EXHIBIT 1

Enerplus Resources Fund 

The Dome Tower

3000, 333-7^th Avenue SW

Calgary, Alberta T2P 2Z1

Tel 403.298.2200

Fax 403.298.2211

www.enerplus.com

November 10, 2006

FOR IMMEDIATE RELEASE

TSX: ERF.UN

NYSE: ERF

ENERPLUS ANNOUNCES 2006 THIRD QUARTER RESULTS

Calgary, Alberta - Enerplus Resources Fund is pleased to announce the results from operations for the third quarter of 2006. Our financial and operating highlights are as follows:

• Cash distributions paid to Unitholders were maintained at $0.42 per month for Canadian Unitholders and approximately $0.37 for US Unitholders during the quarter with a payout ratio of 64% for the quarter and 69% year-to-date compared to 70% and 72% for the same periods in 2005.

• Daily production volumes continued to exceed our expectations and averaged 84,533 BOE/day due primarily as a result of better base production from both our Canadian and U.S. assets. On a year-to-date basis, production volumes have averaged 85,335 BOE/day. As a result, we are revising our full-year production guidance for 2006 to 85,500 BOE/day, up 1,500 BOE/day from our previous guidance of 84,000 BOE/day.

• As a result of our increased annual production guidance, we are also reducing our estimate of 2006 operating costs from $7.95 to $7.80/BOE.

• Development capital activities during the quarter totaled $131.7 million and are marginally below expectations given continued inflationary pressures. We have deferred some drilling to stay within our $485 million spending target this year, resulting in a slight reduction to our expected exit production rate from 89,000 to 88,000 BOE/day.

• During the quarter, approximately 65% of our capital spending was directed to oil development while 35% was directed to natural gas. We drilled 268 gross development wells (145.3 net), the majority of which were shallow natural gas wells, with a 99% success rate. Going forward, service costs may ease with the weakness in natural gas prices and the uncertainties in the Canadian trust sector.

• Oil and gas revenues during the quarter were relatively constant compared to our last quarter as declining natural gas prices were offset by higher crude oil prices and production. This demonstrates the value of having a balanced mix of oil and natural gas assets within our portfolio.

• Our debt-to-cash flow ratio at September 30, 2006 dropped to 0.6x.

PROPOSED CHANGES TO THE TAXATION OF INCOME TRUSTS IN CANADA

On October 31, the Canadian government announced a proposal to effectively tax distributions paid by publicly traded income trusts with the exception of real estate investment trusts. The government stated that this new proposal, aimed at taxing trusts at the same level as corporations, is to come into force for existing trusts such as Enerplus in four years (effective for the 2011 tax year). This proposal requires parliamentary approval to become law and the full details can be found at www.fin.gc.ca/news06/06-061e.html.

This announcement came as a complete surprise to Enerplus and investors alike. The Canadian markets reacted quickly with over $35 billion in value lost in two days. Millions of individuals suffered large declines in their savings and we believe may ultimately see a reduction in their retirement income as a result of this action. Not only has this loss affected millions of investors, but this sudden and drastic change in our tax laws has resulted in a loss of credibility to Canada in the global marketplace. Canada has long been a resource rich nation that needs and has

encouraged foreign investment. Energy trusts play a unique and integral role in maximizing oil and gas production and providing essential capital to Canada’s strategically important energy industry. An important symbiotic relationship exists between senior integrated oil and gas corporations, trusts and junior exploration and production companies. Enerplus has a 20 year history as an income fund in Canada. We have outperformed the corporate index over the long term and we have demonstrated our ability to more efficiently develop and produce mature oil and natural gas reserves in North America.

Unfortunately, this uncertainty has resulted in significant loss of market value to our unitholders as the proposed imposition of additional taxes would likely lead to a reduction in distributions. We are opposed to these changes and have joined the Coalition of Canadian Energy Trusts in the hopes of opening a dialogue with government to find a solution that is best for all Canadians and those who have invested in Canada alongside Canadians.

At this time, we urge our unitholders to contact the Canadian government to ensure that your voice is heard in this important issue. We have provided the contact information for the Department of Finance and the Members of Parliament so that you may voice your concerns directly to them.

Minister of Finance:	Jim Flaherty
	Department of Finance Canada
	140 O’Connor Street
	Ottawa, Ontario K1A 0A6
	Phone: 613-992-6344
	Fax: 613-992-8320
	Email: Flaherty.j@parl.gc.ca

Members of Parliament: www.canada.gc.ca/directories/direct_e.html

Should our efforts be unsuccessful in changing the course of the Conservative government, we will need to adapt our strategy and structure. We acknowledge that unitholders would like to know that future strategy immediately; however, we require time to formulate our plans given that:

• the proposal allows for a four year period to develop alternatives

• the more detailed wording of the legislation has not been announced

• the passage of the legislation is still pending

• with operations and exchange listings in both Canada and the U.S., we require time to analyze all of our options with diligence.

Regardless of these issues, we continue to focus on our core business. We have an excellent portfolio of oil and gas properties with long reserve lives and tremendous potential for further development. We have talented and dedicated staff who are focused on creating value. We remain bullish on the long term prospects for crude oil and natural gas prices. We have worked hard over the last few years to position Enerplus as an efficient and successful oil and gas producer, enhancing our technical skills and increasing our exposure to oil sands and resource plays. We have kept our balance sheet strong to take advantage of opportunities in periods such as these. We expect to survive and prosper regardless of our structure.

SELECTED FINANCIAL RESULTS

For the nine months ended September 30,		2006			2005
Financial (000’s)
Net Income (1)	$	434,623		$	281,125
Funds Flow from Operations (2)		669,660			503,193
Cash Available for Distribution (3)		461,486			363,050
Cash Withheld for Acquisitions and Capital Expenditures		208,174			140,143
Debt Outstanding (net of cash)		589,420			593,006
Development Capital Spending		368,117			229,646
Corporate and Property Acquisitions		46,553			591,456
Divestments		21,021			66,847
Financial per Unit
Net Income (1)	$	3.59		$	2.64
Funds Flow from Operations (2)		5.53			4.73
Cash Distributed (3)		3.78			3.28
Cash Withheld for Acquisitions and Capital Expenditures		1.71			1.27
Payout Ratio		69	%		72	%
Selected Financial Results per BOE (4)

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Oil & Gas Revenues (5)	$	51.65		$	47.98
Royalties		(9.78	)		(9.66	)
Financial Contracts		(1.73	)		(4.40	)
Operating Costs		(7.85	)		(7.51	)
General and Administrative		(1.66	)		(1.19	)
Interest and Foreign Exchange		(0.91	)		(0.94	)
Taxes		(0.67	)		(0.38	)
Restoration and Abandonment		(0.31	)		(0.24	)
Funds Flow from Operations (2)	$	28.74		$	23.66
Weighted Average Number of Trust Units Outstanding (thousands)		121,120			106,307
Debt/Trailing 12 Month Funds Flow Ratio (2)		0.6x			0.9x

SELECTED OPERATING RESULTS

For the nine months ended September 30,		2006			2005
Average Daily Production
Natural gas (Mcf/day)		268,700			275,985
Crude oil (bbls/day)		36,065			27,343
NGLs (bbls/day)		4,487			4,569
Total (BOE/day) (6:1)		85,335			77,910
% Natural gas		52	%		59	%
Average Selling Price (5)
Natural gas (per Mcf)	$	6.89		$	7.35
Crude oil (per bbl)	$	64.27		$	54.85
NGLs (per bbl)	$	52.49		$	46.13
US$ exchange rate		0.88			0.82
Net Wells Drilled		304.3			281.4
Success Rate		99	%		99	%

⁽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 nine months ended September 30, 2006	TSX - ERF.un (CDN$	)	NYSE - ERF (US$	)
High	66.00		59.45
Low	50.69		45.10
Close	56.10		50.29

2006 CASH DISTRIBUTIONS PER TRUST UNIT		CDN$	US$
Production Month	Payment Month
First Quarter Total		$1.26	$1.10
Second Quarter Total		$1.26	$1.12
July	September	$0.42	$0.37
August	October	0.42	0.37
September	November	0.42	0.37*
Third Quarter Total		$1.26	$1.11
Total Year-to-Date		$3.78	$3.33

* Calculated using an exchange rate of 1.13.

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OPERATION’S OVERVIEW

Production during the third quarter averaged 84,533 BOE/day and exceeded expectations due to better than expected base production performance from our U.S. and Canadian operations. We are now projecting this overall positive performance trend to year-end and have subsequently increased our annual average production guidance by 1,500 BOE/day to 85,500 BOE/day.

