 5.

Long-Term Debt

Long-term debt at December 31, 2007 was $726.7 million, an increase of $46.9 million from $679.8 million at December 31, 2006. Long-term debt at December 31, 2007 is comprised of $497.3 million of bank indebtedness, which increased $148.8 million from prior year and $229.3 million of senior unsecured notes. With the adoption of the financial instrument accounting standards (see Note 2) on January 1, 2007 we adjusted the carrying value of our US$175 million senior unsecured notes to fair value of $208.2 million from their previous carrying value of $268.3 million, a decrease of $60.1 million. Subsequent to this adoption entry, our $175 million senior notes have decreased a further $32.2 million as a result of the strengthening Canadian dollar. Increases in long-term debt resulting from the Jonah and Kirby acquisitions along with our development capital program more than offset decreases resulting from the April 2007 equity issue and the foreign exchange impact of the strengthening Canadian dollar on our U.S. dollar denominated senior notes.

In the fourth quarter of 2007 we extended our bank credit facility by one year to November 2010 and increased the facility size to $1.0 billion. Subsequent to December 31, 2007, in conjunction with the Focus acquisition, we increased the bank credit facility size to $1.4 billion. On February 13, 2008 an additional $340 million was drawn on the bank credit facility to settle outstanding indebtedness of Focus.

Our working capital, excluding cash, at December 31, 2007 decreased $73.2 million compared to December 31, 2006. Excluding deferred financial assets and credits, working capital decreased $7.3 million compared to the prior year. This is primarily due to lower accounts receivable in 2007 as a result of lower sales in December 2007 compared to 2006.

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

Financial Leverage and Coverage	Year ended Dec. 31, 2007			Year ended Dec. 31, 2006
Long-term debt to trailing cash flow		0.8	x		0.8	x
Cash flowto interest expense		25.8	x		26.8	x
Long-term debt to long-term debt plus equity		22	%		20	%

Long-term debt is measured net of cash.

Cash flow and interest expense are 12-months trailing.

Enerplus currently has a $1.4 billion ($1.0 billion at December 31, 2007) unsecured covenant based three-year term bank facility ending November 2010, through its wholly-owned subsidiary EnerMark Inc. We have the ability to extend the facility each year or repay the entire balance at the end of the three-year term. This bank debt carries floating interest rates that we expect to range between 55.0 and 110.0 basis points over Bankers’ Acceptance rates, depending on Enerplus’ ratio of senior debt to earnings before interest, taxes and non-cash items.

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 default or fail to comply with certain covenants, the ability of the Fund’s operating subsidiaries to make payments to the Fund and consequently the Fund’s ability to make distributions to the unitholders may be restricted. At December 31, 2007 we are in compliance with our debt covenants, the most restrictive of which limits our long-term debt to three times trailing cash flow reflecting acquisitions on a pro forma basis. Refer to “Debt of Enerplus” in our Annual Information Form for the year ended December 31, 2006 for a detailed description of these covenants.

Principal payments on Enerplus’ senior unsecured notes are required commencing in 2010 and 2011 and are more fully discussed in Note 7.

We anticipate that we will continue to have adequate liquidity to fund planned development capital spending during 2008 through a combination of cash flow retained by the business and debt.

Commitments

Enerplus has contracted to transport 104 MMcf/day of natural gas on the Nova system in the province of Alberta as well as 20 MMcf/day of natural gas on various pipelines to the U.S. midwest. Enerplus also has a contract to transport a minimum of 2,480 bbls/day of crude oil from field locations to suitable marketing sales points within western Canada.

Including Focus, approximately 24% of our current gas production is dedicated to 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.

In 2007 we extended our Canadian office lease commitments. Our Canadian and U.S. leases now expire in 2014 and 2011, respectively. Annual costs of these lease commitments, include rent and operating fees. The Fund’s commitments, contingencies and guarantees are more fully described in Note 13.

