Exhibit 1

ENERPLUS RESOURCES FUND

FINANCIAL & OPERATING HIGHLIGHTS

SELECTED FINANCIAL RESULTS

For the six months ended June 30,	2006			2005
Financial (000’s)
Net Income (1)	$	273,306		$	173,996
Funds Flow from Operations (2)		427,896			308,962
Cash Available for Distribution (3)		306,686			227,071
Cash Withheld for Acquisitions and Capital Expenditures		121,210			81,891
Debt Outstanding (net of cash)		603,919			557,807
Development Capital Spending		236,421			137,758
Acquisitions		42,257			5,681
Divestments		20,806			66,535
Financial per Unit
Net Income (1)	$	2.27		$	1.67
Funds Flow from Operations (2)		3.56			2.96
Cash Distributed (3)		2.52			2.12
Cash Withheld for Acquisitions and Capital Expenditures		1.00			0.76
Payout Ratio		72	%		74	%
Selected Financial Results per BOE (4)
Oil & Gas Revenues (5)	$	51.88		$	44.53
Royalties		(10.16	)		(9.08	)
Financial Contracts		(2.54	)		(3.56	)
Operating Costs		(7.94	)		(7.41	)
General and Administrative		(1.64	)		(1.11	)
Interest and Foreign Exchange		(0.91	)		(0.78	)
Taxes		(0.76	)		(0.22	)
Restoration and Abandonment		(0.36	)		(0.24	)
Funds Flow from Operations (2)	$	27.57		$	22.13
Weighted Average Number of Trust Units Outstanding (thousands)		120,311			104,469
Debt/Trailing 12 Month Funds Flow Ratio (2)		0.7x			0.9x

SELECTED OPERATING RESULTS

For the six months ended June 30,	2006			2005
Average Daily Production
Natural gas (Mcf/day)		269,922			274,780
Crude oil (bbls/day)		36,122			26,768
NGLs (bbls/day)		4,634			4,586
Total (BOE/day) (6:1)		85,743			77,151
% Natural gas		52	%		59	%
Average Selling Price (5)
Natural gas (per Mcf)	$	7.27		$	6.96
Crude oil (per bbl)	$	62.09		$	49.17
NGLs (per bbl)	$	51.50		$	44.89
US$ exchange rate		0.88			0.81
Net Wells Drilled		159			183
Success Rate		100	%		100	%

⁽¹⁾ See trust unit rights incentive plan discussion in Note 1

⁽²⁾ See the definition of funds flow in Management’s Discussion and Analysis

⁽³⁾ Calculated based on distributions paid or payable each month relating to the period

⁽⁴⁾ Non-cash amounts have been excluded

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

TRUST UNIT TRADING SUMMARY for the six months ended June 30, 2006	TSX - ERF.un (CDN$)		NYSE - ERF (US$)
High		64.36		58.00
Low		52.12		45.10
Close		63.00		56.24

2006 CASH DISTRIBUTIONS PER TRUST UNIT		CDN$		US$
Production Month	Payment Month
First Quarter Total		$	1.26	$	1.10
April	June	$	0.42	$	0.37
May	July		0.42		0.37
June	August		0.42		0.37
Second Quarter Total		$	1.26	$	1.11
Total Year-to-Date		$	2.52	$	2.21

* Calculated using an exchange rate of 1.13

PRESIDENT’S MESSAGE

Enerplus continued to post strong results in the second quarter of 2006. Distributions to our Canadian unitholders were maintained at $0.42 per unit per month and to our U.S. unitholders at US$0.37 per unit per month with a payout ratio of 72%. We are on track with the majority of our capital expenditures program, spending $108 million in the quarter and $236 million year-to-date. Wet weather conditions experienced during the quarter hampered our drilling and tie-in operations on our shallow gas projects in southern Alberta and Saskatchewan. Conversely, in the U.S., we advanced our drilling and well workover activities, increasing our production of light oil from the Sleeping Giant project by approximately 1,000 barrels per day over the first quarter. Overall, our production volumes averaged 86,092 BOE/day, up slightly from the first quarter, while performing the majority of our scheduled plant maintenance turnarounds.

Through the quarter, natural gas prices continued to soften as normal seasonal impacts were exacerbated by high levels of natural gas in storage in North America as a consequence of a warm winter. The impact of the softening natural gas prices on our cash flows was offset by the increase in our realized crude oil price. Our realized crude oil price increased 25% over the price received during the first quarter, due not only to a higher West Texas Intermediate benchmark price, but also a narrowing of the discount applied for heavier quality crude oil. The overall result for Enerplus was that we maintained our funds flow from operations quarter over quarter both in terms of the aggregate amount and on a per BOE basis.

Continued unrest in oil producing regions of the world combined with strong demand is keeping the supply/demand balance tight and oil prices at historic highs. We do not see any near term relief from this situation. With respect to natural gas prices, there is a risk that there could be further softening. This will largely be dependent upon cooling requirements in North America through the balance of the summer and the potential for any hurricane related supply disruptions again this year in the Gulf Coast. Our balanced portfolio of oil and natural gas properties have helped mitigate our risk exposure to the volatility of a single commodity.

The oil and natural gas industry in North America continues to experience record activity levels and as a result, the underlying cost for supplies, services and labour skills is impacted. Overall, indications are that costs are escalating in the order of 15% this year. We plan to maintain our guidance for capital spending at $485 million for 2006 however we are deferring a portion of both our shallow gas development program and our coalbed methane program into 2007 in response to the further weakening of natural gas prices. We have repositioned some of our capital spending to oil related projects which will partially offset the reduced spending on shallow gas development. We will work to control our costs while maintaining our momentum of enhancing our operations in Canada and the U.S. and continue to expect annual average production volumes of 84,000 BOE/day with an exit rate of 89,000 BOE/day. We are also maintaining our guidance on operating costs at $7.95/BOE, but we are increasing our guidance on general and administrative expense by $0.15/BOE to $1.85/BOE.

During the second quarter we advised of a steam release at our Joslyn SAGD project in the Alberta oil sands. Our operating partner, Total E&P Canada (“Total”), is in the process of finalizing the investigation and associated reporting to government regulators. We currently expect that the impact of the incident will be a delay in the timeline of the Phase II 10,000 bbl/day project (1,500 bbls/day net to Enerplus) of three to six months. Interest and activity levels in the Alberta oil sands continue to be high which is impacting not only valuations, but timing and costs associated with the development of this resource. The development and execution of plans for the Joslyn lease both in respect of the SAGD and mining potential continue to be a top priority for Enerplus and our operating partner as described more fully in our Operation’s Overview in this report.

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We continue to actively evaluate conventional opportunities in Canadian and U.S. markets focusing on acquisitions which provide attractive base economics and long-term upside through repeatable low risk development. Recently there have been some significant assets being brought to market that when combined with weakened natural gas prices may provide an opportunity that meets our economic thresholds and strategic plans. Through our financial strength, we are well positioned to take advantage of these developing opportunities should they materialize.

I would like to take this opportunity to acknowledge the contribution of Mr. Eric Tremblay, our Senior Vice President, Capital Markets, who left us in June to pursue family business interests and Mrs. Heather Culbert, Senior Vice President, Corporate Services, who retired at the end of June. Both of these individuals were key participants in the successful growth of Enerplus and we wish them well.

We look forward to continuing the success of the Fund into the second half of this year.

Gordon J. Kerr

President & Chief Executive Officer

OPERATION’S OVERVIEW

Production, capital and operating costs during the second quarter were consistent with or exceeded expectations.

Second quarter production levels exceeded expectations due to our U.S. operations realizing better than expected base production and improved performance from our capital program. In addition, we also realized better base production performance from our Canadian operations and positive prior period production adjustments.

Capital development expenditures for the second quarter were generally in-line with expectations at $108 million despite weather related delays which impacted the timing of certain drilling and tie-in programs. Development activities were relatively balanced between our oil and natural gas properties. Oil activity was concentrated on our Montana Bakken oil property and oil waterflood programs, while natural gas directed activities focused on our joint venture deep gas and shallow gas drilling programs. In response to continued cost pressures and falling natural gas prices we have modestly repositioned our development program over the remainder of the year by allocating capital from certain natural gas directed drilling programs toward oil activities. Despite this capital reallocation, our 2006 capital and production guidance remains unchanged at $485 million, 84,000 BOE/day annual average production and an exit rate of 89,000 BOE/day.

Operating costs during the second quarter averaged $8.31/BOE and $7.94/BOE on a year-to-date basis and were in line with quarterly expectations. Costs rose over the first quarter of 2006 as a result of scheduled facility maintenance activities. Although we are experiencing rising cost pressures due to high industry activity levels, we continue to target full year operating costs of $7.95/BOE.

DRILLING ACTIVITY

During the quarter we drilled 93 gross wells (34.7 net), down from 289 gross wells (124.3 net) drilled in the first quarter of this year. Most of the reduced drilling activity was as a result of weather related delays which impacted several of our shallow gas drilling programs. Over the remainder of 2006, our projected well count has decreased from 550 to 425 net wells as a result of the capital reallocation from certain of our shallow gas and coalbed methane programs, which have a large number of wells with relatively lower costs and production rates compared to oil projects that have fewer, more expensive wells with higher productivity.

