Edgar Filing: ENERPLUS RESOURCES FUND

FORM 6-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Report of Foreign Issuer pursuant to Rule 13-a-16 or 15d-16
of the Securities Exchange Act of 1934

FOR THE MONTH OF MARCH, 2003

COMMISSION FILE NUMBER 1-15150

The Dome Tower

Suite 3000, 333 – 7^th Avenue S.W.

Calgary, Alberta

Canada T2P 2Z1

(403) 298-2200

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F o Form 40-F ý

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Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7)

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Indicate by check mark whether, by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the securities Exchange Act of 1934.

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EXHIBIT INDEX

EXHIBIT 1 ENERPLUS ANNOUNCES 2002 YEAR END RESULTS

EXHIBIT 1

FOR IMMEDIATE RELEASE

March 7, 2003

FOR IMMEDIATE RELEASE

Enerplus Resources Fund

TSX: ERF.un

NYSE: ERF

ENERPLUS ANNOUNCES 2002 YEAR END RESULTS

Enerplus Resources Fund is pleased to announce the results of operations for the year ended December 31, 2002.

2002 HIGHLIGHTS

• Enerplus Unitholders realized a total return of 26.5% in 2002;

• Cash distributions paid to Unitholders totaled $3.32 per unit with an additional $0.62 per unit retained for debt repayment;

• The Fund replaced 181% of its production and increased its established crude oil and natural gas reserves by 6% over 2001 levels, with over 14.9 MMBOE of established reserves added through our successful development program;

• Enerplus successfully completed over $218 million of acquisitions, acquiring reserves at an attractive cost of $8.22 per established BOE;

• Enerplus continued with its active development program, investing $141.7 million in development drilling and facility enhancements for 2002, drilling 300 net wells with a 99% success rate;

• The Fund successfully maintained production volumes throughout the year with average daily volumes of 62,784 BOE while achieving a decrease in operating expenses of $0.23/BOE from $6.09/BOE to $5.86/BOE;

• Enerplus diversified its debt portfolio through the issuance of US$175 million senior, 12-year amortizing unsecured notes with the proceeds reducing the Fund’s bank indebtedness;

• Successfully completed the inaugural cross-border equity financing raising over $200 million to fund acquisition and development activities;

• Subsequent to year-end, Enerplus announced plans to internalize its management structure by acquiring all of the outstanding shares of the management company, Enerplus Global Energy Management Company (“EGEM”), for consideration of approximately $48.9 million. In addition, EGEM agreed to fix the management fee for the period January 1, 2003 to April 23, 2003 in an amount of $3.2 million. The proposed transaction will eliminate all management fees effective April 23, 2003. The transaction is subject to Unitholder approval at the annual general and special meeting to be held on April 23, 2003.

Operations Review

During 2002, Enerplus successfully invested $141.7 million in value creation activities that improved the oil and gas production and recovery in our existing assets. We brought on approximately 11,575 BOE/day of new production at an average cost of $12,242 per daily barrel and added 14.9 million barrels of new established reserves. We drilled or participated in 300 net wells with a 99% success factor, optimized our core waterfloods, completed 66 land transactions and expanded our inventory of future projects with emerging opportunities in coal bed methane, shallow gas development, oil sands and attractive light oil developments.

2002 Drilling Activity	Crude Oil Wells		Natural Gas Wells		Dry & Abandoned Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	50.0	17.0	307.0	239.4	8.0	4.2	365.0	260.6
Saskatchewan	28.0	13.7	28.0	25.2	—	—	56.0	38.9
British Columbia	—	—	—	—	—	—	—	—
Total	78.0	30.7	335.0	264.6	8.0	4.2	421.0	299.5

Acquisitions

Enerplus enjoyed a successful year on the acquisition front in 2002 closing $218.7 million of acquisitions resulting in the purchase of 26.6 MMBOE of established reserves and 7,548 BOE/day of production. Established reserves and production were added at $8.22/BOE and $28,970 per BOE/day respectively. These acquisitions replaced 116% of 2002 production and will provide significant low-risk development potential in the future. Enerplus acquired working interests in various oil and gas properties for $60.6 million. The major property acquisitions include an incremental working interest in the Medicine Hat Glauc. “C” operated property for consideration of $20.5 million and the acquisition of a 16% working interest in Oil Sands Lease #24 (also known as the Joslyn Creek Lease) for $16.4 million. On October 21, 2002 Enerplus also completed the acquisition of Celsius Energy Resources Ltd. for $161.4 million.