As at December 31, 2007 Enerplus has the following minimum annual commitments including long-term debt:

				Minimum Annual Commitment Each Year										Total
														Committed
														after
($ millions)	Total			2008		2009		2010		2011		2012		2012
Bank credit facility	$	497.3	(1)	$	-	$	-	$	497.3	$	-	$	-	$	-
Senior unsecured notes		323.4	(1) (2)		-		-		53.7		64.7		64.7		140.3
Pipeline commitments		31.1			10.0		5.9		4.0		2.8		2.4		6.0
Office lease		67.9			6.9		7.6		10.3		10.8		11.1		21.2
Total commitments (3)	$	919.7		$	16.9	$	13.5	$	565.3	$	78.3	$	78.2	$	167.5

(1) Interest payments have not been included since future debt levels and interest rates are not known at this time.

(2) Includes the economic impact of derivative instruments directly related to the senior unsecured notes (CCIRS and foreign exchange swap - see Note 12).

(3) Crown and surface royalties, lease rentals, mineral taxes, and abandonment and reclamation costs (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment.

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Not reflected in the above schedule are those term contracts for transportation and the office lease that Enerplus assumed upon the completion of the Focus acquisition. The Focus term transportation contracts consist of 45 MMcf/day of natural gas in British Columbia, and 60 MMcf/day of natural gas in Saskatchwan.

Accumulated Deficit

We have historically paid cash distributions in excess of accumulated earnings as cash distributions are based on cash flow generated in the period whereas accumulated earnings are based on net income which includes non-cash items such as DDA&A charges, derivative instrument mark-to-market gains and losses, unit based compensation charges, future income tax provisions and non-cash charges resulting from the adoption of the financial instrument accounting standards (see Note 2).

Trust Unit Information

We had 129,813,000 trust units outstanding at December 31, 2007 compared to 123,151,000 trust units at December 31, 2006. The weighted average number of trust units outstanding during 2007 was 127,691,000 (2006 - 121,588,000). At February 20, 2008 we had 160,022,000 trust units outstanding, which reflects the additional trust units issued to acquire Focus, and 9,087,000 exchangeable partnership units outstanding that were assumed with the Focus acquisition and are convertible at the option of the holder into 0.425 of an Enerplus trust unit (3,862,000 trust units).

On April 10, 2007 in conjunction with the acquisition of Kirby we issued 1,105,000 trust units as part of the purchase price consideration representing $54.8 million and also closed a public offering of 4,250,000 trust units for net proceeds of $199.6 million.

In addition 1,307,000 trust units (2006 - 1,242,000) were issued pursuant to the Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan (“DRIP”) and the trust unit rights incentive plan, net of redemptions. This resulted in $56.8 million (2006 - $55.9 million) of additional equity to the Fund.

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, as well as consider the Government’s proposal to implement a tax on trusts.

Canadian Unitholders

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 has historically transferred all of its taxable income to the unitholders by way of distributions.

In computing income, unitholders are required to include the taxable portion of distributions received 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 $5.04 per trust unit in cash distributions to unitholders on record during 2007. For Canadian tax purposes, approximately 2% of these distributions, or $0.12 per trust unit was a tax deferred return of capital, approximately 98% or $4.92 per trust unit was taxable to unitholders as other income, and there was no eligible dividend income.

For 2008, we estimate that 95% of cash distributions will be taxable and 5% will be a tax deferred return of capital. Actual taxable amounts may vary depending on actual distributions which are dependent upon, among other things, production, commodity prices and cash flow experienced throughout the year.

U.S. Unitholders

U.S. unitholders who received cash distributions were subject to at least a 15% Canadian withholding tax. The withholding tax is applied to both the taxable portion of the distribution as computed under Canadian tax law and the non-taxable portion of the distribution. U.S. taxpayers may be eligible for a foreign tax credit with respect to Canadian withholding taxes paid.

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For U.S. taxpayers the taxable portion of cash distributions are 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. This preferential rate of tax for "Qualified Dividends" is set to expire at the end of 2010. On March 24, 2007, Bill 1672 was introduced into the U.S. House of Representatives which, if enacted as presented, would make dividends from Canadian income funds such as Enerplus ineligible for treatment as a "Qualified Dividend". The dividends would then become a "non-qualified dividend from a foreign corporation" subject to the normal rates of tax commencing with dividends received after the date of enactment. The proposed bill still requires the approval of the House of Representatives, the Senate and the President prior to it being enacted. Therefore, we are unable to determine when or even if the bill will become enacted as presented.