Capital development expenditures for the third quarter of $131.7 million were in line with expectations and reflected increased activity levels over the second quarter and continued inflationary pressures. Given these inflationary pressures, we have deferred some drilling programs to stay within our capital spending target of $485 million. As a result, we have modestly lowered our target exit rate by 1,000 BOE/day to 88,000 BOE/day.

During the third quarter, approximately 65% of our capital expenditures were directed to oil development, while 35% were directed to natural gas opportunities. Oil activity was concentrated at our Montana Bakken oil property, oil waterflood programs and oil sands development, while natural gas directed activities focused on our shallow gas drilling programs. Development spending will continue to be weighted towards oil properties versus gas properties for the remainder of the year and into 2007.

Operating costs were in line with expectations during the third quarter averaging $7.68/BOE and $7.85/BOE on a year-to-date basis. As a result of higher projected annual average production and our efforts to control costs, we are now lowering our full year operating cost target from $7.95/BOE to $7.80/BOE.

DRILLING ACTIVITY

During the third quarter we drilled 268 gross wells (145.3 net), up significantly from 93 gross wells (34.7 net) drilled in the second quarter of this year. Although a larger number of natural gas wells were drilled during the quarter, a majority of the capital dollars was directed to oil projects. Our success rate on our drilling activity again exceeded 99%. We have deferred a modest number of projects during the remainder of 2006 and now expect to drill 400 net wells during the year.

2006 DEVELOPMENT ACTIVITY PLAY TYPE

	Three Months ended September 30				Nine Months ended September 30
			Wells Drilled				Wells Drilled
		Capital Spending ($ millions)	Gross	Net		Capital Spending ($ millions)	Gross	Net
Shallow Natural Gas	$	19.3	168	107.8	$	39.6	301	181.0
Crude Oil Waterfloods		20.8	14	11.3		48.2	37	29.6
Bakken Oil		33.6	14	8.3		88.0	39	21.1
Oil Sands		12.4	0	0		30.1	11	1.7
Coalbed Methane		6.4	10	4.9		30.6	52	31.0
Other Conventional Oil & Gas		39.2	62	13.0		131.6	210	39.9
Total	$	131.7	268	145.3	$	368.1	650	304.3

BAKKEN OIL DEVELOPMENT

The Sleeping Giant project in Montana was our most active development area in the third quarter. Production from this area continues to exceed expectations by approximately 1,000 BOE/day with third quarter production at approximately 11,600 BOE/day. We invested approximately $33.6 million to drill 14 gross oil wells (8.3 net) in the Bakken formation on our Montana properties. As a result of additional planned development activities and escalating development costs, we now expect to invest approximately $110 million in 2006, up from our second quarter estimate of $100 million and our beginning of year guidance of $89 million.

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CRUDE OIL WATERFLOOD DEVELOPMENT

In the third quarter, we invested approximately $20.8 million on waterflood drilling, re-completions, stimulations and optimization activities. At Pembina, we drilled 8 gross oil wells (5.6 net) in the Cardium formation. We expect that tie-in operations will be completed in the fourth quarter. At Joarcam we drilled 4 gross oil wells (3.7 net) in the Viking formation and invested in other facility and well optimization activities. At Giltedge, investments were focused on well and facility optimization activities. We are on track to invest $67 million on waterflood development in 2006. Plans for the remainder of the year include the expansion of our waterflood at Medicine Hat and drilling activity at Virden, Manitoba.

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 has built up an internal oil sands team with significant industry experience which is supporting the development of the Joslyn lease and pursuing new grass roots efforts independently and in conjunction with Laricina Energy Ltd. In regard to the Joslyn lease, spending in 2006 is expected to be approximately $36 million to advance both the SAGD ($30 million) and the mining options ($6 million).

Enerplus and the operator, Total E&P Canada (“Total”), are continuing to review the optimal lease development and bitumen resource recovery plan given the flexibility which exists for both SAGD and mining operations. Although we have made meaningful progress this year, the complexities of determining the optimal development plan have extended the timeline we anticipated. We currently expect an extensive full lease development plan being completed in 2007. We do not expect this to impact our current SAGD operations or the startup timing of the initial phase of the mine. It may, however, impact regulatory approval and startup timing of SAGD Phase III as we want to ensure optimum development of the lease prior to proceeding with an expansion of the SAGD area.

SAGD Operations

During the third quarter steam circulation was re-started on more than half of the 18 SAGD Phase II well pairs. As previously disclosed, these wells were impacted by a steam to surface incident on May 18, 2006. The wells are currently operating at lower pressure and production continues to increase. Total is working to put in place appropriate long-term remediation strategies. The primary impact of the release incident remains a delay to the Phase II production. This delay does not affect our corporate production guidance this year as no commercial production volumes were planned for 2006. Total continues to expect Phase II to reach peak production of 10,000 bbls/day in 2008 (1,500 bbls/day net to Enerplus), however, additional wells and capital may be required to reach peak production if average rates are lower with the reduced operating pressure.

The regulatory approval process continues for Phase III of SAGD, as the operator responds to additional Supplemental Information Requests (SIR’s). Regulatory approval may be delayed from the anticipated fourth quarter timing as we work on developing the optimal development plan for the lease which may impact Phase III. Currently Phase III represents a 15,000 bbl/day expansion of the existing facilities to a potential of 25,000 bbls/day gross SAGD production. We currently have a portion of the Phase III 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 III 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 reserves bookings associated with the existing Phase III development plans versus possible expansion of mine development plans.

Mining Operations

Total filed the application for regulatory approval 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 regulatory review of the North Mine application is progressing as expected and Total is currently responding to SIR’s on the project. The operator continues to expect startup in 2013 with peak production expected in 2014.

Enerplus currently recognizes the mine as a recoverable resource however we expect to eventually classify this resource as probable reserves. The timing of such bookings remains uncertain and is expected to extend beyond year-end. Key factors which will impact the timing of future reserve bookings include: confirmation of project timing,

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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 reclassify significant mining recoverable resources into probable reserves.

SHALLOW GAS DEVELOPMENT

Our shallow gas development program continued throughout the quarter with a focus on projects that provide strong economic returns in the current commodity price environment. Our activities were concentrated in the Milk River, Medicine Hat and Second White Specs formations on our properties in southern Alberta and Saskatchewan. We invested approximately $19.3 million in the third quarter to participate in 168 gross wells (107.8 net). With improved weather conditions in the third quarter, we executed on our drilling and tie-in programs as planned. Key development activities occurred at Hanna, Bantry, Medicine Hat and Shackleton. We remain on track to invest approximately $60 million on shallow gas development activities in 2006.

COALBED METHANE

During the third quarter, we invested $6.4 million on Coalbed Methane (“CBM”) development projects. Development activities were focused at Joffre where we participated in the drilling of 8 gross wells (4.4 net) in the Horseshoe Canyon coal formation. In the fourth quarter, development activities will continue to focus on drilling and tie-in operations at Joffre. Given continued gas price softness and access issues in some areas, we are targeting capital expenditures of approximately $37 million in 2006 to participate in the drilling of approximately 90 gross (48 net) wells.

OTHER CONVENTIONAL DEVELOPMENT

We expect spending in our other conventional assets to increase to approximately $175 million for 2006 as compared to original plans of $164 million. This increase is primarily a result of higher spending by industry partners on our non-operated properties.

During the third quarter of 2006, we invested approximately $39.2 million on development activities, including drilling of 62 gross wells (13.0 net). A key part of our conventional oil focus is in southeast Saskatchewan, where we invested approximately $6.8 million in the third quarter. We are on track to drill 13 gross wells (12 net) targeting this area in 2006. Bantry is another key focus area where fourth quarter plans include the drilling of three horizontal oil wells in the Sunburst formation.

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

The following discussion and analysis of financial results is dated November 9, 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 September 30, 2006 and for the three and nine months ended September 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.

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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.

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.

CANADIAN GOVERNMENT ANNOUNCEMENT ON INTENTION TO TAX TRUSTS

On October 31, 2006 Canada’s Finance Minister announced plans to tax distributions from publicly traded income trusts. For existing income trusts, such as Enerplus, the government is proposing a four-year transition period which would result in the tax measures being effective for 2011.

The measures appear intended to effectively tax trusts the same as corporations. These proposals are expected to have the most impact on tax-deferred investors, such as pension funds and registered retirement savings plans, and non-resident investors.

We are currently reviewing the announcement and assessing our options should these proposals be passed in Parliament in their current form.