2006 Development Activity by Play Type

	Three months ended June 30						Six Months ended June 30
	Capital						Capital
	Spending		Wells Drilled				Spending		Wells Drilled
	($millions)		Gross		Net		($millions)		Gross		Net
Shallow Natural Gas	$	8.2		17.0		13.6	$	20.3		133.0		73.2
Crude Oil Waterfloods		13.3		9.0		7.1		27.4		23.0		18.3
Bakken Oil		27.4		17.0		7.2		54.4		25.0		12.8
Oil Sands		6.6		0.0		0.0		17.7		11.0		1.7
Coalbed Methane		7.4		1.0		0.5		24.2		42.0		26.1
Other Conventional Oil & Gas		44.8		49.0		6.3		92.4		148.0		26.9
Total	$	107.7		93.0		34.7	$	236.4		382.0		159.0

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SHALLOW GAS DEVELOPMENT

Shallow gas remains a key play type in our capital investment portfolio and includes our properties in southern Alberta and Saskatchewan, targeting the Milk River, Medicine Hat and Second White Specs formations. During the second quarter, wet weather hampered our drilling and tie-in operations, and only $8.2 million was invested in shallow gas development including the drilling of 17 gross wells (13.6 net). With improved weather conditions, planned drilling and tie-in operations have resumed and key development areas for the second half of 2006 include Shackleton, Hanna and Medicine Hat. As a result of softening gas prices, we have deferred a portion of our shallow gas development at Verger, Atlee Buffalo and Medicine Hat. We also expect a deferral of some of the drilling activity at our non-operated Shackleton property. We now expect our 2006 shallow gas development program to include the drilling of approximately 450 gross wells (220 net) with a capital investment of approximately $60 million versus our original estimate of $74 million.

WATERFLOOD DEVELOPMENT

Our waterflood activities during the second quarter were primarily focused at our Joarcam property where we drilled 6 gross wells (5.8 net) in the Viking formation. In total we invested approximately $13.3 million during the quarter on drilling, recompletions, stimulations and optimization activities. We are on track to drill 22 oil wells at Joarcam during the course of 2006 and expect to bring on 500 bbls/day of additional production. We have revised our 2006 capital spending on our waterflood properties to $67 million from our original estimate of $78 million. Plans for the remainder of the year include the expansion of our waterflood at Medicine Hat and drilling activity at Virden and Pembina.

BAKKEN OIL DEVELOPMENT

Development of the Sleeping Giant project in Montana continued through the second quarter with production volumes in excess of 11,400 BOE/day, exceeding our expectations by approximately 1,300 BOE/day and representing an increase of 1,000 BOE/day over the first quarter. This increase in production was due to better performance from well workovers and our successful development drilling program. We invested $27.4 million during the quarter drilling 11 operated gross oil wells (6.9 net) in the Bakken formation in Montana. Similar to our Canadian operations, we are also experiencing an increase in costs relating to our development capital spending and now expect to spend approximately $100 million in 2006, up from our original estimate of $89 million.

OIL SANDS DEVELOPMENT

Our oil sands business continues to be a significant part of our planning and future growth activities as we progress on both the SAGD and mine development on our Joslyn project. Enerplus and the operator, Total, are continuing to review options on the optimal lease development and bitumen resource recovery plan given the flexibility which exists for both SAGD and mining operations. We anticipate an extensive lease development plan being completed prior to year-end.

SAGD Operations

During the second quarter we initiated steaming of well pairs in the first commercial SAGD project on the lease (10,000 bbls/day Phase II). Phase II operations commenced slightly behind schedule and essentially on budget. However as previously disclosed in our news release of May 24, 2006, we experienced a release of steam from underground into the atmosphere. No injuries occurred and no harmful emissions were released. The operator immediately shut down the affected well pair and two adjoining well pairs as a precautionary measure. Although an investigation into the incident continues, preliminary indications from Total are that the primary cause of the release was due to operating steam injection pressure being within the range of uncertainty of fracture pressure. If the final investigation confirms these findings, the operating steam injection pressure will be reduced but no material negative implications for the SAGD development are expected at this time. The primary impact of the release incident will be to delay the Phase II production ramp up by three to six months as steaming had only commenced on approximately half of the new well pairs prior to the incident. This delay does not affect our corporate production guidance as no commercial production volumes were planned for 2006. Currently, the operator continues to expect peak production from Phase II of 10,000 bbls/day in 2008 (1,500 bbls/day net to Enerplus).

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We anticipate receiving regulatory approval by the fourth quarter for the second commercial SAGD phase (Phase IIIA), a 26 well pair development with an estimated 15,000 bbls/day of gross peak production in 2010 (2,250 bbls/day net to Enerplus). We currently have a portion of the Phase IIIA reserves booked as probable reserves. If current development plans are modified and a decision is made to mine some of the identified SAGD areas, existing Phase IIIA probable reserve bookings could be impacted. Although mining typically provides about twice the recovery of the original bitumen in place versus SAGD projects, there could be timing differences between reserve bookings associated with the existing Phase IIIA development plans versus possible expansion of mine development plans.

In addition to our Joslyn activities, we continue to evaluate new areas primarily with a focus on expanding our oil sands business into other SAGD areas. In addition to internally generated opportunities, we are also benefiting from our joint venture relationship with Laricina Energy Ltd. which is providing additional opportunity generation in the oil sands.

Mining Operations

The Joslyn lease has the potential for resource recovery from mining as well as SAGD recovery. Total filed an application with the regulators in February of this year for the first phase of mining operations (the North Mine). The North Mine development project represents a 100,000 bbl/day gross production project and 890 million barrels of recoverable resource per the application submitted by Total (15,000 bbls/day and 134 million barrels net to Enerplus). These recoverable resource estimates are comparable to the interim reserves/resources report commissioned by Enerplus which provides a range of recoverable resource and includes a best estimate for the North Mine of 950 million barrels (142 million barrels net to Enerplus).

The North Mine application is currently being reviewed by government regulators. The operator’s best estimate for startup is now anticipated to be in 2013 (later than the previous plan of 2010/2011). Given current industry pressures from a significant number of competing projects, timing issues are expected to be on-going.

Enerplus currently classifies the mine as a recoverable resource however we expect to eventually reclassify these as probable reserves. The timing of such bookings remains uncertain and could extend beyond year-end. Key factors which will impact the timing of future reserve bookings include: confirmation of project timing, plans to test certain new technologies included in the North Mine application, project scope and marketing plans for the lease. As these uncertainties are resolved, we expect to move significant mining recoverable resource into probable reserve bookings.

COALBED METHANE

During the second quarter of 2006, we invested $7.4 million on coalbed methane (“CBM”) development projects, predominantly on drilling 1 gross well (0.5 net) in the Horseshoe Canyon coal formation of central Alberta and the completion and tie-in of wells drilled in the first quarter at Bashaw, Trochu and Joffre. Our development activities in the second half of 2006 will be focused at Joffre where we plan to participate in a 32 gross well (16 net) drilling program. We have deferred our drilling plans at Bashaw to 2007 due to area transportation issues and weak natural gas prices negatively impacting our project economics. We now expect to invest approximately $37 million in 2006, down from our original estimate of $49 million, and participate in the drilling of approximately 90 gross wells (48 net).

OTHER CONVENTIONAL DEVELOPMENT

Approximately 50% of our total daily production volumes are attributable to other conventional oil and natural gas properties throughout western Canada. During the second quarter of 2006, we invested approximately $44.8 million on development activities including drilling 49 gross wells (6.3 net).

Despite weaker natural gas prices, deep gas development in the Foothills and Deep Basin areas of western Alberta and northeast British Columbia continues to provide attractive economics given the high productivity of these wells. We invested $4.4 million and participated in the drilling of 8 gross deep natural gas wells (0.5 net) and plan to participate in additional joint venture deep drilling opportunities during the remainder of 2006.

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In southeast Saskatchewan, we invested approximately $6.4 million in the second quarter. Activity was focused at Colgate where we drilled 3 gross horizontal oil wells (2.4 net) in the Midale formation and acquired additional lands for future development opportunities. We are on track to drill 13 gross wells (12 net) targeting Mississippian era carbonates throughout the course of 2006.

HEALTH & SAFETY

With the current high activity levels in the oil and gas industry we continue to experience a higher than average number of injury incidents with both our employees and contractors. While the number of incidents in the second quarter decreased from the first quarter, with the majority of these incidents of lower severity, we are concerned with the incident rate. We are implementing a number of new proactive prevention measures that will address the common underlying factors that are contributing to both potential and actual incidents across the company. We are striving for additional improvement in our safety record through continued focus and commitment to our management system and our workers.

ACQUISITIONS AND DIVESTMENTS

No significant acquisitions were completed in the second quarter of 2006, however we did execute on a modest number of focused acquisitions, increasing working interests in existing strategic portfolio areas. This included the acquisition of additional interests in the Cutpick area of Alberta adding to our growing deep gas focus area. In total, we acquired approximately 1.3 million BOE of proved plus probable reserves and 144 BOE/day of production for $12.2 million resulting in metrics of $9.61/BOE of proved plus probable reserves, excluding future development capital, and $84,970/BOE of current daily production. We also divested miscellaneous interests with limited booked reserves and production for approximately $1.1 million.

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

The following discussion and analysis of financial results is dated August 2, 2006 and is to be read in conjunction with:

• the MD&A and audited consolidated financial statements as at and for the years ended December 31, 2005 and 2004; and

• the unaudited interim consolidated financial statements as at June 30, 2006 and for the three and six months ended June 30, 2006 and 2005.

All amounts are stated in Canadian dollars unless otherwise specified. All note references relate to the notes included with the consolidated financial statements. In accordance with Canadian practice, production volumes, reserve volumes and revenues are reported on a gross basis, before deduction of crown and other royalties, unless otherwise stated. Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE in isolation may be misleading.