We paid US$4.71 per trust unit to U.S. residents during the 2007 calendar year of which 7% or US$0.33 per trust unit was a tax deferred return of capital and 93% or US$4.38 per unit was a taxable qualified dividend.

For 2008, we estimate that 90% of cash distributions will be taxable to most U.S. investors and 10% will be a tax deferred return of capital. Actual taxable amounts may vary depending on actual distributions which are dependent upon production, commodity prices and cash flow experienced throughout the year.

Quarterly Financial Information

In general, oil and gas sales have been decreasing since the first quarter of 2006 due mainly to lower natural gas prices and lower production. Sales increased slightly in the fourth quarter of 2007 due to higher crude oil prices.

Net income has been affected by fluctuating commodity prices and risk management costs, the fluctuating Canadian dollar, higher operating and G&A costs, changes in future tax provisions due to changes in government legislation (SIFT tax and corporate rate reductions) as well as changes to accounting policies adopted during 2007. Furthermore, changes in the fair value of our commodity derivative instruments along with changes in fair value of other financial instruments cause net income to fluctuate between quarters.

	Oil and				Net Income Per Trust Unit
Quarterly Financial Information	Gas		Net
(CDN$ millions, except per trust unit amounts)	Sales(1)		Income		Basic		Diluted
2007
Fourth Quarter	$	389.8	$	98.7	$	0.76	$	0.76
Third Quarter		364.8		93.0		0.72		0.72
Second Quarter		382.5		40.1		0.31		0.31
First Quarter		380.0		107.9		0.88		0.87
Total	$	1,517.1	$	339.7	$	2.66	$	2.66
2006
Fourth Quarter	$	369.5	$	110.2	$	0.90	$	0.89
Third Quarter		398.0		161.3		1.31		1.31
Second Quarter		403.5		146.0		1.19		1.19
First Quarter		401.7		127.3		1.08		1.07
Total	$	1,572.7	$	544.8	$	4.48	$	4.47

(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 2007 with the same period in 2006:

• Net income decreased 10% to $98.7 million due to increased commodity derivative instrument losses, partially offset by higher oil and gas sales.

• Cash flow was $205.1 million in 2007 similar to $207.1 million in 2006.

• Average daily production decreased 7% to 80,959 BOE/day due to the fire at Giltedge, operational interruptions and reductions in our development capital program.

• The average selling price per BOE increased 13% to $52.33 due to stronger crude oil prices.

• Operating expenses of $8.57/BOE (including non-cash amounts) were similar to the fourth quarter of 2006 at $8.52/BOE.

• G&A expenses including non-cash amounts increased 4% on a BOE basis to $2.21/BOE from $2.13/BOE as a result of lower production.

• Development capital spending decreased 14% compared to the fourth quarter of 2006 as a result of a reduced development capital spending program in 2007.

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The following tables provide an analysis of key financial and operating results for the three months ended December 31, 2007 and 2006.

(CDN$ millions, except per unit amounts)	Three Months Ended December 31, 2007	Three Months Ended December 31, 2006
Financial (000’s)

Net Income	$	98.7		$	110.2
Cash Flow from Operating Activities	$	205.1		$	207.1
Cash Distributions to Unitholders(1)	$	163.4		$	155.0
Financial per Unit (2)
Net Income	$	0.76		$	0.90
Cash Flow from Operating Activities	$	1.58		$	1.69
Cash Distributions to Unitholders(1)	$	1.26		$	1.26
Payout Ratio(3)		80	%		75	%
Average Daily Production		80,959			87,092
Selected Financial Results per BOE(4)
Oil and Gas Sales(5)	$	52.33		$	46.11
Royalties		(9.83	)		(8.26	)
Commodity Derivative Instruments		(0.08	)		0.75
Operating Costs		(8.53	)		(8.52	)
General and Administrative		(1.94	)		(1.88	)
Interest and Foreign Exchange		(1.70	)		(1.02	)
Taxes		(1.70	)		(0.64	)
Restoration and Abandonment		(0.75	)		(0.54	)
Cash Flow from Operating Activities before changes in non-cash working capital	$	27.80		$	26.00
Weighted Average Number of Units Outstanding (thousands)		129,658			122,971
Development Capital		106.1			123.1
Net Wells Drilled		76			89
Success Rate		100	%		100	%
Average Benchmark Pricing
AECO natural gas - monthly index (CDN$/Mcf)	$	6.00		$	6.36
AECO natural gas - daily index (CDN$/Mcf)	$	6.14		$	6.91
NYMEX natural gas - monthly NX3 index (US$/Mcf)	$	7.03		$	6.62
NYMEX natural gas - monthly NX3 index: CDN$ equivalent (CDN$/Mcf)	$	6.89		$	7.52
WTI crude oil (US$/bbl)	$	90.68		$	60.21
WTI crude oil: CDN$ equivalent (CDN$/bbl)	$	88.90		$	68.42
CDN$/US$ exchange rate		1.02			0.88