OVERVIEW

We experienced a 13% increase in funds flow from operations and a 10% increase in net income for the third quarter of 2006 compared to the second quarter of 2006 due to reductions in cash price risk management costs, royalties and operating costs. Production and commodity prices were in-line with the second quarter of 2006, causing revenue to be relatively constant between the two quarters. As expected, production for the third quarter decreased to 84,533 BOE/day due to downtime from scheduled facility maintenance activities. Development capital spending for the quarter totaled $131.7 million resulting in the addition of 145.3 net wells with a 99% success rate. Our updated 2006 annual guidance, including updates on production and operating expenses, is detailed in the Summary 2006 Outlook section of the MD&A.

RESULTS OF OPERATIONS

Production

Production averaged 84,533 BOE/day during the third quarter of 2006, a decrease of 2% from 86,092 BOE/day during the second quarter of 2006. The decrease is primarily due to scheduled facility maintenance programs that were carried over from the second quarter.

For the three and nine months ended September 30, 2006 production increased by 6% and 10% respectively compared to the same periods in 2005. Natural gas production declines were more than offset by the increase in crude oil production resulting from our U.S. acquisitions in the second half of 2005 as well as our ongoing development capital program.

Our average production during the third quarter was weighted 53% natural gas and 47% crude oil and natural gas liquids on a BOE basis. Average production volumes for the three and nine months ended September 30, 2006 and 2005 are outlined below:

	Three months ended September 30,					Nine months ended September 30,
Daily Production Volumes		2006	2005	% Change			2006	2005	% Change
Natural gas (Mcf/day)		266,292	278,356	(4	%)		268,700	275,985	(3	%)
Crude oil (bbls/day)		35,952	28,475	26	%		36,065	27,343	32	%
Natural gas liquids (bbls/day)		4,199	4,538	(7	%)		4,487	4,569	(2	%)
Total daily sales (BOE/day)		84,533	79,406	6	%		85,335	77,910	10	%

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We are increasing our annual average production estimate by 1,500 BOE/day to 85,500 BOE/day due to better than expected production from both our Canadian and U.S. operations. However, we have revised our exit rate to 88,000 BOE/day due to capital project delays associated with our response to inflationary pressures.

Pricing

The prices received for our natural gas and crude oil production directly impact our earnings, funds flow and financial condition. The following tables compare our average selling prices and benchmark price indices for the three and nine months ended September 30, 2006 and 2005.

	Three months ended September 30,						Nine months ended September 30,
Average Selling Price(1)		2006		2005	% Change			2006		2005	% Change
Natural gas (per Mcf)	$	6.13	$	8.09	(24	%)	$	6.89	$	7.35	(6	%)
Crude oil (per bbl)		68.57		65.35	5	%		64.27		54.85	17	%
Natural gas liquids (per bbl)		54.63		48.60	12	%		52.49		46.13	14	%
Per BOE	$	51.18	$	54.57	(6	%)	$	51.65	$	47.98	8	%

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

	Three months ended September 30,						Nine months ended September 30,
Average Benchmark Pricing		2006		2005	% Change			2006		2005	% Change
AECO natural gas - monthly index (CDN$/Mcf)	$	6.03	$	8.17	(26	%)	$	7.19	$	7.42	(3	%)
AECO natural gas - daily index (CDN$/Mcf)		5.64		8.82	(36	%)		6.40		7.43	(14	%)
NYMEX natural gas - monthly NX3 index (US$/Mcf)		6.53		8.25	(21	%)		7.47		7.12	5	%
NYMEX natural gas - monthly NX3 index CDN$ equivalent (CDN$/Mcf)		7.34		9.94	(26	%)		8.49		8.68	(2	%)
WTI crude oil (US$/bbl)		70.48		63.19	12	%		68.22		55.40	23	%
WTI crude oil CDN$ equivalent (CDN$/bbl)		79.19		76.13	4	%		77.52		67.56	15	%
CDN$/US$ exchange rate	$	0.89	$	0.83	7	%	$	0.88	$	0.82	7	%

Natural gas prices continued to decline over the nine month period, influenced by continued demand loss, the residual high storage inventories after the warm winter, and strong drilling. In July 2006, prices received some support due to warm temperatures in key consuming regions of the United States. However, the year over year natural gas storage surplus continued to build thereafter, and when preliminary weather forecasts began projecting a warmer than normal winter for the United States, there was further downward pressure on short term, and ultimately longer term, prices.

The volatility of the WTI crude oil price that was experienced during the first half of the year continued into the third quarter. The WTI crude oil spot price rose to a peak daily close during July 2006 of US$77.03 per barrel, due to actual, and threatened, Middle East instability. However, through August and September 2006 the WTI crude oil spot price fell over 20% as supply remained strong and crude, gasoline, and distillate inventories continued to build.

We realized an average price on our natural gas of $6.13/Mcf (net of transportation) during the three months ended September 30, 2006, a decrease of 24% from $8.09/Mcf for the same period in 2005. We sell our natural gas under both month and day AECO index contracts as well as month and day NYMEX index contracts. Decreases in the AECO and NYMEX indexes during the same period were between 21% and 36%. For the nine months ended September 30, 2006 our realized natural gas price decreased 6% compared to the same period in 2005. This decrease was also comparable to the average movement in the AECO and NYMEX indices for the same period.

The average price we received for our crude oil (net of transportation) during the three and nine months ended September 30, 2006 increased 5% to $68.57/bbl and 17% to $64.27/bbl, respectively, compared to the same periods in 2005. In comparison, the West Texas Intermediate (“WTI”) crude oil benchmark price, after adjusting for the change in the US$ exchange rate, increased 4% and 15% from the corresponding periods in 2005. We experienced a slightly higher crude oil price increase than the underlying WTI due to increased light sweet crude oil production from our U.S. acquisition in 2005.

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The Canadian dollar strengthened 7% against the U.S. dollar during both the three and nine 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. With due consideration to cost, we seek to limit exposure to price downturns while maintaining participation in commodity price increases.

Given significant commodity price uncertainty over the coming six to twelve month period, we have entered into additional commodity contracts, during and subsequent to the third quarter, to protect a portion of our crude oil revenue for the period January 2007 through December 2007, and to protect a portion of our natural gas revenue for the period November 2006 through October 2007. We also hedged additional electricity volumes for the period January 2007 through September 2008 to protect against rising electricity costs in the Alberta market.

For the fourth quarter of 2006 we have floor price protection on 32% of crude oil net production, at prices of US$50, US$53, and US$70 per barrel. Net production refers to the Average Annual Production Guidance for 2006, net of an assumed 19% royalty. For calendar 2007, including instruments entered into subsequent to the third quarter of 2006, we currently have floor price protection on 34% of crude oil net production, for prices between US$65.70 and US$71.00 per barrel. As well, we have fixed the price for calendar 2007 on a further 8% at US$66.24 per barrel.

With respect to natural gas, for the month of October 2006 we have floor price protection on 13% of natural gas net production, at $7.38/Mcf, and have fixed price protection on a further 11% at a weighted average price of $5.34/Mcf. For the period November 2006 through March 2007, including instruments entered into subsequent to the third quarter of 2006, we have purchased floor protection on 18% of natural gas net production, at a weighted average price of $7.55/Mcf. In order to help offset the cost of this floor protection, we also capped our price exposure at a weighted average price of $10.64/Mcf for 15% of natural gas net production. For the period April 2007 through October 2007, including instruments entered into subsequent to the third quarter of 2006, we have purchased floor protection for 19% of natural gas net production, at a weighted average price of $7.26/Mcf, capping the same volume at a weighted average price of $9.33/Mcf. As well, for the same period, we have entered into a fixed price transaction for 3% of net production at a price of $7.60/Mcf.

During the third quarter of 2006, our commodity price risk management program incurred cash costs of $1.3 million on crude oil contracts and generated a cash gain of $0.5 million on natural gas contracts, compared to cash costs of $16 million and $0.6 million respectively during the second quarter of 2006. The decrease in crude oil cash costs is due to the expiration of contracts on June 30, 2006 that had ceiling prices between US$35.35 and US$45.80 on 4,500 bbls/day. The decrease in natural gas cash costs is the result of lower natural gas prices during the third quarter.

Compared to the third quarter of 2005, our total cash costs decreased by $43.2 million to $0.8 million. The combination of contracts expiring and significantly lower natural gas prices accounted for the majority of the decrease during 2006.

The unrealized gain on our financial contracts of $27.0 million for the three months ended September 30, 2006 represents the change in the fair value of financial contracts since June 30, 2006. Similarly, the unrealized gain of $89.5 million for the nine months ended September 30, 2006 represents the change in fair value since December 31, 2005. As the forward markets for natural gas and crude oil fluctuate, and new contracts are executed and existing contracts are realized, changes in fair value are reflected as a non-cash charge or increase to earnings. At September 30, 2006 the fair value of our financial contracts of $32.1 million is included in deferred financial assets recorded on the balance sheet. See Note 2 for details.