We refer you to the end of the MD&A for our disclaimer on forward-looking statements.

NON-GAAP MEASURES

Throughout the MD&A, we use industry terminology such as funds flow from operations (“funds flow”), cash available for distribution and payout ratio. These terms as presented do not have any standardized meaning as prescribed by Canadian generally accepted accounting principles (“GAAP”), and therefore they may not be comparable with the calculation of similar measures by other entities.

Funds flow is calculated as cash flow from operating activities before changes in non-cash working capital. Funds flow is used by management to analyze operating performance, leverage and liquidity and is not intended to represent operating cash flows or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. Cash available for distribution is calculated as funds flow less discretionary amounts of cash withheld for acquisitions, capital expenditures and debt repayment. Payout ratio is calculated as cash available for distribution divided by funds flow.

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Refer to the Cash Available for Distribution section of the MD&A for a quantitative reconciliation of funds flow, cash available for distribution and payout ratio.

OVERVIEW

Production for the second quarter of 2006 increased to 86,092 BOE/day, despite downtime from scheduled facility maintenance activities. Continued high crude oil prices, partially offset by softer natural gas prices, once again helped deliver strong funds flow in the quarter. Cost pressures related to the high levels of industry activity resulted in increased operating costs and general and administrative expenses. We are maintaining our 2006 guidance on all measures with the exception of general and administrative expenses which we have increased by $0.15/BOE to an annual average of $1.85/BOE.

RESULTS OF OPERATIONS

Production

Production averaged 86,092 BOE/day during the second quarter of 2006, an increase of 1% from 85,392 BOE/day during the first quarter of 2006. The increase is due to better than expected production from our U.S. operations and approximately 900 BOE/day of positive prior year adjustments, partially offset by downtime resulting from scheduled facility maintenance during the second quarter.

For the three and six months ended June 30, 2006 production increased by 14% and 11% respectively compared to the same periods in 2005. The increase is a result of our acquisitions completed during the second half of 2005 as well as our ongoing development capital program.

Our average production during the second quarter was weighted 52% natural gas and 48% crude oil and natural gas liquids on a BOE basis. Average production volumes for the three and six months ended June 30, 2006 and 2005 are outlined below:

	Three months ended June 30,							Six months ended June 30,
Daily Production Volumes	2006		2005		% Change			2006		2005		% Change
Natural gas (Mcf/day)		269,088		269,159		-	%		269,922		274,780		(2	%)
Crude oil (bbls/day)		36,388		26,093		39	%		36,122		26,768		35	%
Natural gas liquids (bbls/day)		4,856		4,549		7	%		4,634		4,586		1	%
Total daily sales (BOE/day)		86,092		75,502		14	%		85,743		77,151		11	%

As some scheduled facility maintenance programs were delayed from the second quarter, we expect a temporary decrease in production during the third quarter however, we are maintaining our annual average production estimate of 84,000 BOE/day with an exit rate of 89,000 BOE/day.

Pricing

Our earnings, funds flow and financial condition are dependent on the prices received for our natural gas and crude oil production. The following tables compare our average selling prices and benchmark price indices for the three and six months ended June 30, 2006 and 2005.

	Three months ended June 30,							Six months ended June 30,
Average Selling Price(1)	2006		2005		% Change			2006		2005		% Change
Natural gas (per Mcf)	$	6.22	$	7.36		(15	%)	$	7.27	$	6.96		4	%
Crude oil (per bbl)		68.80		50.80		35	%		62.09		49.17		26	%
Natural gas liquids (per bbl)		52.33		45.98		14	%		51.50		44.89		15	%
Per BOE	$	51.50	$	46.57		11	%	$	51.88	$	44.53		17	%

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

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	Three months ended June 30,							Six months ended June 30,
Average Benchmark Pricing	2006		2005		% Change			2006		2005		% Change
AECO natural gas - monthly index (CDN$/Mcf)	$	6.27	$	7.38		(15	%)	$	7.77	$	7.03		11	%
AECO natural gas - daily index (CDN$/Mcf)		6.01		7.35		(18	%)		6.79		7.11		(5	%)
NYMEX natural gas - monthly NX3 index (US$/Mcf)		6.82		6.80		-	%		7.95		6.56		21	%
NYMEX natural gas - monthly NX3 index CDN$ equivalent (CDN$/Mcf)		7.66		8.50		(10	%)		9.03		8.10		11	%
WTI crude oil (US$/bbl)		70.70		53.17		33	%		67.09		51.51		30	%
WTI crude oil CDN$ equivalent (CDN$/bbl)		79.44		66.46		20	%		76.24		63.59		20	%
CDN$/US$ exchange rate	$	0.89	$	0.80		11	%	$	0.88	$	0.81		9	%

We realized an average price on our natural gas of $6.22/Mcf (net of transportation) during the three months ended June 30, 2006, a decrease of 15% from $7.36/Mcf for the same period in 2005. We sell our natural gas under both month and day AECO index contracts. The decrease realized is comparable to the decrease of 15% in the AECO monthly index price for natural gas and the decrease of 18% in the AECO daily index price for the same period. For the six months ended June 30, 2006 our realized price for natural gas increased 4% compared to the same period in 2005. This was also comparable to the blended increase of 3% for the combined indices for the same period.

The average price we received for our crude oil during the three months ended June 30, 2006 increased 35% to $68.80/bbl (net of transportation) from $50.80/bbl during the same period in 2005. In comparison, the West Texas Intermediate (“WTI”) crude oil benchmark price, after adjusting for the change in the US$ exchange rate, increased 20% from the corresponding period in 2005. We experienced a higher crude oil price increase than the underlying WTI due to narrowing crude oil differentials as well as an increase of light sweet crude oil in our production mix.

The Canadian dollar strengthened 11% and 9% against the U.S. dollar during the three and six months ended 2006 compared to the same periods in 2005. As most of our crude oil and a portion of our natural gas are priced in reference to U.S. dollar denominated benchmarks, this movement in the exchange rate reduced the Canadian dollar prices that we would have otherwise realized.

Price Risk Management 

We continue to review our risk management strategies in response to the volatile price environment and the economics of our acquisitions and development projects together with our overall financial position. All current outstanding financial contracts will expire during 2006 as we have not entered into any financial contracts since the third quarter of 2005 however we have extended some of our physical natural gas contracts as described below.

Physical Natural Gas Contracts

As at July 25, 2006, we have outstanding physical natural gas contracts which will provide us a price premium to the AECO monthly index in the amount of $0.79/Mcf on 19.0 MMcf/day for July through October 2006. We have also entered into additional physical natural gas contracts which will provide us a premium to the AECO monthly index in the amount of $0.83/Mcf on 28.0 MMcf/day for July and $1.19/Mcf on 38.0 MMcf/day for August through October 2006.

Financial Commodity Sales Contracts

During the second quarter of 2006, our commodity price risk management program incurred cash costs of $16.0 million on crude oil contracts and cash costs of $0.6 million on natural gas contracts, compared to cash costs of $12.9 million and $10.0 million respectively during the first quarter of 2006. The increase in cash costs on our crude oil contracts is consistent with the increase in crude oil prices in the second quarter. Reduced natural gas prices during the second quarter resulted in the decrease in our natural gas contract cash costs.

Compared to the second quarter of 2005 our total cash costs decreased by $12.8 million from $29.4 million. Although crude oil prices have increased, the combination of fewer outstanding contracts and reduced natural gas prices have decreased cash costs during 2006.

The unrealized gain on our financial contracts of $22.2 million for the three months ended June 30, 2006 represents the change in the fair value of financial contracts since March 31, 2006. Similarly, the unrealized gain of $62.5 million for the six months ended June 30, 2006 represents the change in fair value since December 31, 2005. As the forward markets for natural gas and crude oil fluctuate, and existing contracts are realized, changes in fair value are reflected as a non-cash charge or increase to earnings. At June 30, 2006 the fair value of our financial contracts of $5.1 million is included in deferred financial assets recorded on the balance sheet. See Note 2 for details.

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Effective December 31, 2005, we elected to stop designating our commodity financial contracts as hedges. As a result we recorded a deferred credit representing the fair value of these contracts on that day, with an offset recorded as a deferred financial asset that is amortized to income over the life of the underlying contracts. For the three and six months ended June 30, 2006 we recorded $18.4 million and $36.7 million, respectively, of amortization related to these contracts. The remaining balance of $13.2 million at June 30, 2006 is included in deferred financial assets on the balance sheet and will be amortized during the remainder of the year as the underlying contracts mature. See Note 2 for details.