(1)   Calculated based on distributions paid or payable. Cash distributions to unitholders per unit may not correspond to actual distributions of $1.26 per trust unit as a result of using the annual weighted average trust units outstanding.

(2)   Based on weighted average trust units outstanding.

(3)   Based on cash distributions divided by cash flow from operating activities.

(4)  Non-cash amounts have been excluded.

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

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Selected Quarterly Canadian and U.S. Financial Results

	Three months ended December 31, 2007										Three months ended December 31, 2006
(CDN$ millions, except per unit amounts)		Canada			U.S.			Total				Canada			U.S.			Total
Daily Production Volumes
Natural gas (Mcf/day)			245,219			12,196			257,415				271,061			6,654			277,715
Crude oil (bbls/day)			24,248			9,973			34,221				25,903			10,436			36,339
Natural gas liquids (bbls/day)			3,836			-			3,836				4,467			-			4,467
Total daily sales (BOE/day)			68,953			12,006			80,959				75,547			11,545			87,092
Pricing (1)
Natural gas (per Mcf)		$	5.91		$	5.98		$	5.91			$	6.57		$	6.81		$	6.58
Crude oil (per bbl)		$	68.94		$	80.16		$	72.21			$	52.39		$	59.85		$	54.53
Natural gas liquids (per bbl)		$	58.12		$	-		$	58.12			$	46.15		$	-		$	46.15
Capital Expenditures
Development capital and office		$	94.3		$	13.7		$	108.0			$	96.7		$	29.1		$	125.8
Acquisitions of oil and gas properties		$	5.0		$	0.1		$	5.1			$	4.1		$	0.7		$	4.8
Dispositions of oil and gas properties		$	(0.4	)	$	(3.6	)	$	(4.0	)		$	(0.1	)	$	-		$	(0.1	)
Revenues
Oil and gas sales (1)		$	309.5		$	80.3		$	389.8			$	307.9		$	61.6		$	369.5
Royalties		$	(56.1	)	$	(17.1	) (2)	$	(73.2	)		$	(54.1	)	$	(12.1	) (2)	$	(66.2	)
Commodity derivative instruments		$	(48.8	)	$	-		$	(48.8	)		$	(5.4	)	$	-		$	(5.4	)
Expenses
Operating		$	61.0		$	2.8		$	63.8			$	66.4		$	1.9		$	68.3
General and administrative		$	16.5		$	(0.1	)	$	16.4			$	14.6		$	2.5		$	17.1
Depletion, depreciation, amortization and accretion		$	89.9		$	21.8		$	111.7			$	93.3		$	26.2		$	119.5
Current income taxes		$	-		$	12.6		$	12.6			$	-		$	5.1		$	5.1

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

(2)  Royalties include U.S. state production tax.

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 16. 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 efforts 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 not exploration in nature and is more focused on 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, on a country by country cost centre basis 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 method may generate a different carrying value of property, plant and equipment and a different net income depending on the circumstances at period end. Net costs related to operating and administrative activities during the development of large capital projects are capitalized until commercial production has commenced and are tested for impairment separately.

Critical Accounting Estimates

The preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates. Due to the timing of when activities occur compared to the reporting of those activities, management must estimate and accrue operating results and capital spending. Changes in these judgments and estimates could have a material impact on our financial results and financial condition.