Acquisition Summary

	Crude oil bbls/day	Natural gas Mcf/day	NGLs bbls/day	Total BOE/day	Total Cost Per Daily BOE
Daily Production*	3,064	25,098	301	7,548	$	28,970

*Enerplus received only a partial year benefit of the entire daily production volumes acquired in 2002, depending upon the closing date of each acquisition.

	Crude oil MMbbl	Natural gas Bcf	NGLs MMbbl	Total MMBOE	Total Cost Per BOE
Reserves:
Proven	7.8	79.3	1.1	22.1	$	9.90
Established	10.5	89.0	1.3	26.6	$	8.22

Acquisition Subsequent to Year-End:

On March 5, 2003, Enerplus acquired all of the outstanding shares and debt of PCC Energy Inc. and PCC Energy Corp., (collectively “PCC”) which are wholly-owned Canadian subsidiaries of US-based PetroCorp Incorporated for cash consideration of $167.6 million. This transaction provides high-quality, long-life gas assets in large established pools and adds approximately 4,380 BOE/day of production and 17.2 MMBOE of established reserves after adjustments for a royalty arrangement to a third party which is structured as a net profits interest. The properties have an established reserve life index of 10.7 years and 74% of the production is natural gas. Approximately 79% of the value of PCC is concentrated in eight properties, which are high quality, long-life, deep-gas properties with drilling potential. The operating costs associated with the PCC assets are approximately $4.00/BOE. The production and reserves associated with this acquisition will be recorded by Enerplus from March 2003 onward.

Reserves:

Enerplus ended 2002 with a record 330.4 MMBOE of established reserves, up 6% from 2001 and the highest level of reserves achieved in the Fund’s history. Acquisition activities, net of dispositions, added 26.0 MMBOE of established reserves with development activities resulting in the addition of 14.9 MMBOE of established reserves, also a record achievement. Significant shallow natural gas reserve additions were realized at Medicine Hat, Hanna Garden, Verger, and Countess while major oil-related reserve additions were achieved at Giltedge, Joarcam, and Gleneath.

2002 Reserves Summary	Crude oil MMbbl	Natural gas Bcf	NGLs MMbbl	Total MMBOE
Total established reserves as at December 31, 2001	113.7	1,081	18.5	312.4
Proven, producing	94.9	787	14.0	240.1
Proven, non-producing	10.3	215	2.0	48.1
Total proven	105.2	1,002	16.0	288.2
Total probable at 50%	16.7	139	2.3	42.2
Total established reserves at December 31, 2002	121.9	1,141	18.3	330.4

	Crude oil MMbbl				Natural gas Bcf				NGLs MMbbl				Total MMBOE				Established MMBOE
Reserves Reconciliation	Prov.		Prob.		Prov.		Prob.		Prov.		Prob.		Prov.		Prob.
Reserves at December 31, 2001	94.8		37.6		951.1		260.7		16.1		4.7		269.5		85.8		312.4
Acquisitions	7.8		5.5		79.3		19.5		1.1		0.4		22.1		9.1		26.6
Divestments	(0.6	)	—		(0.2	)	—		—		—		(0.6	)	—		(0.6	)
Production	(8.5	)	—		(76.8	)	—		(1.6	)	—		(22.9	)	—		(22.9	)
Drilling, Development & Revisions	11.7		(9.7	)	48.5		(2.6	)	0.4		(0.5	)	20.2		(10.6	)	14.9
Reserves at December 31, 2002	105.2		33.4		1,001.9		277.6		16.0		4.6		288.2		84.3		330.4

The present value of the reserves at December 31, 2002 increased over 24% from the prior period using a 12% discount rate. Net asset value per trust unit increased by 11% on a year-over-year basis. This is significant considering the increase of 19% in the number of outstanding trust units at December 31, 2002, versus December 31, 2001. The increased value was primarily driven by an increase in commodity pricing and reserves. The natural gas and oil price forecasts used by Sproule Associates Limited (“Sproule”) were significantly higher as compared to the prior year. Positive established reserve revisions and additions resulting from our successful development programs also helped increase net asset value per trust unit.