Risk Management Costs	Three months ended June 30,					Three months ended June 30,
($ millions, except per unit amounts)	2006					2005
Cash costs:
Crude oil	$	16.0		$	4.82/bbl	$	22.5		$	9.48/bbl
Natural gas		0.6		$	0.03/Mcf		6.9		$	0.28/Mcf
Total Cash costs	$	16.6		$	2.12/BOE	$	29.4		$	4.28/BOE
Non-cash costs:
Change in fair value -financial contracts	$	(22.2	)	$	(2.84)/BOE	$	(23.6	)	$	(3.43)/BOE
Amortization of deferred financial assets		18.4		$	2.35/BOE		1.0		$	0.15/BOE
Total Non-cash costs	$	(3.8	)	$	(0.48)/BOE	$	(22.6	)	$	(3.28)/BOE
Total costs	$	12.8		$	1.64/BOE	$	6.8		$	1.00/BOE

Risk Management Costs	Six months ended June 30,					Six months ended June 30,
($ millions, except per unit amounts)	2006					2005
Cash costs:
Crude oil	$	28.9		$	4.41/bbl	$	41.4	$	8.54/bbl
Natural gas		10.6		$	0.22/Mcf		8.3	$	0.17/Mcf
Total Cash costs	$	39.5		$	2.54/BOE	$	49.7	$	3.56/BOE
Non-cash costs:
Change in fair value -financial contracts	$	(62.5	)	$	(4.03)/BOE	$	7.7	$	0.55/BOE
Amortization of deferred financial assets		36.7		$	2.37/BOE		2.0	$	0.14/BOE
Total Non-cash costs	$	(25.8	)	$	(1.66)/BOE	$	9.7	$	0.69/BOE
Total costs	$	13.7		$	0.88/BOE	$	59.4	$	4.25/BOE

REVENUES

Crude oil and natural gas revenues during the second quarter of 2006 were consistent with the first quarter of 2006 as increases in crude oil prices and production offset the decrease in natural gas prices.

Crude oil and natural gas revenues for the three months ended June 30, 2006 were $403.5 million ($409.1 million, net of $5.6 million transportation) compared to $320.0 million ($327.0 million, net of $7.0 million transportation) for the same period in 2005. For the six months ended June 30, 2006 revenues were $805.2 million ($816.9 million, net of $11.7 million transportation) compared to $621.8 million ($635.9 million, net of $14.1 million transportation) during the same period in 2005.

The increased revenues for the three and six months ended June 30, 2006 of $83.5 million or 26% and $183.4 million or 29%, respectively, are primarily due to higher crude oil prices as well as increased production resulting from acquisitions in the second half of 2005 and our ongoing development capital program.

Analysis of Sales Revenue (1) ($ millions)	Crude Oil		NGLs		Natural Gas			Total
Quarter ended June 30, 2005	$	120.6	$	19.0	$	180.4		$	320.0
Price variance(1)		59.6		2.8		(27.8	)		34.6
Volume variance		47.6		1.3		-			48.9
Quarter ended June 30, 2006	$	227.8	$	23.1	$	152.6		$	403.5

 

Page 9

($ millions)	Crude Oil		NGLs		Natural Gas			Total
Year-to-date ended June 30, 2005	$	238.2	$	37.2	$	346.4		$	621.8
Price variance(1)		84.5		5.6		15.4			105.5
Volume variance		83.3		0.4		(5.8	)		77.9
Year-to-date ended June 30, 2006	$	406.0	$	43.2	$	356.0		$	805.2

 ⁽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. For the three and six months ended June 30, 2006 royalties were $77.7 million and $157.7 million, respectively, both approximately 19% of oil and gas sales, net of transportation. For the three and six months ended June 30, 2005 royalties were $64.6 million and $126.8 million, respectively, both approximately 20% of oil and gas sales, net of transportation. Increases in royalties for the three and six months ended June 30, 2006 of $13.1 million and $30.9 million, respectively, compared to the same periods in 2005 were the result of increased oil and gas sales. We continue to expect royalties to be between 19% and 20% of oil and gas sales, net of transportation, for the remainder of the year.

OPERATING EXPENSES

Operating expenses for the second quarter of 2006 were $8.31/BOE or 10% higher than the first quarter of 2006. As expected, constrained production due to scheduled facility maintenance and the incremental expenditures associated with these turnaround activities resulted in increased operating expenses.

Operating expenses for the three months ended June 30, 2006 were $65.1 million or $8.31/BOE compared to $54.0 million or $7.86/BOE for the second quarter of 2005. For the six months ended June 30, 2006 operating costs were $123.3 million or $7.94/BOE compared to $103.5 million or $7.41/BOE for the same period in 2005. Increases in operating costs are generally being experienced by producers across the industry and are mainly due to cost pressures related to the high level of industry activity. More specifically, we continue to see increases in costs associated with scheduled facility maintenance, well servicing and utilities.

We continue to expect operating costs to average $7.95/BOE during 2006.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative (“G&A”) expenses for the second quarter of 2006 were 9% higher than the first quarter of 2006. G&A expenses for the three months ended June 30, 2006 were $14.6 million or $1.86/BOE compared to $8.5 million or $1.24/BOE for the second quarter of 2005. G&A expenses totaled $27.9 million or $1.80/BOE for the six months ended June 30, 2006 compared to $16.9 million or $1.21/BOE for the same period in 2005. These increases are primarily due to compensation costs associated with higher staffing levels, the impact of our higher trust unit price on long term staff retention plans, increased investment in information systems and technology and our contribution to education through the Southern Alberta Institute of Technology. As a result of these cost pressures we are increasing our annual guidance for G&A costs from $1.70/BOE to $1.85/BOE for 2006.

On October 1, 2005 we retroactively adopted the fair value method of accounting for our trust unit rights incentive plan to January 1, 2003. For comparative purposes the 2005 quarters have been restated to reflect the adoption of the fair value method of accounting for the trust unit rights incentive plan. See Notes 1 and 4 for further details. For the three months ended June 30, 2006 these charges were $1.3 million or $0.17/BOE compared to $0.7 million or $0.11/BOE for the same period in 2005. For the six months ended June 30, 2006 these charges were $2.5 million or $0.16/BOE compared to $1.4 million or $0.10/BOE for the same period in 2005.

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

General and Administrative Costs	Three months ended June 30,				Six months ended June 30,
($ millions)	2006		2005		2006		2005
Cash	$	13.3	$	7.8	$	25.4	$	15.5
Non-cash trust unit rights incentive plan (1)		1.3		0.7		2.5		1.4
Total G&A	$	14.6	$	8.5	$	27.9	$	16.9

Page 10

(Per BOE)
Cash	$	1.69	$	1.13	$	1.64	$	1.11
Non-cash trust unit rights incentive plan (1)		0.17		0.11		0.16		0.10
Total G&A	$	1.86	$	1.24	$	1.80	$	1.21

⁽¹⁾ See trust unit rights incentive plan discussion in Note 1

INTEREST EXPENSE

Interest expense in the second quarter of 2006 was comparable to the first quarter of 2006. Interest expense increased to $7.8 million for the second quarter of 2006 from $5.8 million during the same period in 2005. Interest expense increased to $16.0 million for the six months ended June 30, 2006 from $11.7 million during the same period in 2005. The increases are due to higher average indebtedness and higher interest rates during 2006 compared to the same periods during 2005.

At June 30, 2006, 22% of our debt was based on fixed interest rates while 78% was floating.

CAPITAL EXPENDITURES

We spent $107.7 million and $236.4 million on development drilling and facilities for the three and six months ended June 30, 2006, respectively, compared to $68.5 million and $137.8 million during the same periods in 2005. We achieved a 100% success rate with our drilling program as 35 net wells were drilled during the second quarter and 159 net wells were drilled year-to-date for 2006. Development in 2006 to date has been focused primarily on U.S. Bakken oil, waterflood, and joint venture deep gas.

Property acquisitions were $12.2 million and $42.2 million for the three and six months ended June 30, 2006, compared to $3.8 million and $5.6 million for the same periods in 2005. Second quarter acquisitions have been focused on increasing interests in existing areas of ownership. Property dispositions were $1.1 million and $20.8 million for the three and six months ended June 30, 2006, compared to $4.8 million and $66.5 million for the same periods in 2005. The majority of the $20.8 million divestments during 2006 related to the sale of a 1% interest in the Joslyn project, compared to the 2005 non-core divestment program which raised $66.5 million.

Total net capital expenditures for 2006 and 2005 are outlined below.

Capital Expenditures	Three months ended June 30,						Six months ended June 30,
($ millions)	2006			2005			2006			2005
Development expenditures	$	90.3		$	55.9		$	188.0		$	110.2
Plant and facilities		17.4			12.6			48.4			27.6
Development Capital		107.7			68.5			236.4			137.8
Office		0.5			1.7			1.3			2.2
Sub-total		108.2			70.2			237.7			140.0
Acquisitions of oil and gas properties(1)		12.2			3.8			42.2			5.6
Dispositions of oil and gas properties(1)		(1.1	)		(4.8	)		(20.8	)		(66.5	)
Total Net Capital Expenditures	$	119.3		$	69.2		$	259.1		$	79.1
Total Capital Expenditures financed with funds flow	$	60.1		$	38.0		$	121.2		$	79.1
Total Capital Expenditures financed with debt and equity		59.2			31.2			157.4			-
Total non-cash consideration for 1% sale of Joslyn project		-			-			(19.5	)		-
Total Net Capital Expenditures	$	119.3		$	69.2		$	259.1		$	79.1

⁽¹⁾ Net of post-closing adjustments

We are maintaining our 2006 annual guidance of $485 million for development capital spending.

Page 11

DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION (“DDA&A”)

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

For the three months ended June 30, 2006, DDA&A increased to $15.47/BOE compared to $12.49/BOE during the corresponding period in 2005. For the six months ended June 30, 2006, DDA&A increased to $15.00/BOE compared to $12.37/BOE during the corresponding period in 2005. The increase in DDA&A is due to increased property, plant and equipment from acquisitions completed during the second half of 2005.

No impairment of the Fund’s assets existed at June 30, 2006 using year-end reserves updated for acquisitions, divestitures, production and management’s estimates of future prices.

TAXES

Future Income Taxes

Future income taxes arise from differences between the accounting and tax bases of the operating companies’ assets and liabilities. The future income tax liability that is recorded on the balance sheet is recovered through earnings over time.