Effective December 31, 2005, we elected to stop designating our commodity financial contracts as hedges. As a result we recorded a deferred credit representing the fair value of these contracts on that day, with an offset recorded as a deferred financial asset that is amortized to income over the life of the underlying contracts. For the three and nine months ended September 30, 2006 we recorded $10.3 million and $47.0 million, respectively, of amortization related to these contracts. The remaining balance of $2.9 million at September 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.

Page 9

Risk Management (Gains)/Losses	Three months ended September 30,					Three months ended September 30,
($ millions, except per unit amounts)	2006					2005
Cash (gains)/losses:
Crude oil	$	1.3		$	0.39/bbl	$	32.2		$	12.30/bbl
Natural Gas		(0.5	)	$	(0.02)/Mcf		11.8		$	0.46/Mcf
Total Cash losses	$	0.8		$	0.10/BOE	$	44.0		$	6.03/BOE
Non-cash (gains)/losses:
Change in fair value -financial contracts	$	(27.0	)	$	(3.47)/BOE	$	(3.5	)	$	(0.48)/BOE
Amortization of deferred financial assets		10.3		$	1.32/BOE		0.8		$	0.10/BOE
Total Non-cash gains	$	(16.7	)	$	(2.15)/BOE	$	(2.7	)	$	(0.38)/BOE
Total (gains)/losses	$	(15.9	)	$	(2.05)/BOE	$	41.3		$	5.65/BOE
Risk Management (Gains)/Losses	Nine months ended September 30,					Nine months ended September 30,
($ millions, except per unit amounts)	2006					2005
Cash losses:
Crude oil	$	30.2		$	3.07/bbl	$	73.6		$	9.86/bbl
Natural Gas		10.1		$	0.14/Mcf		20.1		$	0.27/Mcf
Total Cash losses	$	40.3		$	1.73/BOE	$	93.7		$	4.40/BOE
Non-cash (gains)/losses:
Change in fair value -financial contracts	$	(89.5	)	$	(3.84)/BOE	$	4.2		$	0.20/BOE
Amortization of deferred financial assets		47.0		$	2.02/BOE		2.8		$	0.13/BOE
Total Non-cash (gains)/losses	$	(42.5	)	$	(1.82)/BOE	$	7.0		$	0.33/BOE
Total (gains)/losses	$	(2.2	)	$	(0.09)/BOE	$	100.7		$	4.73/BOE

REVENUES

Revenues during the third quarter of 2006 remained consistent with the second quarter of 2006 as the impact of decreases in natural gas prices and production were minimal.

Crude oil and natural gas revenues for the three months ended September 30, 2006 were $398.0 million ($403.7 million, net of $5.7 million transportation), which is in-line with $398.7 million ($404.8 million, net of $6.1 million transportation) for the same period in 2005. Increased crude oil production offset decreased natural gas prices.

For the nine months ended September 30, 2006 revenues were $1,203.2 million ($1,220.7 million, net of $17.5 million transportation) compared to $1,020.5 million ($1,040.8 million, net of $20.3 million transportation) during the same period in 2005. The increased revenues of $182.7 million or 18% are due entirely to increased crude oil production and prices, offset by a decrease in natural gas production and prices.

Analysis of Sales Revenue (1) ($ millions)		Crude Oil		NGLs			Natural Gas			Total
Quarter ended September 30, 2005	$	171.2	$	20.2		$	207.3		$	398.7
Price variance(1)		10.6		2.4			(48.2	)		(35.2	)
Volume variance		45.0		(1.5	)		(9.0	)		34.5
Quarter ended September 30, 2006	$	226.8	$	21.1		$	150.1		$	398.0

($ millions)		Crude Oil		NGLs			Natural Gas			Total
Year-to-date ended September 30, 2005	$	409.5	$	57.5		$	553.5		$	1,020.5
Price variance(1)		92.7		7.8			(32.7	)		67.8
Volume variance		130.5		(1.0	)		(14.6	)		114.9
Year-to-date ended September 30, 2006	$	632.7	$	64.3		$	506.2		$	1,203.2

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

Page 10

ROYALTIES

Royalties are paid to various government entities and other land and mineral rights owners. For the three and nine months ended September 30, 2006 royalties were $70.0 million and $227.7 million, 18% and 19% of oil and gas sales, net of transportation, respectively. For the three and nine months ended September 30, 2005 royalties were $78.7 million and $205.5 million, approximately 20% of oil and gas sales, net of transportation. Lower royalty crude oil sales have increased and higher royalty natural gas sales have decreased due to the change in volumes and prices year over year. We continue to maintain our guidance, expecting royalties to be approximately 19% of oil and gas sales, net of transportation, for the remainder of the year.

OPERATING EXPENSES

Operating expenses for the three months ended September 30, 2006 were $59.7 million or $7.68/BOE compared to $56.2 million or $7.69/BOE for the third quarter of 2005. For the nine months ended September 30, 2006 operating costs were $183.0 million or $7.85/BOE compared to $159.7 million or $7.51/BOE for the same period in 2005. Operating costs have increased during 2006 compared to 2005 due to cost pressures associated with the high level of industry activity. The areas most impacted by these activity levels include scheduled facility maintenance and well servicing. Lower cost operations resulting from our U.S. acquisitions during 2005 have helped offset the overall increase on a BOE basis.

We are decreasing our annual operating cost guidance from $7.95/BOE to $7.80/BOE to reflect the impact from the 1,500 BOE/day increase to our production guidance.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative (“G&A”) expenses for the third quarter of 2006 were 3% higher than the second quarter of 2006, due to increased non-cash expenses related to our trust unit rights incentive plan.

G&A expenses for the three months ended September 30, 2006 were $15.0 million or $1.93/BOE compared to $10.6 million or $1.45/BOE for the third quarter of 2005. G&A expenses totaled $42.9 million or $1.84/BOE for the nine months ended September 30, 2006 compared to $27.5 million or $1.29/BOE for the same period in 2005. These increases are primarily due to compensation costs associated with higher staffing levels, increased investment in information systems and technology, costs associated with Sarbanes Oxley compliance and our contribution to education through the Southern Alberta Institute of Technology. In addition, non-cash charges associated with our trust unit rights incentive plan have increased due to the increase in our trust unit price over the last three years as well as the increased number of rights outstanding. Due to these cost pressures we are maintaining our guidance for G&A costs at $1.85/BOE for 2006, despite the increased guidance for annual average production.

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 5 for further details. For the three months ended September 30, 2006 these charges were $1.8 million or $0.23/BOE compared to $0.8 million or $0.11/BOE for the same period in 2005. For the nine months ended September 30, 2006 these charges were $4.3 million or $0.18/BOE compared to $2.2 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 September 30,				Nine months ended September 30,
($ millions)		2006		2005		2006		2005
Cash	$	13.2	$	9.8	$	38.6	$	25.3
Non-cash trust unit rights incentive plan (1)		1.8		0.8		4.3		2.2
Total G&A	$	15.0	$	10.6	$	42.9	$	27.5

(Per BOE)
Cash	$	1.70	$	1.34	$	1.66	$	1.19
Non-cash trust unit rights incentive plan (1)		0.23		0.11		0.18		0.10
Total G&A	$	1.93	$	1.45	$	1.84	$	1.29

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

Page 11

INTEREST EXPENSE

Interest expense in the third quarter of 2006 increased by $1.6 million compared to the second quarter of 2006 as a result of higher average debt outstanding and higher interest rates during the quarter. Interest expense was $9.4 million for the third quarter of 2006 compared to $6.0 million during the same period in 2005 and $25.4 million for the nine months ended September 30, 2006 compared to $17.7 million during the same period in 2005. These increases are due to higher average indebtedness and higher interest rates during 2006 compared to the same periods during 2005.

At September 30, 2006, 23% of our debt was based on fixed interest rates while 77% was floating.

CAPITAL EXPENDITURES

We spent $131.7 million and $368.1 million on development drilling and facilities for the three and nine months ended September 30, 2006, respectively, compared to $91.8 million and $229.6 million during the same periods in 2005. We achieved a 99% success rate with our drilling program as 145.3 net wells were drilled during the third quarter and 304.3 net wells were drilled year to date for 2006. Development in 2006 focused primarily on U.S. Bakken oil, waterflood, and joint venture deep gas.