Present Worth of Production Revenue ($millions) (including ARTC)	10%		12%
Total established reserves at December 31, 2001	$	1,785.4	$	1,610.3

Proven, producing	1,805.7		1,665.5
Proven, non-producing	225.0		194.0
Total proven	2,030.7		1,859.5
Probable @ 50%	163.3		137.8
Total established reserves at December 31, 2002	$	2,194.0	$	1,997.3

Net Asset Value ($millions, except per Trust Unit amount)	10%			12%
Net Asset Value per Trust Unit as at December 31, 2001(1)	$	20.46		$	17.94
Present value of established reserves at December 31, 2002	$	2,194.0		$	1,997.3
Undeveloped acreage and seismic (acreage valued at $50/acre)	23.2			23.2
Bank debt	(361.7		)	(361.7		)
Working capital excluding distributions to Unitholders	(2.5		)	(2.5		)
Net asset value	$	1,853.0		$	1,656.3
Net asset value per Trust Unit(2)	$	22.35		$	19.98

(1) Based on 69.532 million Trust Units outstanding as at December 31, 2001

(2) Based on 82.898 million Trust Units outstanding as at December 31, 2002

Enerplus’ net asset value is measured with reference to the present value of future net cash flows from our reserves as estimated by independent reserve engineers, Sproule plus land values, adjusted for working capital and long-term debt at year-end. This calculation can vary significantly depending on the oil and natural gas price assumptions used by Sproule. In addition, this calculation ignores “going concern” value and assumes only the reserves identified in the Sproule report with no further acquisitions, despite our 17-year history of replacing production through acquisition and development.

Amendment to Trust Indenture

Enerplus has amended its Trust Indenture which allows the Fund to adopt certain non-resident ownership constraints, from time to time, to ensure that the Fund maintains its mutual fund trust status. Following this amendment, Enerplus may impose a limit on the number of its outstanding Trust Units that may be beneficially owned by non-residents of Canada (within the meaning of the Income Tax Act). If the number of non-resident unitholders of the Fund has exceeded, or appears that it will likely exceed, that threshold, Enerplus will notify non-resident unitholders that certain limitations will be placed on the transfer and issuance of Trust Units to non-residents of Canada, and that some non-residents (generally chosen in the inverse order to the order of acquisition of the Trust Units) may be required to sell their Trust Units in order to reduce the total number of Trust Units held by non-residents. The non-resident ownership restrictions adopted by Enerplus are similar to those in place for other income funds and royalty trusts in Canada.

MANAGEMENT’S DISCUSSION & ANALYSIS

RESULTS OF OPERATIONS

Production

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 indicated.

Daily production during 2002 averaged 62,784 BOE/day, representing a 16% increase over average production volumes of 54,015 BOE/day for the previous year. Although the majority of this increase was a result of the Merger, acquisitions completed during the year accounted for annualized production of 1,900 BOE/day primarily from the addition of Celsius Energy Resources Ltd. (“Celsius”) which closed on October 21, 2002 and the additional interest of the Medicine Hat Glauc “C” property which closed in March of 2002. Enerplus’ production before acquisitions was on target with expectations for the year. The Fund will see the full impact of these acquisitions in 2003.

Enerplus’ production is widely distributed across more than 250 properties in Alberta, Saskatchewan and British Columbia. The largest 10 properties account for 31% of Enerplus’ production. This wide distribution minimizes the risk that production might be materially impacted by the performance of a few major properties.

Average production volumes for the years ended December 31, 2002 and 2001 are outlined below:

Daily Production Volumes	2002	2001(1)	% Change
Natural gas (Mcf/day)	210,517	176,671	19	%
Crude oil (bbls/day)	23,288	20,592	13	%
Natural gas liquids (bbls/day)	4,410	3,978	11	%
Total daily sales (BOE/day)	62,784	54,015	16	%

(1) 2001 production reflects only 193 days of the post-merger Enerplus production after the date of the Merger.