For the three months ended June 30, 2006 a future income tax recovery of $44.8 million was recorded in income compared to $17.1 million for the same period in 2005. Included in the 2006 second quarter is a recovery of $32.2 million that resulted from a reduction in the provincial and federal corporate tax rates, substantively enacted in the quarter. For the six months ended June 30, 2006, a future income tax recovery of $46.6 million was recorded in income compared to a future income tax recovery of $46.7 million during the same period in 2005.

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.

For the three months and six months ended June 30, 2006 our U.S. operations incurred income related taxes in the amount of $6.1 million and $10.0 million, respectively. We did not have U.S. operations during the first six months of 2005 therefore no amount was recorded.

The amount of current taxes recorded throughout the year is dependant upon the timing of both capital expenditures and repatriation of the funds to Canada. Although U.S. taxes as a percentage of funds flow were lower in the second quarter, we continue to expect current income and withholding taxes to be approximately 20% of funds flow from U.S. operations in 2006.

Capital Taxes

Capital taxes include both the Federal Large Corporations Tax (“LCT”) and the Saskatchewan Resource Surcharge. During the second quarter, the federal government eliminated the LCT retroactive to January 1, 2006.

SELECTED FINANCIAL RESULTS

	Three months ended June 30,						Six months ended June 30,
Per BOE of production (6:1)	2006			2005			2006			2005
Production per day		86,092			75,502			85,743			77,151
Weighted average sales price (1)	$	51.50		$	46.57		$	51.88		$	44.53
Royalties		(9.92	)		(9.39	)		(10.16	)		(9.08	)
Financial contracts		(1.64	)		(1.00	)		(0.88	)		(4.25	)
Add back / (deduct): Non-cash financial contracts		(0.48	)		(3.28	)		(1.66	)		0.69
Operating costs		(8.31	)		(7.86	)		(7.94	)		(7.41	)
General and administrative (2)		(1.86	)		(1.24	)		(1.80	)		(1.21	)
Add back: Non-cash G&A expense (trust unit rights) (2)		0.17			0.11			0.16			0.10
Interest expense, net of interest and other income		(0.88	)		(0.83	)		(0.88	)		(0.77	)
Foreign exchange (loss) gain		0.31			(0.14	)		0.15			(0.09	)
Deduct: Non-cash foreign exchange loss		(0.36	)		0.13			(0.18	)		0.08
Capital taxes		(0.04	)		(0.27	)		(0.11	)		(0.22	)
Current income tax		(0.78	)		-			(0.65	)		-
Restoration and abandonment cash costs		(0.32	)		(0.21	)		(0.36	)		(0.24	)
Funds flow from operations		27.39			22.59			27.57			22.13
Restoration and abandonment cash costs		0.32			0.21			0.36			0.24
Non-cash items:
Depletion, depreciation, amortization and accretion		(15.47	)		(12.49	)		(15.00	)		(12.37	)
Financial contracts		0.48			3.28			1.66			(0.69	)
G&A expense (trust unit rights) (2)		(0.17	)		(0.11	)		(0.16	)		(0.10	)
Foreign exchange		0.36			(0.13	)		0.18			(0.08	)
Future income tax recovery		5.73			2.49			3.00			3.33
Total net income per BOE	$	18.64		$	15.84		$	17.61		$	12.46

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

⁽²⁾ See trust unit rights incentive plan discussion in Note 1

Page 12

SELECTED CANADIAN AND U.S. FINANCIAL RESULTS

The following tables provide a geographical analysis of key financial results for the three and six months ended June 30, 2006. Prior period information has not been presented as we commenced operations in the U.S. on August 30, 2005.

	Three months ended June 30, 2006
(CDN$ millions, except per unit amounts)	Canada			U.S.			Total
Daily Production Volumes
Natural gas (Mcf/day)		263,265			5,823			269,088
Crude oil (bbls/day)		25,912			10,476			36,388
Natural gas liquids (bbls/day)		4,856			-			4,856
Total Daily Sales (BOE/day)		74,645			11,447			86,092
Pricing (1)
Natural gas (per Mcf)	$	6.17		$	8.25		$	6.22
Crude oil (per bbl)	$	67.30		$	72.50		$	68.80
Natural gas liquids (per bbl)	$	52.33		$	-		$	52.33
Capital Expenditures
Development capital and office	$	80.8		$	27.4		$	108.2
Acquisitions of oil and gas properties	$	12.2		$	-		$	12.2
Dispositions of oil and gas properties	$	(1.1	)	$	-		$	(1.1	)
Revenues
Oil and gas sales (1)	$	330.0		$	73.5		$	403.5
Royalties (2)	$	(63.8	)	$	(13.9	)	$	(77.7	)
Financial contracts	$	(12.8	)	$	-		$	(12.8	)
Expenses
Operating	$	63.4		$	1.7		$	65.1
General and administrative	$	13.2		$	1.4		$	14.6
Depletion, depreciation, amortization and accretion	$	92.3		$	28.8		$	121.1
Current income taxes	$	-		$	6.1		$	6.1

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

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

	Six months ended June 30, 2006
(CDN$ millions, except per unit amounts)	Canada			U.S.			Total
Daily Production Volumes
Natural gas (Mcf/day)		264,304			5,618			269,922
Crude oil (bbls/day)		26,124			9,998			36,122
Natural gas liquids (bbls/day)		4,634			-			4,634
Total Daily Sales (BOE/day)		74,809			10,934			85,743
Pricing (1)
Natural gas (per Mcf)	$	7.25		$	8.42		$	7.27
Crude oil (per bbl)	$	59.47		$	68.92		$	62.09
Natural gas liquids (per bbl)	$	51.50		$	-		$	51.50
Capital Expenditures
Development capital and office	$	182.8		$	54.9		$	237.7
Acquisitions of oil and gas properties	$	27.6		$	14.6		$	42.2
Dispositions of oil and gas properties	$	(20.8	)	$	-		$	(20.8	)
Revenues
Oil and gas sales (1)	$	671.9		$	133.3		$	805.2
Royalties (2)	$	(132.4	)	$	(25.3	)	$	(157.7	)
Financial contracts	$	(13.7	)	$	-		$	(13.7	)
Expenses
Operating	$	119.9		$	3.4		$	123.3
General and administrative	$	25.7		$	2.2		$	27.9
Depletion, depreciation, amortization and accretion	$	178.0		$	54.7		$	232.7
Current income taxes	$	-		$	10.0		$	10.0

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

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

Page 13

FUNDS FLOW FROM OPERATIONS AND NET INCOME

Funds flow from operations for the second quarter of 2006 was comparable with the first quarter of 2006. For the three months ended June 30, 2006, funds flow from operations was $214.6 million or $1.75 per trust unit compared to $155.2 million or $1.48 per trust unit for the same period in 2005. For the six months ended June 30, 2006, funds flow from operations was $427.9 million or $3.56 per trust unit compared to $309.0 million or $2.96 per trust unit for the same period in 2005. Funds flow from operations increased as a result of higher production and crude oil prices as well as lower cash risk management costs during the first half of 2006, offset in part by the increases in operating costs and G&A expenses.

Net income for the second quarter of 2006 was $146.0 million or $1.19 per trust unit compared to $108.8 million or $1.04 per trust unit for the second quarter of 2005. Net income for the six months ended June 30, 2006 was $273.3 million or $2.27 per trust unit compared to $174.0 million or $1.67 per trust unit for the same period in 2005. The increase is due to increased oil and gas sales and reduced risk management costs, partially offset by the increases in operating costs, G&A expenses, DDA&A charges and fluctuations in future income tax recoveries.

QUARTERLY FINANCIAL INFORMATION

Generally, oil and gas sales have increased due to higher prices and production both through acquisitions and capital development during the last two years, offset by an increased Canadian/U.S. dollar exchange rate. Net income has been affected by the fluctuations in oil and gas sales and risk management costs, the fluctuating Canadian dollar, increasing operating and G&A costs and changes to accounting policies adopted during 2003 and 2005. Changes in the fair values of our financial contracts continue to cause net income to fluctuate between quarters.

Quarterly information is summarized in the following table:

Quarterly Financial Information	Oil and Gas		Net		Net income per trust unit
($ millions, except per trust unit amounts)		Revenue(1)		Income		Basic		Diluted
2006
Second quarter	$	403.5	$	146.0	$	1.19	$	1.19
First quarter		401.7		127.3		1.08		1.07
2005 (2)
Fourth quarter	$	503.2	$	150.9	$	1.29	$	1.28
Third quarter		398.7		107.1		0.97		0.97
Second quarter		320.0		108.8		1.04		1.04
First quarter		301.8		65.2		0.63		0.62
Total	$	1,523.7	$	432.0	$	3.96	$	3.95
2004
Fourth quarter	$	317.5	$	114.5	$	1.10	$	1.10
Third quarter		302.2		50.6		0.49		0.49
Second quarter		265.6		48.0		0.51		0.51
First quarter		239.3		45.2		0.48		0.48
Total	$	1,124.6	$	258.3	$	2.60	$	2.60

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

⁽²⁾ See trust unit rights incentive plan discussion in Note 1

Page 14

CASH AVAILABLE FOR DISTRIBUTION

Our payout ratio for both the three and six months ended June 30, 2006 was 72%, compared to a payout ratio of 76% and 74% for the three and six month periods in 2005. During the first half of 2006, we funded $279.9 million in acquisitions and capital spending by withholding a portion of our funds flow from operations and the proceeds from our March 2006 equity issue.