Property acquisitions were $4.3 million and $46.5 million for the three and nine months ended September 30, 2006, compared to $1.7 million and $7.3 million for the same periods in 2005. Property dispositions were $0.2 million and $21.0 million for the three and nine months ended September 30, 2006, compared to $0.4 million and $66.9 million for the same periods in 2005. The majority of our 2006 divestments relate to the sale of a 1% interest in the Joslyn project, compared to the 2005 non-core divestment program which raised $66.9 million.

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

	Three months ended September 30,						Nine months ended September 30,
Capital Expenditures ($ millions)		2006			2005			2006			2005
Development expenditures	$	96.0		$	64.7		$	284.0		$	174.9
Plant and facilities		35.7			27.1			84.1			54.7
Development Capital		131.7			91.8			368.1			229.6
Office		1.0			1.1			2.3			3.3
Sub-total		132.7			92.9			370.4			232.9
Acquisitions of oil and gas properties(1)		4.3			1.7			46.5			7.3
Corporate acquisitions		-			584.2			-			584.2
Dispositions of oil and gas properties(1)		(0.2	)		(0.4	)		(21.0	)		(66.9	)
Total Net Capital Expenditures	$	136.8		$	678.4		$	395.9		$	757.5
Total Capital Expenditures financed with funds flow	$	87.0		$	58.2		$	208.2		$	140.1
Total Capital Expenditures financed with debt and equity		49.8			620.2			207.2			617.4
Total non-cash consideration for 1% sale of Joslyn project		-			-			(19.5	)		-
Total Net Capital Expenditures	$	136.8		$	678.4		$	395.9		$	757.5

⁽¹⁾ Net of post-closing adjustments.

Year-to-date we have spent $368.1 million on development capital and we continue to maintain our 2006 annual guidance of $485 million for development capital spending.

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 and nine months ended September 30, 2006, DDA&A increased to $16.64/BOE and $15.54/BOE, respectively, compared to $13.47/BOE and $12.75/BOE during the corresponding periods in 2005. These increases in DDA&A are due to increased property, plant and equipment from acquisitions completed during the second half of 2005.

Page 12

No impairment of the Fund’s assets existed at September 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 accounting and tax bases of the operating companies' assets and liabilities. Net income of the operating companies and the tax recovery fluctuate based on the royalty and interest payments to the Fund. Therefore, the future income tax that is recorded on the balance sheet is recovered through earnings over time.

The future income tax recovery for the three and nine months ended September 30, 2006 was $32.3 million and $78.9 million, respectively. The future income tax recoveries for the same periods in 2005 were $4.2 million and $50.9 million, respectively. The change year-over-year is due to a $32.2 million future income tax recovery recorded in the second quarter of 2006 to reflect the reduction in the federal and corporate tax rates and a change in estimate of the royalty payments between the operating subsidiaries and the Fund.

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 nine months ended September 30, 2006 our U.S. operations incurred income related taxes in the amount of $3.1 million and $13.1 million, respectively, compared to $3.1 million for the three and nine months ended September 30, 2005.

The amount of current taxes recorded throughout the year is dependent upon the level of U.S. funds flow as well as the timing of both capital expenditures and repatriation of the funds to Canada. The U.S. taxes as a percentage of funds flow was 8% for the nine months ended September 30, 2006 due primarily to an acceleration of our capital expenditure program and related deductions combined with an adjustment for prior period tax returns. Consequentially, we are revising our guidance and expect the current income and withholding taxes to average approximately 15% of funds flow from U.S. operations in 2006 rather than our previous guidance of 20%.

SELECTED FINANCIAL RESULTS

	Three months ended September 30,						Nine months ended September 30,
Per BOE of production (6:1)		2006			2005			2006			2005
Production per day		84,553			79,406			85,335			77,910
Weighted average sales price (1)	$	51.18		$	54.57		$	51.65		$	47.98
Royalties		(9.01	)		(10.77	)		(9.78	)		(9.66	)
Financial contracts		2.05			(5.65	)		0.09			(4.73	)
Add back / (deduct): Non-cash financial contracts		(2.15	)		(0.38	)		(1.82	)		0.33
Operating costs		(7.68	)		(7.69	)		(7.85	)		(7.51	)
General and administrative (2)		(1.93	)		(1.45	)		(1.84	)		(1.29	)
Add back: Non-cash G&A expense (trust unit rights) (2)		0.23			0.11			0.18			0.10
Interest expense, net of interest and other income		(0.96	)		(0.66	)		(0.91	)		(0.73	)
Foreign exchange gain (loss)		0.08			(0.11	)		0.12			(0.10	)
Deduct: Non-cash foreign exchange loss		-			(0.48	)		(0.12	)		(0.11	)
Capital taxes		(0.11	)		(0.26	)		(0.11	)		(0.24	)
Current income tax		(0.40	)		(0.42	)		(0.56	)		(0.14	)
Restoration and abandonment cash costs		(0.21	)		(0.22	)		(0.31	)		(0.24	)
Funds flow from operations		31.09			26.59			28.74			23.66
Restoration and abandonment cash costs		0.21			0.22			0.31			0.24
Non-cash items:
Depletion, depreciation, amortization and accretion		(16.64	)		(13.47	)		(15.54	)		(12.75	)
Financial contracts		2.15			0.38			1.82			(0.33	)
G&A expense (trust unit rights) (2)		(0.23	)		(0.11	)		(0.18	)		(0.10	)
Foreign exchange		-			0.48			0.12			0.11
Future income tax recovery		4.16			0.58			3.39			2.39
Total net income per BOE	$	20.74		$	14.67		$	18.66		$	13.22

⁽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 13

SELECTED CANADIAN AND U.S. FINANCIAL RESULTS

The following tables provide a geographical analysis of key financial results for the three and nine months ended September 30, 2006.

	Three months ended September 30, 2006
(CDN$ millions, except per unit amounts)		Canada			U.S.			Total
Daily Production Volumes
Natural gas (Mcf/day)		260,381			5,911			266,292
Crude oil (bbls/day)		25,288			10,664			35,952
Natural gas liquids (bbls/day)		4,199			-			4,199
Total Daily Sales (BOE/day)		72,884			11,649			84,533
Pricing (1)
Natural gas (per Mcf)	$	6.09		$	7.69		$	6.13
Crude oil (per bbl)	$	66.28		$	74.00		$	68.57
Natural gas liquids (per bbl)	$	54.63		$	-		$	54.63
Capital Expenditures
Development capital and office	$	99.0		$	33.7		$	132.7
Acquisitions of oil and gas properties	$	3.6		$	0.7		$	4.3
Dispositions of oil and gas properties	$	(0.2	)	$	-		$	(0.2	)
Revenues
Oil and gas sales (1)	$	321.2		$	76.8		$	398.0
Royalties (2)	$	(55.3	)	$	(14.7	)	$	(70.0	)
Financial contracts	$	15.9		$	-		$	15.9
Expenses
Operating	$	57.6		$	2.1		$	59.7
General and administrative	$	12.1		$	2.9		$	15.0
Depletion, depreciation, amortization and accretion	$	98.3		$	31.1		$	129.4
Current income taxes	$	-		$	3.1		$	3.1

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

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

	Nine months ended September 30, 2006
(CDN$ millions, except per unit amounts)		Canada			U.S.			Total
Daily Production Volumes
Natural gas (Mcf/day)		262,983			5,717			268,700
Crude oil (bbls/day)		25,843			10,222			36,065
Natural gas liquids (bbls/day)		4,487			-			4,487
Total Daily Sales (BOE/day)		74,160			11,175			85,335
Pricing (1)
Natural gas (per Mcf)	$	6.86		$	8.16		$	6.89
Crude oil (per bbl)	$	61.72		$	70.71		$	64.27
Natural gas liquids (per bbl)	$	52.49		$	-		$	52.49
Capital Expenditures
Development capital and office	$	281.8		$	88.6		$	370.4
Acquisitions of oil and gas properties	$	31.2		$	15.3		$	46.5
Dispositions of oil and gas properties	$	(21.0	)	$	-		$	(21.0	)
Revenues
Oil and gas sales (1)	$	993.1		$	210.1		$	1,203.2
Royalties (2)	$	(187.7	)	$	(40.0	)	$	(227.7	)
Financial contracts	$	2.2		$	-		$	2.2
Expenses
Operating	$	177.5		$	5.5		$	183.0
General and administrative	$	37.8		$	5.1		$	42.9
Depletion, depreciation, amortization and accretion	$	276.3		$	85.8		$	362.1
Current income taxes	$	-		$	13.1		$	13.1

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

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

Page 14

QUARTERLY FINANCIAL INFORMATION

Generally, oil and gas sales have increased due to higher prices and production through both 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, which are impacted by future prices, continue to cause net income to fluctuate between quarters.