Enerplus’ exit production rate averaged 67,800 BOE/day for the month of December 2002, with a weighting of 58% natural gas, 36% crude oil, and 6% natural gas liquids. Production, prior to any further acquisitions is expected to average 68,900 BOE per day in 2003, assuming capital development spending of approximately

$155 million, but without taking into account any further acquisitions. This production estimate is based on a full year benefit of the Celsius acquisition and the PCC acquisition from the closing date of March 5, 2003.

Pricing and Price Risk Management

The average price that Enerplus received for its natural gas (before hedging) decreased 21% from $4.91/Mcf in 2001 to $3.87/Mcf in 2002. In comparison, the AECO Monthly Index decreased 35% from $6.30/Mcf in 2001 to $4.07/Mcf in 2002 and the NYMEX Henry Hub index price decreased 26% from US$4.38/Mcf in 2001 to US$3.25/Mcf in 2002. The Fund has a balanced natural gas portfolio of spot and term contracts that will respond differently to the market than the reference indices. The wider basis differential between the AECO and NYMEX indices, the strengthening Canadian dollar, and the physical fixed price contracts helped reduce the Fund’s exposure to price volatility.

The average price that Enerplus received for its crude oil (before hedging) increased 13% from $30.48/bbl in 2001 to $34.37/bbl in 2002. Although there was virtually no change in the average price of benchmark West Texas Intermediate (WTI) crude oil from US$25.97 in 2001 to US$26.08 in 2002, Enerplus realized the benefit from a narrowing in the price differentials on it’s heavier streams of crude oil during the year and a slightly weaker Canadian dollar.

The realized prices for natural gas liquids (“NGLs”) decreased 17% from $31.12/bbl in 2001 to $25.68/bbl during 2002. These prices tend to be influenced by the corresponding prices for natural gas.

Average Selling Price (Before the Effects of Hedging)	2002		2001		% Change
Natural gas (per Mcf)	$	3.87	$	4.91	-21	%
Crude oil (per bbl)	34.37		30.48		13	%
Natural gas liquids (per bbl)	25.68		31.12		-17	%
Total daily sales (per BOE)	$	27.49	$	29.89	-8	%

Average Benchmark Pricing	2002		2001		% Change
AECO natural gas (per Mcf)	$	4.07	$	6.30	-35	%
NYMEX natural gas (US$per Mcf)	3.25		4.38		-26	%
WTI crude oil (US$per bbl)	26.08		25.97		0	%
CDN$/US$exchange rate	$	0.6369	$	0.6458	-1	%

Enerplus has an on-going commodity price risk management program that is designed to provide price protection on a portion of its future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. The program is intended to provide a measure of stability to the Fund’s cash distributions as well as ensure Enerplus realizes positive economic returns from its capital development and acquisition activities.

In 2002, Enerplus realized a cost of $8.7 million compared to a $50.1 million gain in 2001 as a result of its price risk management program, as outlined below:

Gain (Cost) from Financial Hedging	2002					2001
Crude oil	$	(4.3	)	$	(0.50)/bbl	$	5.5	$	0.73/bbl
Natural gas	(4.4		)	$	(0.06)/Mcf	44.6		$	0.69/Mcf
Net hedging opportunity gain (cost)	$	(8.7	)	$	(0.38)/BOE	$	50.1	$	2.54/BOE

During the first half of 2001, Enerplus was able to hedge a portion of its production for the remainder of the year at favorable rates. When natural gas prices retreated from their record highs at the end of 2001, Enerplus’ hedging protection resulted in a significant gain. Hedging costs arose in 2002 as oil and natural gas prices strengthened through to the end of the year due to colder winter temperatures, a crude oil production strike in Venezuela, and the threat of hostilities in the Middle East.

Enerplus’ commodity risk management position as at December 31, 2002 is described in Note 7 to the consolidated financial statements. Commodity price risk is managed through fixed price physical delivery contracts and financial instruments such as forward contracts. The net receipts or payments arising from the forward contracts are recognized in income as a component of oil and gas sales during the same period as

the corresponding hedged position. At December 31, 2002, Enerplus had $1.7 million in unamortized premium costs related to forward contracts that will be amortized over the remaining life of those contracts. The mark-to-market value of the financial forward contracts at December 31, 2002 represented an unrealized cost of $34.2 million on natural gas and an unrealized cost of $8.5 million on oil with reference to year-end prices and forward markets.