Reserves

The process of estimating reserves is critical to several accounting estimates. It requires significant judgments 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.

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Asset Retirement Obligation

Management calculates the asset retirement obligation based on 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 PP&E as part of the cost of the related asset and amortized over its useful life.

Business Combinations

Management makes various assumptions in determining the fair values of any acquired company’s assets and liabilities in a business combination. The most significant assumptions and judgments made relate to the estimation of the fair value of the oil and gas properties. To determine the fair value of these properties, we estimated (a) oil and gas reserves in accordance with NI 51-101 reserve standards, and (b) future prices of oil and gas.

Commodity Prices

Management’s estimates of future crude oil and natural gas prices are critical as these prices are used to determine the carrying amount of PP&E, amounts recorded for depletion, impairment in the cost centre, and the change in fair value of financial contracts.

Trust Unit Rights

Management calculates the fair value of rights granted under our trust unit rights incentive plan using a binomial lattice option-pricing model. This process involves the use of significant estimates and assumptions, which may change over time. The values calculated under the option-pricing model may not reflect the actual value realized by trust unit rights holders.

Derivative Financial Instruments

Management uses derivative financial instruments to manage its exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Fair values of derivative contracts are subject to fluctuation depending on the underlying estimate of future commodity prices, foreign currency exchange rates and interest rates.

RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS

Convergence of Canadian GAAP with International Financial Reporting Standards

In 2006, Canada’s Accounting Standards Board (AcSB) ratified a strategic plan that will result in Canadian GAAP, as used by public entities, being converged with International Financial Reporting Standards (IFRS) by 2011. On February 13, 2008 the AcSB confirmed that use of IFRS will be required for public companies beginning January 1, 2011. We continue to assess the impact of adopting IFRS and implementing plans for transition.

Financial Instruments, Comprehensive Income and Hedges

CICA Section 3862 - Financial Instruments - Disclosures

This standard requires entities to provide disclosures in their financial statements that enable users to evaluate the significance of financial instruments to the entity’s financial position and performance. It also requires that entities disclose the nature and extent of risks arising from financial instruments and how the entity manages those risks.

This standard is effective for reporting periods beginning January 1, 2008 and will result in additional disclosures for our financial instruments.

CICA Section 3863 - Financial Instruments - Presentation

This standard establishes presentation guidelines for financial instruments and non-financial derivatives and deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset.

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This standard is effective for reporting periods beginning January 1, 2008 and should have a minimal impact on our reporting.

CICA Section 1535 - Capital Disclosures

This section details disclosures that must be made regarding an entity’s capital and how it is managed. The standard requires qualitative information about an entity’s objectives, policies and processes for managing capital and quantitative data about what the entity regards as capital. It requires disclosure of compliance with any capital requirements and consequences of any non-compliance.

This standard is effective for reporting periods beginning January 1, 2008 and will result in additional disclosures around managing capital.

RISK FACTORS AND RISK MANAGEMENT

Enerplus investors are participating in the net cash flow from a portfolio of crude oil and natural gas producing properties. As such, the cash distributions 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:

Canadian Government Tax on Income Trusts

On June 22, 2007, Bill C-52 was passed by the Senate and was given royal assent by the Governor General. As a result, our second quarter future income tax provision includes a future income tax expense of $78.1 million related to this legislation. This non-cash expense relates to temporary differences between the accounting and tax basis of the Fund’s assets and liabilities and has no immediate impact on cash flow. Tax pools in 2011 may not be sufficient to shelter taxable income from the new SIFT tax and as a result increased tax may reduce cash flow available for distributions and development spending.

We are currently evaluating alternatives to determine the optimal business structure for our unitholders. However, we currently see value in the three-year tax exemption period through 2010 as a distributing entity and would be hesitant to make major structural changes during this period without compelling reasons that we do not currently foresee.

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 may 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 may use financial instruments 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, and may be exposed to risk of default by the counterparties. Refer to the price risk management section.