Quarterly information is summarized in the following table:

Quarterly Financial Information

($ millions, except per trust unit amounts)	Oil and Gas				Net	Net income per trust unit
	Revenue(1)				Income		Basic		Diluted
2006
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
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.

ACCUMULATED DEFICIT

During the quarter presentation changes were made to combine the previously reported accumulated income and accumulated cash distributions figures on the balance sheet into a single accumulated deficit balance. 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, financial contract gains and losses, unit based compensation charges and future income tax provisions.

NET INCOME

Net income for the third quarter of 2006 was $161.3 million or $1.31 per trust unit compared to $107.1 million or $0.97 per trust unit for the third quarter of 2005. The increase in net income was primarily due to lower royalties and risk management costs and increased financial contract gains and future income tax recoveries. Net income for the nine months ended September 30, 2006 was $434.6 million or $3.59 per trust unit compared to $281.1 million or $2.64 per trust unit for the same period in 2005. The nine month increase is due to increased oil and gas sales, reduced risk management costs and an increased future income tax recovery, partially offset by the increases in royalties, operating costs and DDA&A charges.

Page 15

FUNDS FLOW

Funds flow is calculated as cash flow from operating activities before changes in non-cash working capital.

Funds flow for the third quarter of 2006 was 13% higher than the second quarter of 2006 due to reductions in cash price risk management costs, royalties and operating costs. For the three months ended September 30, 2006, funds flow was $241.8 million or $1.97 per trust unit compared to $194.2 million or $1.77 per trust unit for the same period in 2005. For the nine months ended September 30, 2006, funds flow was $669.7 million or $5.53 per trust unit compared to $503.2 million or $4.73 per trust unit for the same period in 2005. Funds flow increased during the nine months ended September 30, 2006 as a result of higher oil and gas sales and reduced cash price risk management costs, offset in part by the increases in operating costs and G&A expenses.

CASH AVAILABLE FOR DISTRIBUTION

Sustainability of our Distributions and Asset Base

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

Acquisitions and development activities 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 we are required to withhold cash flow to finance these activities, the amount of cash available for distribution will be reduced. Should external sources of capital become limited or unavailable, our ability to make the necessary acquisitions and development expenditures to maintain or expand our asset base may be impaired and the amount of cash available for distribution will be reduced.

Distribution Policy

The amount of cash available for distribution is proposed by management and approved by the Board of Directors. We continually assess distribution levels with respect to forecasted funds flow, debt levels and capital spending plans. The level of cash withheld can vary between 10% and 40% of annual funds flow and is dependant 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.

Calculation of Cash Available for Distribution

Cash available for distribution is calculated as funds flow less discretionary amounts withheld for capital expenditures, acquisitions and debt repayments.

Actual asset retirement costs incurred in the period are deducted for purposes of calculating cash available for distribution. Differences between actual site restoration costs incurred and the amortization of the capitalized asset retirement cost and accretion of the asset retirement obligation are discussed in the asset retirement obligation section of the MD&A.

Reconciliation of Cash Flow from Operating Activities, Funds Flow and Cash Available for Distribution

The following table reconciles Enerplus’ cash flow from operating activities, as presented on the consolidated statements of cash flows, to funds flow and cash available for distribution.

	Three months ended September 30,						Nine months ended September 30,
($ millions, except per unit amounts)		2006			2005			2006			2005
Cash flow from operating activities	$	268.9		$	180.7		$	656.6		$	486.2
Change in non-cash working capital		(27.1	)		13.5			13.1			17.0
Funds flow		241.8			194.2			669.7			503.2
Cash withheld for acquisitions, capital expenditures and debt repayment(1)		(87.0	)		(58.2	)		(208.2	)		(140.1	)

Page 16

Cash available for distribution(2)	$	154.8		$	136.0		$	461.5		$	363.1
Cash available for distribution per trust unit	$	1.26		$	1.16		$	3.78		$	3.28
Payout ratio(3)		64	%		70	%		69	%		72	%

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

PAYOUT RATIO

Our payout ratio is calculated as cash available for distribution divided by funds flow.

Our payout ratio for the three and nine months ended September 30, 2006 was 64% and 69% respectively, compared to a payout ratio of 70% and 72% for the three and nine month periods in 2005. For the nine months ended September 30, 2006, we funded 56% of our capital spending, or $208.2 million, by withholding a portion of our funds flow from operations. The remainder of our capital spending and our net acquisitions in 2006 were financed from the proceeds of our March 2006 equity issue.

ASSET RETIREMENT OBLIGATION

The following chart compares the amortization of the asset retirement cost, accretion of the asset retirement obligation, and actual site restoration costs incurred.

	Three months ended September 30,				Nine months ended September 30,
($ millions)		2006		2005		2006		2005
Amortization of the asset retirement cost	$	3.3	$	2.7	$	9.4	$	7.9
Accretion of the asset retirement obligation		1.6		1.6		4.6		4.9
Total Amortization and Accretion	$	4.9	$	4.3	$	14.0	$	12.8
Actual Site Restoration Costs Incurred	$	1.6	$	1.6	$	7.2	$	5.0

The timing of actual asset retirement costs will differ from the timing of amortization and accretion charges. Actual asset retirement costs will be incurred over the next 66 years with the majority between 2026 and 2035. 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.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2006 our balance sheet remains strong with conservative debt levels of 0.6 times debt to trailing funds flow. This is a result of strong cash flow from operating activities and the net proceeds of $240.3 million from our March 2006 equity issue, offset by development capital spending.

During the nine months ended September 30, 2006 long-term debt, net of cash, decreased to $589.4 million, which is comprised of $260.8 million of bank indebtedness and $328.6 million of senior unsecured notes.

Subsequent to September 30, 2006 we extended our $850 million bank credit facility by one year to November 2009. In addition, floating interest rates under the facility were reduced and will range between 55.0 and 110.0 basis points over Bankers Acceptance rates, depending on our ratio of senior debt to earnings before interest, taxes and non cash items.

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

Financial Leverage and Coverage	September 30, 2006	December 31, 2005
Long-term debt to trailing funds flow	0.6x	0.8x
Funds flow to interest expense	28.7x	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).

Page 17

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. As at September 30, 2006 we are in compliance with our debt covenants. Refer to our 2005 Annual Information Form for a detailed description of these covenants.

Based on planned expenditures for 2006, we will have adequate liquidity to fund future working capital and planned capital expenditures primarily through funds flow from operations.

TRUST UNIT INFORMATION

We had 122,854,000 trust units outstanding at September 30, 2006 compared to 117,234,000 trust units at September 30, 2005 and 117,539,000 at December 31, 2005. The weighted average basic number of trust units outstanding for the nine months ended September 30, 2006 was 121,120,000 (2005 - 106,307,000).

For three months ended September 30, 2006, 272,000 trust units (2005 - 192,000) were issued pursuant to the Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan (“DRIP”) and the trust unit rights plan. This resulted in $13.7 million (2005 - $6.8 million) of additional equity to the Fund. For the nine months ended September 30, 2006, 945,000 trust units ($41.7 million additional equity) were issued pursuant to DRIP and the trust unit options and rights plans compared to 840,000 trust units ($28.0 million) during the same period in 2005. For further details see Note 5.

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

SUMMARY 2006 OUTLOOK

The following table summarizes our initial 2006 guidance from our 2005 Annual Report along with our year-to-date actuals and revised 2006 guidance:

Summary of 2006 Expectations		Initial 2006 Guidance			Actuals year-to-date September 30, 2006			Current / Revised 2006 Guidance
Average Annual Production		84,000 BOE/day			85,335 BOE/day			85,500 BOE/day
Exit rate December 2006 production		89,000 BOE/day						88,000 BOE/day
2006 production mix		53% gas, 43% oil, 4% NGL			52% gas, 43% oil, 5% NGL			52% gas, 43% oil, 5% NGL
Average royalty rate		19	%		19	%		19	%
Operating expenses	$	7.95/BOE		$	7.85/BOE		$	7.80/BOE
G&A costs	$	1.70/BOE		$	1.84/BOE		$	1.85/BOE
Capital taxes	$	6.5 million		$	2.6 million		$	3.5 million
U.S. income and withholding tax - cash costs		20	%		8	%		15	%
Average interest cost		4.5	%		4.9	%		5.0	%
Payout ratio		60% - 90	%		69	%		60% - 90	%
Development capital spending	$	485.0 million		$	368.1 million		$	485.0 million

Page 18

COMMITMENTS

Subsequent to September 30, 2006, we extended our $850 million bank credit facility by one year to November 2009.