In the future, Enerplus intends to continue to manage its commodity price exposure in a similar manner as in the past with the objective of establishing downside price protection at a reasonable cost, while maintaining exposure to improving prices. The future gain or cost from such a program depends on forward markets and future prices.

Enerplus has the following physical and financial contracts in place:

Physical & Financial	Contracted natural gas volumes MMcf/day	% of estimated gross natural gas production	Contracted crude oil volumes bbls/day	% of estimated gross crude oil production
First half 2003	104.5	42	11,000	46
Second half 2003	103.4	41	12,000	50
First half 2004	70.3	28	8,500	36
Second half 2004	50.0	20	5,000	21

Even with these positions, the Fund’s cash flow remains sensitive to changes in commodity prices as demonstrated by the following table:

Sensitivity to Changes in Price and Exchange Rate	Estimated effect on 2003 Distributions per trust unit
Change of $0.10 per Mcf in the price of natural gas	$	0.05
Change of US$1.00 per barrel in the price of WTI crude oil	$	0.10
Change of 1,000 BOE/day in production	$	0.08
Change of $0.01 in the US$/CDN$exchange rate	$	0.04
Change of 1% in interest rate	$	0.03

These sensitivities are based on current projections for 2003, which have been adjusted to include all commodity contracts as described in Note 7 to the consolidated financial statements. They apply to commodity prices, production, interest and exchange rates within the context of current market rates and the Fund’s current risk management positions. To the extent the market price of crude oil or natural gas change to levels that are above the ceiling or below the floor price limits set by existing commodity contracts, the above sensitivities will no longer be relevant. As these sensitivity calculations assume a number of factors, actual sensitivities may vary significantly from those presented.

REVENUES

Crude oil and natural gas revenues, inclusive of hedging, were $621.5 million for the year ended December 31, 2002, which was marginally lower than the $639.4 million reported for the year ended December 31, 2001. Revenues in 2002 represent a full year’s production compared to the partial year’s production received in 2001, due to the Merger. The increase in revenues from greater production volumes was more than offset by the combined effects of the variance in hedging results and the overall decrease in natural gas and NGL prices during 2002 compared to 2001. These variances are described in the table below.

Analysis of Sales Revenues ($millions)	Crude Oil			NGL			Natural Gas			Total
2001 Sales Revenues	$	234.5		$	45.2		$	359.7		$	639.4
Price variance	33.1			(8.8		)	(79.9		)	(55.6		)
Volume variance	30.0			4.9			61.6			96.5
Hedging variance	(9.7		)	—			(49.1		)	(58.8		)
2002 Sales Revenues	$	287.9		$	41.3		$	292.3		$	621.5

ROYALTIES

Royalties decreased marginally from $132.7 million or 22.5% of oil and gas sales before hedging for 2001 to $131.8 million or 20.9% for 2002. The decline in royalties as a percentage of oil and gas sales before hedging is attributable to a lower reference natural gas price used by the provincial government to calculate crown royalties during the year, which is consistent with the decrease in realized natural gas prices during the year. In the current commodity price environment, Enerplus expects the royalty percentage to remain at approximately 21%.

OPERATING EXPENSES

Operating expenses for the year ended December 31, 2002 increased to $134.4 million from $120.1 million in 2001 due to higher production volumes associated with acquisitions and the Merger. On a per unit of production basis, operating expenses decreased by 4% from $6.09/BOE in 2001 to $5.86/BOE in 2002. Several cost categories that decreased year over year include water disposal costs, utility costs and the cost of supplies and services. Prior period adjustments to processing income also contributed to the overall reduction in operating expenses. Enerplus expects to maintain a similar level of operating costs in 2003 and average approximately $5.85/BOE.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses were $16.0 million or $0.70 per BOE for the year ended December 31, 2002 compared to $13.0 million or $0.66 per BOE for 2001. General and administrative costs per BOE of production increased due to the relocation of the corporate head office combined with the incremental cost of consulting services retained to optimize cash flows and pursue value creation opportunities within the existing property portfolio. Enerplus expects general and administrative costs to be approximately $0.70 per BOE for 2003. As allowed under the full cost method of accounting, Enerplus capitalized $9.1 million of general and administrative costs in 2002 compared to $7.5 million in 2001. The majority of these capitalized costs represent compensation costs for staff involved in development and acquisition activities.