We continually monitor our distribution payout ratio with respect to forecasted funds flow, debt levels and spending plans. The level of cash withheld typically varies between 10% and 40% of annual funds flow. We are prepared to adjust the payout levels in an effort to balance the investor’s desire for distributions with the Fund’s requirement to maintain a prudent capital structure. The actual amount of cash withheld is dependant upon our current levels of production, the prevailing commodity price environment and the Board of Directors’ discretion.

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

Reconciliation of Cash Available for Distribution	Three months ended June 30,						Six months ended June 30,
($ millions, except per unit amounts)	2006			2005			2006			2005
Cash flow from operating activities	$	198.4		$	175.1		$	387.7		$	305.4
Change in non-cash working capital		16.2			(19.9	)		40.2			3.6
Funds flow from operations		214.6			155.2			427.9			309.0
Cash withheld for acquisitions, capital expenditures and debt repayment(1)		(60.1	)		(38.0	)		(121.2	)		(81.9	)
Cash available for distribution(2)	$	154.5		$	117.2		$	306.7		$	227.1
Cash available for distribution per trust unit	$	1.26		$	1.07		$	2.52		$	2.12
Payout ratio(3)		72	%		76	%		72	%		74	%

⁽¹⁾    Cash withheld for acquisitions, capital expenditures and debt repayment is a discretionary amount and represents the difference between funds flow from operations and cash available for distribution.

⁽²⁾    Cash available for distribution will differ from cash distributions to unitholders on the Consolidated Statements of Cash Flows due to the timing of distribution announcements and the number of trust units outstanding on the record dates.

⁽³⁾    Based on cash available for distribution divided by funds flow from operations

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2006 our balance sheet remains strong with conservative debt levels of 0.7 times debt to trailing funds flow. This is a result of the current high crude oil price environment, increased production, and the net proceeds of $240.3 million from our March 2006 equity issue, offset by development capital spending in the first six months of the year.

During the first half of 2006 long-term debt, net of cash, decreased slightly to $603.9 million, which is comprised of $275.4 million of bank indebtedness and $328.5 million of senior unsecured notes.

The following table provides certain key financial ratios for the Fund:

Financial Leverage and Coverage	June 30, 2006		December 31, 2005
Long-term debt to trailing funds flow		0.7x		0.8x
Funds flow to interest expense		30.4x		30.8x
Long-term debt to long-term debt plus equity		18%		21%

Long-term debt is measured net of cash

Funds flow and interest expense are 12-months trailing (calculated based on the last 12 months after adjusting for acquisitions).

There has been no change to our $850 million bank credit facility or our senior unsecured notes during the quarter. Payments with respect to the bank facilities, senior unsecured notes and other third party debt have priority over claims of and future distributions to the unitholders. Unitholders have no direct liability should funds flow be insufficient to repay this indebtedness.

Page 15

We anticipate that we will continue to have adequate liquidity to fund future working capital and planned capital expenditures during 2006 primarily through funds flow from operations and the proceeds from the March 2006 equity issue.

TRUST UNIT INFORMATION

We had 122,582,000 trust units outstanding at June 30, 2006 compared to 104,772,000 trust units at June 30, 2005 and 117,539,000 at December 31, 2005. The weighted average basic number of trust units outstanding for the six months ended June 30, 2006 was 120,311,000 (2005 - 104,469,000).

For three months ended June 30, 2006, 350,000 trust units (2005 - 186,000) were issued pursuant to the Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan (“DRIP”) and the trust unit rights plan. This resulted in $14.6 million (2005 - $6.6 million) of additional equity to the Fund. For the six months ended June 30, 2006, 673,000 trust units ($28.0 million additional equity) were issued pursuant to the DRIP and the trust unit options and rights plans compared to 648,000 trust units ($21.2 million) during the same period in 2005. For further details see Note 4.

CANADIAN AND U.S. TAXPAYERS

Enerplus estimates that approximately 95% of cash distributions paid to Canadian and U.S. unitholders will be taxable and the remaining 5% will be treated as a tax deferred return of capital. Actual taxable amounts may vary depending on actual distributions that are dependent upon production, commodity prices and funds flow experienced throughout the year.

For U.S. taxpayers the taxable portion of the cash distribution is considered to be a dividend for U.S. tax purposes. For most U.S. taxpayers this should be a “Qualified Dividend” eligible for the reduced tax rate.

In July 2006, Enerplus estimated its non-resident ownership to be approximately 73%.

ADDITIONAL INFORMATION

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

FORWARD-LOOKING STATEMENTS

This discussion and analysis contains certain forward-looking statements and forward-looking information which are based on Enerplus' current internal expectations, estimates, projections, assumptions and beliefs. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe" and similar expressions are intended to identify forward-looking statements and forward-looking information. These statements are not guarantees of future performance and 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 statements or information. Enerplus believes the expectations reflected in those forward-looking statements and information are reasonable but no assurance can be given that these expectations will prove to be correct, and such forward-looking statements and information included in this discussion and analysis should not be unduly relied upon. Such forward-looking statements and information speak only as of the date of this discussion and analysis and Enerplus does not undertake any obligation to publicly update or revise any forward-looking statements or information, except as required by applicable laws.

Page 16

CONSOLIDATED BALANCE SHEETS

(CDN$ thousands) (Unaudited)	June 30, 2006			December 31, 2005
Assets
Current assets
Cash	$	652		$	10,093
Accounts receivable		156,187			170,623
Deferred financial assets (Note 2)		18,265			49,874
Other current		17,911			26,751
		193,015			257,341
Property, plant and equipment (Note 3)		3,666,199			3,650,327
Goodwill		214,065			221,234
Other assets		21,150			1,721
	$	4,094,429		$	4,130,623
Liabilities
Current liabilities
Accounts payable	$	222,868		$	316,875
Distributions payable to unitholders		51,498			49,367
Deferred credits (Note 2)		-			57,368
		274,366			423,610
Long-term debt		604,571			659,918
Future income taxes		388,901			442,970
Asset retirement obligations		117,238			110,606
		1,110,710			1,213,494
Equity
Unitholders’ capital (Note 4)		3,681,384			3,410,614
Accumulated income		1,681,484			1,408,178
Accumulated cash distributions		(2,614,298	)		(2,309,705	)
Cumulative translation adjustment		(39,217	)		(15,568	)
		2,709,353			2,493,519
	$	4,094,429		$	4,130,623

CONSOLIDATED STATEMENTS OF INCOME

	Three months ended June 30,						Six months ended June 30,
(CDN$ thousands except per trust unit amounts) (Unaudited)	2006			2005			2006			2005
Revenues
Oil and gas sales	$	409,078		$	326,974		$	816,916		$	635,934
Royalties		(77,708	)		(64,557	)		(157,679	)		(126,825	)
Derivative instruments (Notes 2 and 5)
Financial contracts - qualified hedges		-			(4,403	)		-			(7,295	)
Other financial contracts		(12,837	)		(2,451	)		(13,732	)		(52,100	)
Interest and other income		926			124			2,261			932
		319,459			255,687			647,766			450,646
Expenses
Operating		65,106			54,035			123,271			103,512
General and administrative		14,560			8,528			27,865			16,871
Transportation		5,615			6,978			11,727			14,137
Interest on long-term debt		7,814			5,804			15,977			11,725
Foreign exchange (gain)/loss		(2,408	)		928			(2,254	)		1,241
Depletion, depreciation, amortization and accretion		121,183			85,795			232,734			172,758
		211,870			162,068			409,320			320,244
Income before taxes		107,589			93,619			238,446			130,402
Capital taxes		275			1,851			1,710			3,092
Current taxes		6,147			-			10,009			-
Future income tax recovery		(44,847	)		(17,050	)		(46,579	)		(46,686	)
Net Income	$	146,014		$	108,818		$	273,306		$	173,996
Net income per trust unit
Basic	$	1.19		$	1.04		$	2.27		$	1.67
Diluted	$	1.19		$	1.04		$	2.26		$	1.66
Weighted average number of trust units outstanding (thousands)
Basic		122,379			104,669			120,311			104,469
Diluted		122,845			104,975			120,747			104,802

Page 17

CONSOLIDATED STATEMENTS OF ACCUMULATED INCOME

	Three months ended June 30,				Six months ended June 30,
(CDN$ thousands) (Unaudited)	2006		2005		2006		2005
Accumulated income, beginning of period	$	1,535,470	$	1,041,315	$	1,408,178	$	976,137
Net income		146,014		108,818		273,306		173,996
Accumulated income, end of period	$	1,681,484	$	1,150,133	$	1,681,484	$	1,150,133