CONSOLIDATED BALANCE SHEETS

(CDN$ thousands) (Unaudited)		September 30, 2006			December 31, 2005
Assets
Current assets
Cash	$	475		$	10,093
Accounts receivable		155,308			170,623
Deferred financial assets (Note 2)		35,019			49,874
Other current		26,061			26,751
		216,863			257,341
Property, plant and equipment (Note 3)		3,678,584			3,650,327
Goodwill		214,110			221,234
Other assets		31,102			1,721
	$	4,140,659		$	4,130,623
Liabilities
Current liabilities
Accounts payable	$	291,198		$	316,875
Distributions payable to unitholders		51,599			49,367
Deferred credits (Note 2)		-			57,368
		342,797			423,610
Long-term debt		589,895			659,918
Future income taxes		356,603			442,970
Asset retirement obligations (Note 4)		118,938			110,606
		1,065,436			1,213,494
Equity
Unitholders’ capital (Note 5)		3,696,862			3,410,614
Accumulated deficit		(926,197	)		(901,527	)
Cumulative translation adjustment		(38,239	)		(15,568	)
		2,732,426			2,493,519
	$	4,140,659		$	4,130,623

CONSOLIDATED STATEMENTS OF ACCUMULATED DEFICIT

		Three months ended September 30,						Nine months ended September 30,
(CDN$ thousands) (Unaudited)		2006			2005			2006			2005
Accumulated income, beginning of period	$	1,681,484		$	1,150,133		$	1,408,178		$	976,137
Net income		161,317			107,129			434,623			281,125
Accumulated income, end of period	$	1,842,801		$	1,257,262		$	1,842,801		$	1,257,262
Accumulated cash distributions, beginning of period	$	(2,614,298	)	$	(2,031,722	)	$	(2,309,705	)	$	(1,811,500	)
Cash distributions		(154,700	)		(130,057	)		(459,293	)		(350,279	)
Accumulated cash distributions, end of period	$	(2,768,998	)	$	(2,161,779	)	$	(2,768,998	)	$	(2,161,779	)
Accumulated deficit, end of period	$	(926,197	)	$	(904,517	)	$	(926,197	)	$	(904,517	)

Page 19

CONSOLIDATED STATEMENTS OF INCOME

	Three months ended September 30,						Nine months ended September 30,
(CDN$ thousands except per trust unit amounts) (Unaudited)		2006			2005			2006			2005
Revenues
Oil and gas sales	$	403,761		$	404,834		$	1,220,677		$	1,040,768
Royalties		(70,062	)		(78,659	)		(227,741	)		(205,484	)
Derivative instruments (Notes 2 and 7)
Financial contracts - qualified hedges		-			(6,149	)		-			(13,444	)
Other financial contracts		15,911			(35,162	)		2,179			(87,262	)
Interest and other income		1,940			1,161			4,201			2,093
		351,550			286,025			999,316			736,671
Expenses
Operating		59,689			56,186			182,960			159,698
General and administrative		14,997			10,591			42,862			27,462
Transportation		5,728			6,177			17,455			20,314
Interest on long-term debt		9,441			5,973			25,418			17,698
Foreign exchange (gain)/loss		(639	)		805			(2,893	)		2,046
Depletion, depreciation, amortization and accretion		129,400			98,413			362,134			271,171
		218,616			178,145			627,936			498,389
Income before taxes		132,934			107,880			371,380			238,282
Capital taxes		869			1,924			2,579			5,016
Current taxes		3,092			3,062			13,101			3,062
Future income tax recovery		(32,344	)		(4,235	)		(78,923	)		(50,921	)
Net Income	$	161,317		$	107,129		$	434,623		$	281,125
Net income per trust unit
Basic	$	1.31		$	0.97		$	3.59		$	2.64
Diluted	$	1.31		$	0.97		$	3.58		$	2.64
Weighted average number of trust units outstanding (thousands)
Basic		122,712			109,924			121,120			106,307
Diluted		123,126			110,359			121,511			106,650

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three months ended September 30,						Nine months ended September 30,
(CDN$ thousands) (Unaudited)		2006			2005			2006			2005
Operating Activities
Net income	$	161,317		$	107,129		$	434,623		$	281,125
Non-cash items add/(deduct):
Depletion, depreciation, amortization and accretion		129,400			98,413			362,134			271,171
Financial contracts (Note 2)		(16,754	)		(2,763	)		(42,513	)		6,952
Foreign exchange (gain)/loss		16			(3,483	)		(2,732	)		(2,295	)
Trust unit rights incentive plan (Note 5)		1,765			783			4,291			2,172
Future income tax recovery		(32,344	)		(4,235	)		(78,923	)		(50,921	)
Asset retirement costs incurred		(1,636	)		(1,613	)		(7,220	)		(5,011	)
		241,764			194,231			669,660			503,193
Decrease/(Increase) in non-cash working capital		27,140			(13,495	)		(13,071	)		(17,030	)
		268,904			180,736			656,589			486,163
Financing Activities
Issue of trust units, net of issue costs (Note 5)		13,713			473,710			281,957			494,904
Cash distributions to unitholders		(154,700	)		(130,057	)		(459,293	)		(350,279	)
(Decrease)/Increase in bank credit facilities		(14,692	)		71,260			(67,291	)		42,888
Decrease in non-cash financing working capital		101			6,135			2,232			6,941
		(155,578	)		421,048			(242,395	)		194,454
Investing Activities
Capital expenditures		(132,673	)		(92,958	)		(370,366	)		(232,908	)
Property acquisitions		(4,296	)		(1,610	)		(46,553	)		(7,291	)
Property dispositions		215			312			1,493			66,847
Corporate acquisitions, net of cash acquired		-			(483,013	)		-			(483,013	)
Decrease/(Increase) in non-cash investing working capital		24,798			9,003			(5,711	)		9,266

Page 20

		(111,956	)		(568,266	)		(421,137	)		(647,099	)
Effect of exchange rate changes on cash		(1,547	)		(940	)		(2,675	)		(940	)
Change in cash		(177	)		32,578			(9,618	)		32,578
Cash, beginning of period		652			-			10,093			-
Cash, end of period	$	475		$	32,578		$	475		$	32,578
Supplementary Cash Flow Information
Cash income taxes paid	$	-		$	-		$	3,770		$	-
Cash interest paid	$	4,563		$	4,228		$	19,324		$	14,521

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 third quarter of 2005 was a decrease to general and administrative expenses (“G&A”) of $6,782,000 (a decrease of $10,586,000 for the nine months ended September 30, 2005) and a decrease to contributed surplus of $5,838,000 (a decrease of $11,333,000 for the nine months ended September 30, 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)		89,491
Amortization of deferred financial assets (2)		(46,978	)
Deferred financial assets as at September 30, 2006	$	35,019

⁽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 $35,019,000, as at September 30, 2006, is comprised of the fair value of financial contracts of $32,123,000 and the remaining $2,896,000 asset related to the financial contracts for which hedge accounting was no longer applied after December 31, 2005.

Page 21

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

	Three months ended September 30,		Nine months ended September 30,
Other Financial Contracts ($ thousands)	2006	2005	2006	2005
Change in fair value	$(26,992)	$(3,483)	$(89,491)	$4,219
Amortization of deferred financial assets	10,238	720	46,978	2,733
Realized cash costs, net	843	37,925	40,334	80,310
Other financial contracts (gain) loss	$(15,911)	$35,162	$ (2,179)	$87,262

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

3. PROPERTY, PLANT AND EQUIPMENT

($ thousands)		September 30, 2006			December 31, 2005
Property, plant and equipment	$	5,685,477		$	5,306,137
Accumulated depletion, depreciation and amortization		(2,006,893	)		(1,655,810	)
Net property, plant and equipment	$	3,678,584		$	3,650,327

Capitalized development G&A of $10,157,000 (2005 - $7,825,000) is included in property, plant and equipment (“PP&E”) for the nine months ended September 30, 2006. Excluded from PP&E for the purpose of the depletion and depreciation calculation is $60,499,000 (2005 - $52,991,000) related to the Joslyn development project that has not yet commenced commercial production.