Oil and Gas Reserves and Resources Risk

The value of our trust units are based on, among other things, the underlying value of the oil and gas reserves and resources. Geological and operational risks can affect the quantity and quality of reserves and resources and the cost of ultimately recovering those reserves and resources. Lower oil and natural gas prices may increase the risk of write-downs of our oil and gas property investments. Regulatory changes to reporting practices can also result in reserve or resource write-downs.

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.

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Each year, independent engineers evaluate a significant portion of our proved and probable reserves as well as the resources attributable to our oil sands properties

.

Sproule Associates Limited (“Sproule”) evaluated 92% of the total proved plus probable value (discounted at 10%) of our Canadian conventional year-end reserves, in accordance with NI 51-101 and has reviewed the remainder of the reserves Enerplus evaluated internally. GLJ Petroleum Consultants Ltd. (“GLJ”) evaluated the Joslyn bitumen reserves as they have previously performed such evaluations for the operator of the Joslyn project. Netherland, Sewell & Associates Inc. (“NSA”) of Dallas, Texas, evaluated the reserves attributed to our assets in the United States. Both GLJ and NSA evaluated 100% of the reserves in their respective areas. Both GLJ and NSA utilized Sproule’s forecast and constant price and cost assumptions as of December 31, 2007 in their evaluations to maintain consistency. GLJ also evaluated the resources attributable to our Joslyn and Kirby oil sands projects. The Reserves Committee of the Board of Directors has reviewed and approved the reserve and resource reports of the independent evaluators.

Operational Inflation Risk

Over the last few years we have experienced inflationary pressures on both our development capital costs and our operating costs. Higher costs decrease the amount of cash flow from our operating activities which may affect the amount of distributions to unitholders.

We strive to control costs through incentive-based compensation plans that reward employees for such things as cost control and value-added initiatives. We attempt to minimize costs by exploiting our purchasing strength with suppliers. 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, subsequent to the Focus acquisition, approximately 30% of our production is operated by third parties. We have limited ability to influence costs on partner-operated properties.

Access to Transportation Capacity

Market access for crude oil and natural gas production in Canada and the United States is dependent on the ability of Enerplus and the buyers of our production to access sufficient transportation capacity on third party pipelines to transport all production volumes. While the third party pipelines generally expand capacity to meet market needs, there can be differences in timing between the growth of production and the growth of pipeline capacity. There are also occasionally operational reasons for curtailing transportation capacity. Accordingly, there can be periods where pipeline capacity is insufficient to transport all of the production from a given region, causing volume curtailments for all shippers, including Enerplus and its production buyers.

We continuously monitor this risk for both the short and longer term through dialogue with the third party pipelines and other market participants, as well as by review of supply and demand studies prepared by third party experts. Where available and commercially appropriate given the production profile and commodity, we attempt to mitigate this risk by contracting for firm transportation capacity or by using other means of transportation.

Production Replacement 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 resources and developing existing reserves and resources. Acquisitions of oil and gas assets depend on our assessment of value at the time of acquisition. Incorrect assessments of value can adversely affect distributions to unitholders and the value of our trust units.

Acquisitions and our development capital program are subject to investment guidelines, due diligence and review. Major acquisitions are approved by the Board of Directors and, where appropriate, independent reserve engineer evaluations are obtained.

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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 2008, an estimated 72% of our outstanding trust units were held by non-residents. Immediately after the acquisition of Focus, on February 13, 2008, we estimate that approximately 63% of our trust units were held by non-residents. However, this estimate may not be accurate as it is based on certain assumptions and data from the securities industry that does not have a well-defined methodology to determine the residency of beneficial holders of securities.

Enerplus currently meets the requirements of a Mutual Fund Trust as defined in the Income Tax Act (Canada). Our trust indenture does not have a specific limit on the percentage of trust units that may be owned by non-residents.

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.

Regulatory Risk

Government royalties, income tax laws, environmental laws and regulatory requirements can have a significant financial and operational impact on Enerplus. During 2007 the Alberta government announced proposed changes to the provincial royalty program expected to be effective on January 1, 2009 (see the Royalties section of this MD&A for further details). Canada ratified the Kyoto Protocol in late 2002, which requires countries to reduce their emissions of carbon dioxide and other greenhouse gases. The Canadian federal government is currently gathering information to set emission targets for the industry. The details are projected to be announced by 2010 and could affect capital expenditures and operating costs.