MANAGEMENT FEES

($millions)	2002		2001
Base management fee	$	9.2	$	9.3
Performance fee	12.4		—
Total management fees	$	21.6	$	9.3

Enerplus Global Energy Management Company (“EGEM”) supplies management services to Enerplus on a fee and cost reimbursement basis. The management fees, which were renegotiated as a result of the Merger, are now comprised of two components, a base management fee of 2.75% of net operating income and an incremental performance fee which can range from 0% to 4% of net operating income.

For the year ended December 31, 2002 total management fees were $21.6 million compared to $9.3 million for 2001. The performance fee, which is based on the Fund’s total return and its relative performance compared to other senior conventional oil and gas trusts, was $12.4 million or 3.5% of the Fund’s net operating income for 2002. This performance fee was based on the Fund earning a total return of approximately 29% for unitholders and placing second out of the eight senior conventional oil and gas trusts for total return in its peer group. This return was calculated using the ten day weighted average trading price of the trust units prior to December 31, 2002 and 2001. There was no performance fee recorded for 2001 pursuant to the terms of the management agreement as the Manager received a minimum fee of 172,500 trust units with an assigned value of $5,000,000 in conjunction with the Merger. This fee was accounted for as a cost of the Merger.

On March 6, 2003, the Fund announced plans to internalize its management structure by acquiring the shares of the management company, EGEM, from an indirect subsidiary of El Paso Corporation (“El Paso”). The proposed internalization transaction will result in the elimination of all management fees effective April

23, 2003. Enerplus’ unitholders will be asked to approve the transaction at the annual general and special meeting to be held on April 23, 2003.

Under the terms of the proposed transaction, Enerplus will purchase EGEM for total cash consideration of approximately $48.9 million. Furthermore, El Paso has agreed to fix the management fees for the period from January 1, 2003 to April 23, 2003 in an amount of $3.2 million.

Retention arrangements, at a maximum cost of $4.7 million to the Fund, have been made for the executive team and staff at Enerplus to ensure continuity.

The expected benefits of the proposed internalization transaction are as follows:

• The transaction cost represents fair value to unitholders relative to the management fees that have been paid in the past, the estimated future management fees, and the costs associated with terminating the existing agreement;

• The transaction is immediately accretive to Enerplus’ net asset value and cash flow per trust unit;

• The transaction compares favorably in relation to other internalization transactions that have occurred in the energy trust sector;

• In conjunction with the transaction, Enerplus has taken steps to affirm the continued commitment of the executive;

• The Fund’s organizational structure will be simplified and its corporate governance will be improved. For example, unitholders will be able to elect all nine members of the board of directors rather than just the six independent directors, as EGEM’s right to nominate three directors will be eliminated;

• The transaction may lower Enerplus’ cost of capital by increasing the attractiveness of Enerplus trust units to a wider range of investors, including institutions that have refrained from purchasing entities with external management contracts;

• Furthermore, by eliminating management fees, Enerplus can be more competitive with respect to future acquisitions and consolidation opportunities within the trust and E&P sectors.

INTEREST EXPENSE

Interest expense increased to $18.3 million in 2002 from $17.6 million in 2001 as a result of higher average debt outstanding throughout 2002.

DEPLETION, DEPRECIATION AND AMORTIZATION

Depletion of property, plant and equipment is provided using the unit-of-production method based on constant price proven reserves. An estimate of the future costs for restoration and abandonment of well sites and facilities is updated annually and this cost estimate is amortized over the life of the properties on a unit-of-production basis as part of depletion, depreciation and amortization expense (“DD&A”).

DD&A increased to $213.9 million or $9.33/BOE in 2002 from $194.1 million or $9.85/BOE in 2001. Higher production volumes during 2002 have increased the total amount of DD&A however, on a BOE basis, DD&A has decreased.