4. ASSET RETIREMENT OBLIGATIONS

The following table reconciles the Fund’s asset retirement obligations:

($ thousands)		Nine months ended September 30, 2006			Year ended December 31, 2005
Asset retirement obligations, beginning of period	$	110,606		$	105,978
Changes in estimates		4,113			8,764
Acquisition and development activity		6,843			6,791
Dispositions		(39	)		(9,413	)
Retirement obligations settled		(7,220	)		(7,829	)
Accretion expense		4,635			6,315
Balance, end of period	$	118,938		$	110,606

5. FUND CAPITAL

(a) Unitholders’ Capital

Trust Units

Authorized: Unlimited number of trust units

Issued:	Nine months ended September 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	572	20,392	805	24,737
Trust unit rights incentive plan (non-cash) - exercised		2,521	-	4,629
DRIP*, net of redemptions	373	21,278	339	15,613
Issued for acquisition of corporate and property interests (non-cash)	-	-	1,633	69,062
	122,854	3,692,045	117,539	3,407,567
Contributed Surplus (Trust unit rights incentive plan)	-	4,817	-	3,047
Balance, end of period	122,854	$3,696,862	117,539	$3,410,614

* Distribution Reinvestment and Unit Purchase Plan.

Page 22

Contributed surplus ($ thousands)		Nine months ended September 30, 2006			Year ended December 31, 2005
Balance, beginning of period	$	3,047		$	4,636
Trust unit rights incentive plan (non-cash) - exercised		(2,521	)		(4,629	)
Trust unit rights incentive plan (non-cash) - expensed		4,291			3,040
Balance, end of period	$	4,817		$	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 September 30, 2006, a total of 2,691,000 rights pursuant to the Trust Unit Rights Incentive Plan (“Rights Plan”) at an average exercise price of $47.88 were outstanding. This represents 2.2% of the total trust units outstanding of which 342,000 rights with an average exercise price of $34.88 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, second and third 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) and $0.51 per trust unit (effective January 2007), respectively.

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

	Nine months ended September 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		987			55.27			1,125			53.07
Exercised		(572	)		35.64			(805	)		30.72
Cancelled		(345	)		46.05			(100	)		37.15
End of period		2,691			47.88			2,621			42.80
Rights exercisable at the end of the period		342		$	34.88			643		$	32.46

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

The Fund uses a binomial option-pricing model to calculate the estimated fair value of rights under the plan. During the three and nine months ended September 30, 2006, non-cash compensation costs of $1,765,000 ($0.01 per unit) and $4,291,000 ($0.04 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 nine months ended September 30, 2005 was $783,000 ($0.01 per unit) and $2,172,000 ($0.02 per unit) respectively.

(c) Basic and Diluted per Trust Unit Calculations

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

	Nine months ended September 30,
(thousands)		2006	2005
Weighted average units		121,120	106,307
Dilutive impact of rights		391	343
Diluted trust units		121,511	106,650

6. COMMITMENTS AND CONTINGENCIES

Subsequent to September 30, 2006, the Fund extended its $850,000,000 bank credit facility by one year to November 2009.

7. FINANCIAL INSTRUMENTS

Page 23

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

The carrying value of cash, accounts receivable, deferred financial assets, other assets, 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 and other assets are carried at cost on the balance sheet and are adjusted to reflect other than temporary losses in value. The fair value of the marketable securities at September 30, 2006 exceeded the cost of these securities by $13,770,000. The Fund has US$54,000,000 of senior unsecured notes with fixed rate debt and a fair value of $59,726,000 at September 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 September 30, 2006 the fair value of the senior unsecured note was $203,451,000.

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 September 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 0.55% and 1.10%. These interest rate swaps mature between January 2007 and June 2011. The fair value of the $75,000,000 interest rate swaps as at September 30, 2006 represents an unrealized cost of $946,044. 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 September 30, 2006 represents an unrealized cost of $74,283,000 whereas the fair value of the underlying debt instrument as at September 30, 2006 represents an unrealized gain of $64,877,000. The cross currency swap has been designated as a hedge for accounting purposes.

Crude Oil Instruments

The net premium cost of the crude oil instruments entered into as of September 30, 2006 is $15,506,000. This amount will be charged to income over the term of the underlying contracts.

The following table summarizes the Fund’s crude oil risk management positions at November 1, 2006:

		WTI US$/bbl
	Daily Volumes bbls/day		Purchased Put		Sold Put	Fixed Price and Swaps
Term
October 1, 2006 - December 31, 2006
Put *	1,500	$	50.00		-	-
Put	1,500		-	$	41.00	-
October 1, 2006 - December 31, 2006
Put *	3,000	$	53.00		-	-
Put	3,000		-	$	43.00	-
October 1, 2006 - December 31, 2006
Put (1)	5,000	$	70.00		-	-
January 1, 2007 - December 31, 2007
Put (1)	5,000	$	71.00		-	-
Put (1)	2,500	$	68.00		-	-

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Put (2)	2,500	$	65.70	-		-
Swap (2)	2,500		-	-	$	66.24

* 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.

⁽¹⁾ Financial contracts entered into during the third quarter of 2006.

⁽²⁾ Financial contracts entered into subsequent to the third quarter of 2006.

Natural Gas Instruments

The net premium cost of the natural gas instruments entered into as of September 30, 2006 is $2,072,000. This amount will be charged to income over the term of the underlying contracts.

The following table summarizes the Fund’s natural gas risk management positions at November 1, 2006:

AECO CDN$/Mcf
Daily Volumes MMcf/day			Sold Call		Purchased Put	Sold Put		Fixed Price and Swaps
Term
October 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
October 1, 2006 - October 31, 2006
Put *	28.5		-	$	7.38	-		-
November 1, 2006 - March 31, 2007
Collar (1)	6.6	$	11.45	$	9.00	-		-
Costless Collar (1)	6.6	$	11.45	$	7.70	-		-
Collar (2)	9.5	$	9.50	$	7.00	-		-
Collar (2)	9.5	$	10.66	$	7.00	-		-
Put (2)	6.6		-	$	7.50	-		-
April 1, 2007 - October 31, 2007
Collar (1)	6.6	$	10.02	$	7.50	-		-
Collar (1)	6.6	$	9.00	$	7.50	-		-
Collar (2)	9.5	$	9.10	$	7.10	-		-
Collar (2)	9.5	$	9.15	$	7.14	-		-
Collar (2)	9.5	$	9.50	$	7.20	-		-
Swap (2)	6.6		-		-	-	$	7.60
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.

⁽¹⁾ Financial contracts entered into during the third quarter of 2006.

⁽²⁾ Financial contracts entered into subsequent to the third 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 September 30, 2006 is an unrealized gain of $365,000. Proceeds or costs realized from the electricity hedge are recognized as operating costs.

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The following table summarizes the Fund’s electricity management positions at November 1, 2006:

Term	Volumes MW/hr		Price CDN$/MWh
October 1, 2006 - December 31, 2006	5.0	$	49.99
October 1, 2006 - December 31, 2006	5.0	$	59.90
January 1, 2007 - December 31, 2007	5.0	$	61.50
January 1, 2007 - December 31, 2007 (1)	4.0	$	62.90
January 1, 2008 - September 30, 2008 (1)	4.0	$	63.00

⁽¹⁾ Financial contracts entered into during the third quarter of 2006.

8. EVENTS SUBSEQUENT TO SEPTEMBER 30, 2006

On October 31, 2006 Canada’s Finance Minister announced plans to tax distributions from publicly traded income trusts. For existing income trusts, such as Enerplus, the government is proposing a four-year transition period which would result in the tax measures being effective for 2011.

The measures appear intended to effectively tax trusts the same as corporations. At this time it is unknown if and when these proposals could be passed in parliament.

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

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.

For further information and a complete copy of the 2006 Third Quarter Interim report, please contact Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com.

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This news release contains certain forward-looking statements, which are based on Enerplus' current internal expectations, estimates, projections, assumptions and beliefs. Some of the forward-looking statements may be identified by words such as "expects", "anticipates", "believes", "projects", "plans" and similar expressions. These statements are not guarantees of future performance and involve a number of risks and uncertainties. Such forward-looking statements necessarily involve known and unknown risks and uncertainties, which may cause Enerplus' actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things, changes in general economic, market and business conditions; changes or fluctuations in production levels, commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; changes to legislation, investment eligibility or investment criteria; Enerplus' ability to comply with current and future environmental or other laws; Enerplus' success at acquisition, exploitation and development of reserves; actions by governmental or regulatory authorities including increasing taxes, changes in investment or other regulations; and the occurrence of unexpected events involved in the operation and development of oil and gas properties. Enerplus has adopted the standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Many of these risks and uncertainties are described in Enerplus' Annual Information Form and Enerplus' Management's Discussion and Analysis. Readers are also referred to risk factors described in other documents Enerplus files with the Canadian and U.S. securities authorities. Copies of these documents are available without charge from Enerplus. Enerplus disclaims any responsibility to update these forward-looking statements.

Gordon J. Kerr

President & Chief Executive Officer

Enerplus Resources Fund

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