Our operations expose us to possible regulatory changes by both Canadian and U.S. governments. As an oil and gas producer, we are subject to a broad range of regulatory requirements. Similarly, as a mutual fund trust, we have 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, the exchange of information with third party experts and employing qualified individuals to assess the impact of such changes on our financial and operating results.

Access to Capital Markets

Our access to capital has allowed us to fund a portion of our acquisitions and development capital program through equity and debt and as a result distribute the majority of our cash flow to our unitholders. 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. To the extent the cash flow retained by the Fund together with new equity and debt financing is not sufficient to cover required capital expenditures then cash distributions to unitholders may be reduced. Furthermore, current tightening global credit markets may have an adverse effect on our ability to access these capital markets.

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 dependent 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.

Health, Safety and Environmental Risk (“HSE”)

Health, safety and environmental risks influence the workforce, operating costs and the establishment of regulatory standards.

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We have established a HSE Management System designed to:

• provide staff with the training and resources needed to complete work safely and effectively;

• incorporate hazard assessment and risk management as an integral part of everyday business;

• monitor performance to ensure that our operations comply with legal obligations and the standards we set for ourselves; and

• identify and manage environmental liabilities associated with our existing asset base and

potential acquisitions.

We have a site inspections program and a corrosion risk management program designed to ensure compliance with environmental laws and regulations. We carry insurance to cover a portion of our property losses, liability and business interruption. HSE risks are reviewed regularly by the HSE committee comprised of members of the Board of Directors.

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 18% of our debt through our senior unsecured notes and interest rate swaps.

Foreign Currency Exposure

We have exposure to fluctuations in foreign currency as a result of the issuance of senior unsecured notes denominated in U.S. dollars. Our U.S. operations are directly exposed to fluctuations in the U.S. dollar when translated to our Canadian dollar denominated financial statements.

We also have indirect exposure to fluctuations in foreign currency as our crude oil sales and a portion of our natural gas sales are based on U.S. dollar indices. Our oil and gas revenues are negatively impacted as the Canadian dollar strengthens relative to the U.S. dollar.

We have hedged our foreign currency exposure on both our US$175 million and US$54 million of senior unsecured notes using financial swaps that convert the U.S. denominated debt to Canadian dollar debt. In addition we have hedged our interest obligation on our US$175 million notes.

We have not entered into any other foreign currency derivatives with respect to oil and gas sales or our U.S. operations.

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 non-payment with respect to oil and gas sales, financial hedging transactions and joint venture participants. We maintain a diversified sales customer base and we review our single-entity exposure on a regular basis. We do not have exposure to asset backed commercial paper, however we do have exposure to Canadian and U.S. banks as a counterparty to financial hedging transactions.

Unitholder Liability

In the past, there has been some concern that trust unitholders might be held personally liable for the indebtedness of the Fund.

Enerplus is registered in Alberta, which passed legislation in June 2005 to provide statutory protection for unitholders similar to the protection afforded shareholders in a corporation. Three other provinces (Ontario, Quebec, and Manitoba) also have statutory protection for unitholders. Our bank credit agreement and our debenture agreements do not allow the creditors to extend recourse to unitholders beyond the unitholders’ equity investment in the Fund.

Recruitment and Retention of Qualified Personnel

There is strong competition in all aspects of the oil and gas industry. Enerplus competes with a substantial number of other organizations for capital, acquisitions of reserves, undeveloped lands, access to drilling rigs, service rigs and other equipment, access to processing facilities, pipeline and refining capacity and in all other aspects of our operations. Other organizations may have greater technical and financial resources than Enerplus which leads to increased competition. Another rising challenge is the recruitment and retention of qualified professional staff at all levels in the organization. Increased activity within the oil and gas sector can create a competitive marketplace which presents challenges in recruiting and retaining key personnel.

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In order to attract and retain qualified personnel we offer competitive compensation including performance based plans.