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three months ended June 30,						Six months ended June 30,
(CDN$ thousands) (Unaudited)	2006			2005			2006			2005
Operating Activities
Net income	$	146,014		$	108,818		$	273,306		$	173,996
Non-cash items add/(deduct):
Depletion, depreciation, amortization and accretion		121,183			85,795			232,734			172,758
Financial contracts (Note 2)		(3,774	)		(22,581	)		(25,759	)		9,715
Foreign exchange (gain)/loss		(2,813	)		864			(2,748	)		1,188
Trust unit rights incentive plan (Note 4)		1,339			727			2,526			1,389
Future income tax recovery		(44,847	)		(17,050	)		(46,579	)		(46,686	)
Asset retirement costs incurred		(2,521	)		(1,352	)		(5,584	)		(3,398	)
		214,581			155,221			427,896			308,962
Decrease/(Increase) in non-cash working capital		(16,177	)		19,847			(40,211	)		(3,535	)
		198,404			175,068			387,685			305,427
Financing Activities
Issue of trust units, net of issue costs (Note 4)		14,564			6,607			268,244			21,194
Cash distributions to unitholders		(154,348	)		(110,536	)		(304,593	)		(220,222	)
(Decrease)/Increase in bank credit facilities		80,255			(5,426	)		(52,599	)		(28,372	)
Decrease in non-cash financing working capital		131			642			2,131			806
		(59,398	)		(108,713	)		(86,817	)		(226,594	)
Investing Activities
Capital expenditures		(108,133	)		(70,203	)		(237,693	)		(139,950	)
Property acquisitions		(12,230	)		(3,861	)		(42,257	)		(5,681	)
Property dispositions		1,089			4,846			1,278			66,535
Decrease/(Increase) in non-cash investing working capital		(19,076	)		2,863			(30,509	)		263
		(138,350	)		(66,355	)		(309,181	)		(78,833	)
Effect of exchange rate changes on cash		(1,269	)		-			(1,128	)		-
Change in cash		(613	)		-			(9,441	)		-
Cash, beginning of period		1,265			-			10,093			-
Cash, end of period	$	652		$	-		$	652		$	-
Supplementary Cash Flow Information
Cash income taxes paid	$	3,516		$	-		$	3,770		$	-
Cash interest paid	$	10,238		$	7,908		$	14,761		$	10,293

CONSOLIDATED STATEMENTS OF ACCUMULATED CASH DISTRIBUTIONS

	Three months ended June 30,				Six months ended June 30,
(CDN$ thousands) (Unaudited)	2006		2005		2006		2005
Accumulated cash distributions, beginning of period	$	2,459,950	$	1,921,186	$	2,309,705	$	1,811,500
Cash distributions		154,348		110,536		304,593		220,222
Accumulated cash distributions, end of period	$	2,614,298	$	2,031,722	$	2,614,298	$	2,031,722

Page 18

ENERPLUS RESOURCES FUND

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular amounts in thousands of Canadian dollars and thousands of units except per unit amounts) (Unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The interim consolidated financial statements of Enerplus Resources Fund (“Enerplus” or the “Fund”) have been prepared by management following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2005. The note disclosure requirements for annual statements provide additional disclosure to that required for these interim statements. Accordingly, these interim statements should be read in conjunction with the Fund’s consolidated financial statements for the year ended December 31, 2005. The disclosures provided below are incremental to those included in the 2005 annual consolidated financial statements.

On October 1, 2005 the Fund retroactively adopted the fair value method of accounting for the trust unit rights incentive plan to January 1, 2003. Under this method, the fair value of the rights is calculated on the date in which fair value can reasonably be determined, generally being the grant date. The impact of the adoption on our 2003 and 2004 reported earnings was not material and therefore those prior year financial statements have not been restated. The 2005 impact was recorded upon adoption. For comparison purposes the 2005 quarters have been restated to reflect the fair value methodology. The impact on the second quarter of 2005 was a decrease to general and administrative expenses (“G&A”) of $818,000 (a decrease of $3,804,000 for the first six months of 2005) and a decrease to contributed surplus of $219,000 (a decrease of $5,495,000 for the first six months of 2005).

2. DEFERRED FINANCIAL ASSETS AND DEFERRED CREDITS

Current Deferred Financial Assets ($ thousands)
Deferred financial assets as at December 31, 2005	$	49,874
Deferred financial credits as at December 31, 2005		(57,368	)
Change in fair value - other financial contracts (1)		62,499
Amortization of deferred financial assets (2)		(36,740	)
Deferred financial assets as at June 30, 2006	$	18,265

⁽¹⁾ Changes in the fair value of financial contracts that do not qualify for hedge accounting are taken into income during the period as other financial contracts and reflected as an increase or decrease in the deferred financial asset or liability.

⁽²⁾ Represents the amortization of the fair value of financial contracts on December 31, 2005 for which hedge accounting is no longer applied. These deferred financial assets will be amortized over the remaining lives of the associated financial contracts.

The following table summarizes the income statement effects of other financial contracts:

Other Financial Contracts	Three months ended June 30,						Six months ended June 30,
($ thousands)	2006			2005			2006			2005
Change in fair value	$	(22,218	)	$	(23,588	)	$	(62,499	)	$	7,702
Amortization of deferred financial assets		18,444			1,007			36,740			2,013
Realized cash costs, net		16,611			25,032			39,491			42,385
Other financial contracts	$	12,837		$	2,451		$	13,732		$	52,100

Effective December 31, 2005 the Fund elected to stop designating commodity financial contracts as hedges.

3. PROPERTY, PLANT AND EQUIPMENT

($ thousands)	June 30, 2006			December 31, 2005
Property, plant and equipment	$	5,546,964		$	5,306,137
Accumulated depletion, depreciation and accretion		(1,880,765	)		(1,655,810	)
Net property, plant and equipment	$	3,666,199		$	3,650,327

Page 19

Capitalized development G&A of $6,696,000 (2005 - $5,102,000) is included in property, plant and equipment (“PP&E”) for the six months ended June 30, 2006. Excluded from PP&E for the purpose of the depletion and depreciation calculation is $57,799,000 (2005 - $45,756,000) related to the Joslyn development project that has not yet commenced commercial production.

4. FUND CAPITAL

(a) Unitholders’ Capital

Trust Units

Authorized: Unlimited number of trust units

Issued:	Six months ended June 30, 2006				Year ended December 31, 2005
(thousands)	Units		Amount		Units		Amount
Balance before Contributed Surplus, beginning of period		117,539	$	3,407,567		104,124	$	2,826,641
Issued for cash:
Pursuant to public offerings		4,370		240,287		10,638		466,885
Pursuant to rights plans		454		15,791		805		24,737
Trust unit rights incentive plan (non-cash) - exercised				1,245		-		4,629
DRIP*, net of redemptions		219		12,166		339		15,613
Issued for acquisition of corporate and property interests (non-cash)		-		-		1,633		69,062
		122,582		3,677,056		117,539		3,407,567
Contributed Surplus (Trust unit rights incentive plan)		-		4,328		-		3,047
Balance, end of period		122,582	$	3,681,384		117,539	$	3,410,614

* Distribution Reinvestment and Unit Purchase Plan

Contributed surplus ($ thousands)	Six months ended June 30, 2006			Year ended December 31, 2005
Balance, beginning of period	$	3,047		$	4,636
Trust unit rights incentive plan (non-cash) - exercised		(1,245	)		(4,629	)
Trust unit rights incentive plan (non-cash) - expensed		2,526			3,040
Balance, end of period	$	4,328		$	3,047

On March 20, 2006 the Fund closed an equity offering of 4,370,000 units at a price of $58.00 per unit for gross proceeds of $253,460,000 ($240,287,000 net of issuance costs).

(b) Trust Unit Rights Incentive Plan

As at June 30, 2006, a total of 2,742,000 rights pursuant to the Trust Unit Rights Incentive Plan (“Rights Plan”) at an average exercise price of $46.64 were outstanding. This represents 2.2% of the total trust units outstanding of which 385,000 rights with an average exercise price of $33.71 were exercisable. Under the Rights Plan, distributions per trust unit to Enerplus unitholders in a calendar quarter which represent a return of more than 2.5% of the net PP&E of Enerplus at the end of such calendar quarter may result in a reduction in the exercise price of the rights. Results for the first and second quarters of 2006 reduced the exercise price of the outstanding rights by $0.50 per trust unit (effective July 2006) and $0.51 per trust unit (effective October 2006), respectively.

Activity for the rights issued pursuant to the Rights Plan is as follows:

	Six months ended June 30, 2006					Year ended December 31, 2005
	Number of Rights (000’s)			Weighted Average Exercise Price(1)		Number of Rights (000’s)			Weighted Average Exercise Price(1)
Trust unit rights outstanding
Beginning of period		2,621		$	42.80		2,401		$	34.33
Granted		662			54.91		1,125			53.07
Exercised		(454	)		34.80		(805	)		30.72
Cancelled		(87	)		46.50		(100	)		37.15
End of period		2,742			46.64		2,621			42.80
Rights exercisable at the end of the period		385		$	33.71		643		$	32.46

⁽¹⁾ Exercise price reflects grant prices less reduction in strike price discussed above.

Page 20

The Fund uses a binomial option-pricing model to calculate the estimated fair value of rights under the plan. During the three and six months ended June 30, 2006, non-cash compensation costs of $1,339,000 ($0.01 per unit) and $2,526,000 ($0.02 per unit), respectively, related to rights issued since January 1, 2003 have been charged to general and administrative expense. The non-cash compensation expense for the three and six months ended June 30, 2005 was $727,000 ($0.01 per unit) and $1,389,000 ($0.01 per unit), respectively.

(c) Basic and Diluted per Trust Unit Calculations

Net income per trust unit has been determined based on the following:

	Six months ended June 30,
(thousands)	2006		2005
Weighted average units		120,311		104,469
Dilutive impact of rights		436		333
Diluted trust units		120,747		104,802

5. FINANCIAL INSTRUMENTS

The Fund’s financial instruments presented on the balance sheet consist of cash, accounts receivable, other current assets, current liabilities and long-term debt.

The carrying value of cash, accounts receivable, current liabilities and outstanding bank credit facility balances approximate their fair value. Other current assets are comprised of prepaid expenses and marketable securities. The marketable securities are carried on the balance sheet at the lower of cost and fair value. The fair value of the marketable securities at June 30, 2006 exceeded the cost of these securities by $18,551,000. The Fund has US$54,000,000 of senior unsecured notes with fixed rate debt and a fair value of $58,745,000 at June 30, 2006. In addition, the Fund has US$175,000,000 of senior unsecured notes with fixed rate debt that was converted to CDN$268,328,000 floating rate debt through a cross-currency swap with a syndicate of financial institutions. At June 30, 2006 the fair value of the senior unsecured note was $195,289,000.

The estimated fair values have been determined based on available market information. The actual amounts realized may differ from these estimates.

(a) Derivative Financial Instruments

The Fund uses certain derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. The fair values of these instruments are based on an approximation of the amounts that would have been paid to or received from counterparties to settle the instruments outstanding as at June 30, 2006 with reference to forward prices and market valuations provided by independent sources.

The fair values of derivative financial instruments are as follows:

Interest Rate and Cross Currency Swaps

The Fund has entered into interest rate swaps on $75,000,000 of notional debt at rates varying from 4.12% to 4.61% before banking fees that are expected to range between 0.60% and 1.15%. These interest rate swaps mature between January 2007 and June 2011. The fair value of the $75,000,000 interest rate swaps as at June 30, 2006 represents an unrealized gain of $506,325. These swaps have been designated as hedges for accounting purposes.

The fair value of the cross currency swap related to the US$175,000,000 senior unsecured notes as at June 30, 2006 represents an unrealized cost of $80,368,000 whereas the fair value of the underlying debt instrument as at June 30, 2006 represents an unrealized gain of $73,039,000. The cross currency swap has been designated as a hedge for accounting purposes.

Page 21

Crude Oil Instruments

The Fund has financial contracts in place on its crude oil production as described below. Effective December 31, 2005, the Fund elected to stop designating commodity contracts as qualified hedges.

The following table summarizes the Fund’s crude oil risk management positions at July 25, 2006:

			WTI US$/bbl
	Daily Volumes bbls/day		Sold Call		Purchased Put		Sold Put
Term
July 1, 2006 - December 31, 2006
Put *		1,500		-	$	50.00		-
Put		1,500		-		-	$	41.00
July 1, 2006 - December 31, 2006
Put *		1,500		-	$	53.00		-
Put		1,500		-		-	$	43.00
July 1, 2006 - December 31, 2006
Put *		1,500		-	$	53.00		-
Put		1,500		-		-	$	43.00

* Financial contracts that were treated as hedges during 2005, however the Fund elected to stop designating these contracts as hedges as of December 31, 2005.

The Fund did not enter into any new contracts during the second quarter of 2006.

Natural Gas Instruments

The Fund has physical and financial contracts in place on its natural gas production as described below. Effective December 31, 2005, the Fund elected to stop designating commodity contracts as qualified hedges.

The following table summarizes the Fund’s natural gas risk management positions at July 25, 2006:

			AECO CDN$/Mcf
	Daily Volumes MMcf/day		Sold Call		Purchased Put		Sold Put		Fixed Price and Swaps
Term
July 1, 2006 - October 31, 2006
Swap *		9.5		-		-		-	$	5.47
Swap *		4.8		-		-		-	$	5.25
Swap *		4.8		-		-		-	$	5.24
Swap *		4.8		-		-		-	$	5.28
July 1, 2006 - October 31, 2006
Put *		9.5		-	$	7.38		-		-
Put *		9.5		-	$	7.38		-		-
Put *		9.5		-	$	7.38		-		-
2006 - 2010
Physical (escalated pricing)		2.0		-		-		-	$	2.52

* Financial contracts that were treated as hedges during 2005, however the Fund elected to stop designating these contracts as hedges as of December 31, 2005.

The Fund did not enter into any new contracts during the second quarter of 2006.

Electricity Instrument

The Fund has entered into electricity swap contracts that fix the price of electricity. These contracts have been designated as cash flow hedges and the fair value of these instruments as at June 30, 2006 is an unrealized gain of $847,000. Proceeds or costs realized from the electricity hedges are recognized as operating costs.

Page 22

The following table summarizes the Fund’s electricity management positions at July 25, 2006:

Term	Volumes MW/hr		Price CDN$/MWh
July 1, 2006 - December 31, 2006		5.0	$	49.99
July 1, 2006 - December 31, 2006 *		5.0	$	59.90
January 1, 2007 - December 31, 2007 *		5.0	$	61.50

* Financial contracts entered into during the second quarter of 2006

BOARD OF DIRECTORS

Douglas R. Martin ⁽¹⁾⁽²⁾

President

Charles Avenue Capital Corp.

Calgary, Alberta

Edwin Dodge^(3)(9)(11)

Corporate Director

Calgary, Alberta

Gordon J. Kerr

President & Chief Executive Officer

EnerMark Inc.

Calgary, Alberta

Robert L. Normand⁽⁶⁾⁽⁹⁾

Corporate Director

Rosemere, Québec

Glen D. Roane^(5)(10)

Corporate Director

Canmore, Alberta

W.C. (Mike) Seth⁽⁷⁾

Chairman

McDaniel & Associates Consulting Ltd.

Calgary, Alberta

Donald T. West^(7)(12)

Corporate Director

Calgary, Alberta

Harry B. Wheeler⁽⁵⁾⁽⁸⁾

President

Colchester Investments Ltd.

Calgary, Alberta

Robert L. Zorich^(4)(11)

Managing Director

EnCap Investments L.P.

Houston, Texas

⁽¹⁾ Chairman of the Board

⁽²⁾ Ex-Officio member of all Committees of the Board

⁽³⁾ Member of the Corporate Governance and Nominating Committee

⁽⁴⁾ Chairman of the Corporate Governance and Nominating Committee

⁽⁵⁾ Member of the Audit and Risk Management Committee

⁽⁶⁾ Chairman of the Audit and Risk Management Committee

⁽⁷⁾ Member of the Reserves Committee

⁽⁸⁾ Chairman of the Reserves Committee

⁽⁹⁾ Member of the Compensation and Human Resources Committee

⁽¹⁰⁾ Chairman of the Compensation and Human Resources Committee

⁽¹¹⁾ Member of the Environment, Health and Safety Committee

⁽¹²⁾ Chairman of the Environment, Health and Safety Committee

Page 23

OFFICERS

Gordon J. Kerr

President & Chief Executive Officer

Garry A. Tanner

Executive Vice President & Chief Operating Officer

Ian C. Dundas

Senior Vice President, Business Development

Robert J. Waters

Senior Vice President & Chief Financial Officer

Jo-Anne M. Caza

Vice President, Investor Relations

Rodney D. Gray

Vice President, Finance

Larry P. Hammond

Vice President, Operations

David A. McCoy

Vice President, General Counsel & Corporate Secretary

Daniel M. Stevens

Vice President, Development Services

Wayne G. Ford

Controller, Operations

Jodine J. Jenson Labrie

Controller, Finance

CORPORATE INFORMATION

OPERATING COMPANIES OWNED BY ENERPLUS RESOURCES FUND

EnerMark Inc.

Enerplus Resources Corporation

Enerplus Oil & Gas Ltd.

Enerplus Commercial Trust

Enerplus Resources (USA) Corporation

Page 24

LEGAL COUNSEL

Blake, Cassels & Graydon LLP

Calgary, Alberta

AUDITORS

Deloitte & Touche LLP

Calgary, Alberta

TRANSFER AGENT

CIBC Mellon Trust Company

Calgary, Alberta

Toll free: 1-800-387-0825

Email: inquiries@cibcmellon.com

CO-TRANSFER AGENT

Mellon Investor Services L.L.C.

Ridgefield, New Jersey

INDEPENDENT RESERVE ENGINEERS

Sproule Associates Limited

Calgary, Alberta

GLJ Petroleum Consultants

Calgary, Alberta

DeGolyer and MacNaughton

Dallas, Texas

STOCK EXCHANGE LISTINGS AND TRADING SYMBOLS

Toronto Stock Exchange: ERF.un

New York Stock Exchange: ERF

ABBREVIATIONS

AECO	Alberta Energy Company interconnect with the Nova Gas System, the Canadian benchmark for natural gas pricing purposes
bbl(s)/day	barrel(s) per day, with each barrel representing 34.972 Imperial gallons or 42 U.S. gallons
BOE(s)/day	barrel of oil equivalent per day (6 Mcf of gas:1 BOE)
CBM	coalbed methane, otherwise known as natural gas from coal - NGC
GAAP	Generally accepted accounting principles
Mbbls	thousand barrels
MBOE	thousand barrels of oil equivalent
Mcf/day	thousand cubic feet per day
MMbbl(s)	million barrels
MMBOE	million barrels of oil equivalent
MMBtu	million British Thermal Units
MMcf/day	million cubic feet per day
MWh	Megawatt hour(s) of electricity
NGLs	natural gas liquids
NYSE	New York Stock Exchange
SAGD	steam assisted gravity drainage
SEDAR	System for Electronic Document Analysis and Retrieval
TSX	Toronto Stock Exchange
WI	percentage working interest ownership
WTI	West Texas Intermediate oil at Cushing, Oklahoma, the benchmark for North American crude oil pricing purposes

HEAD OFFICE

The Dome Tower

3000, 333 - 7^th Avenue S.W.

Calgary, Alberta T2P 2Z1

Telephone: 403.298.2200

Toll free: 1.800.319.6462

Fax: 403.298.2211

Email: investorrelations@enerplus.com

For more information, visit our website: www.enerplus.com

Page 25