SUMMARY 2008 OUTLOOK

Enerplus offers investors the benefits of owning a large, diversified portfolio of producing oil and natural gas properties within Canada and the United States. As such, our business prospects are closely linked to the opportunities and challenges associated with oil and natural gas production. In particular, we are strongly influenced by the price of crude oil and natural gas, both of which have been volatile in recent years. Our comments with respect to our 2008 outlook should be taken within the context of the current commodity price environment.

The following summarizes Enerplus’ 2008 guidance as provided throughout this MD&A and includes the acquisition of Focus at the closing date of February 13, 2008. We do not attempt to forecast commodity prices and, as a result, we do not forecast future cash flow or cash distributions. Readers are encouraged to apply their own price expectations to the following factors to arrive at an expected cash distribution.

Summary of 2008 Expectations	Target	Comments
Average annual production	98,000 BOE/day	Does not include any further potential acquisitions/divestments
Exit rate December 2008 production	100,000 BOE/day	Assumes $580 million development capital spending
2008 production mix	60% gas, 40% liquids
Average royalty rate	19%	Percentage of gross unhedged sales
Operating costs	$8.65/BOE
G&A costs	$2.20/BOE	Includes non-cash charges of $0.20/BOE (unit rights incentive plan)
U.S. income and withholding tax - cash costs	20%	Applied to net cash flow generated by U.S. operations and assumes repatriation of the funds to Canada after U.S. development capital spending
Average interest cost	4.5%	Based on current fixed rates and forward market
Payout ratio	60% - 90%
Development capital spending	$580 million

We expect our 2008 development capital spending to be $580 million, which is 50% higher than our 2007 spending. We plan to continue to withhold a portion of our cash flow to finance this capital program and we expect the payout ratio to be within our 60-90% guidance range. We believe it is important to maintain a conservative balance sheet as a defense against commodity price changes and to be positioned to capture acquisition opportunities.

We will continue to focus on low-risk development opportunities and review our risk management strategies in response to changing prices and the economics of our acquisition and development projects.

For 2008, we estimate that 95% of cash distributions will be taxable and 5% will be a tax-deferred return of capital for our Canadian unitholders. For our U.S. unitholders, we estimate that 90% of cash distribution will be taxable and 10% will be a tax-deferred return of capital.

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DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING

Under the supervision of our Chief Executive Officer and Chief Financial Officer we have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report and concluded that our disclosure controls and procedures are effective. There were no changes in our internal control over financial reporting during the quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ADDITIONAL INFORMATION

Additional information relating to Enerplus Resources Fund, including our Annual Information Form, is available under our profile on the SEDAR website at www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.

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FORWARD-LOOKING INFORMATION AND STATEMENTS

This management's discussion and analysis ("MD&A") contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this MD&A contains forward-looking information and statements pertaining to the following: the amount, timing and tax treatment of cash distributions to unitholders; future payout ratio; future tax treatment of income trusts such as the Fund; future structure of the Fund and its subsidiaries; the Fund’s tax pools; the volumes and estimated value of the Fund's oil and gas reserves and resources; the volume and product mix of the Fund's oil and gas production; future oil and natural gas prices and the Fund's commodity risk management programs; the amount of future asset retirement obligations; future liquidity and financial capacity; future results from operations, cost estimates and royalty rates; future development, exploration, and acquisition and development activities and related expenditures, including with respect to both our conventional and oil sands activities.

The forward-looking information and statements contained in this MD&A reflect several material factors and expectations and assumptions of the Fund including, without limitation: that the Fund will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing and in certain circumstances, proposed tax and royalty regimes; the accuracy of the estimates of the Fund's reserve volumes; and certain commodity price and other cost assumptions. The Fund believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information and statements included in this MD&A are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; unanticipated operating results or production declines; changes in tax or environmental laws or royalty rates; increased debt levels or debt service requirements; inaccurate estimation of the Fund's oil and gas reserves volumes; limited, unfavourable or no access to capital markets; increased costs; the impact of competitors; and certain other risks detailed from time to time in the Fund's public disclosure documents including, without limitation, those risks identified in this MD&A, our MD&A for the year ended December 31, 2007 and in the Fund's Annual Information Form.

The forward-looking information and statements contained in this MD&A speak only as of the date of this MD&A, and none of the Fund or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

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