TAXES

Capital taxes, which are based on total debt and equity levels of the Fund’s operating companies at the end of the year, increased to $5.5 million for 2002 from $4.7 million in 2001 primarily due to the increase in the Fund’s capital during 2002. According to the February 2003 Federal Budget, capital taxes are to be gradually eliminated over the next five years.

Future income taxes arise from differences between the accounting and tax bases of the operating companies’ assets and liabilities. In the Fund’s structure, payments are made between the operating companies and the Fund transferring both income and future income tax liability to the unitholders. Therefore, it is the opinion of management that no cash income taxes are expected to be paid by the operating companies in the future, and as such, the future income tax liability recorded on the balance sheet will be recovered through earnings over time. For the year ended December 31, 2002, a future income tax recovery of $35.4 million ($31.5 million on 2001) was recorded in income.

Upon the acquisition of Celsius, a future income tax liability of $42.1 million was recorded. This liability arose as the purchase price of Celsius’ assets exceeded the balance of its tax pools at the date of the acquisition.

NETBACKS

Netbacks per BOE of Production (6:1)	2002			2001
Production per day	62,784			54,015
Weighted average price (net of hedging)	$	27.11		$	32.43
Royalties, net of ARTC	(5.75		)	(6.73		)
Operating costs	(5.86		)	(6.09		)
Operating netback	15.50			19.61
General and administrative	(0.70		)	(0.66		)
Management fees	(0.94		)	(0.47		)
Interest expense, net of interest and other income	(0.78		)	(0.85		)
Capital taxes	(0.23		)	(0.24		)
Restoration and abandonment cash costs	(0.20		)	(0.13		)
Funds flow from operations	12.65			17.26
Depletion and depreciation	(9.07		)	(9.18		)
Amortization of site restoration and hedging, net of cash costs	(0.06		)	(0.54		)
Future income tax recovery	1.54			1.60
Net income per BOE of production	$	5.06		$	9.14

NET INCOME AND FUNDS FLOW FROM OPERATIONS

Net income for the year ended December 31, 2002 was $115.9 million, or $1.61 per trust unit, down 36% (51% per trust unit) from $180.3 million or $3.28 per trust unit for 2001. After adding back non-cash expenses such as depletion, depreciation and amortization and the future income tax recovery, the resultant funds flow from operations was $289.9 million in 2002 or $4.03 per trust unit compared to $340.2 million or $6.20 per trust unit in 2001. This decrease in net income and funds flow from operations is mainly due to the reduction in natural gas prices and the difference between the $50.1 million gain recognized from crude oil and natural gas hedging contracts during 2001 compared to a hedging cost of $8.7 million in 2002.

QUARTERLY FINANCIAL INFORMATION

$millions, except per trust unit amounts	Oil and gas revenue net of royalties		Net income		Net income per trust unit
$millions, except per trust unit amounts	Oil and gas revenue net of royalties		Net income		Basic		Diluted
2002
First quarter	$	97.0	$	9.4	$	0.13	$	0.13
Second quarter	120.6		26.0		0.37		0.37
Third quarter	122.3		29.1		0.41		0.41
Fourth quarter	149.7		51.4		0.66		0.66
Total	$	489.6	$	115.9	$	1.61	$	1.61
2001
First quarter	$	136.7	$	59.7	$	1.42	$	1.41
Second quarter	109.3		58.5		1.30		1.29
Third quarter	130.9		25.1		0.39		0.39
Fourth quarter	129.8		37.0		0.55		0.55
Total	$	506.7	$	180.3	$	3.28	$	3.28

CASH AVAILABLE FOR DISTRIBUTION

Enerplus makes monthly cash distributions to its unitholders based upon the net cash flow from its oil and gas operations. A portion of this cash flow is typically withheld to repay bank debt incurred with respect to acquisitions and capital spending. For the year ended December 31, 2002, Enerplus generated $289.9 million in funds flow from operations. Of this amount (together with certain funds described in the following table), $246.8 million ($3.32 per trust unit) was paid to unitholders and $46.3 million ($0.62 per trust unit) was retained for debt reduction.

Management monitors the Fund’s distribution payout policy with respect to forecasted cash flows, debt levels, and spending plans. The level of cash retained for debt repayment typically varies between 10% and 20% of annual cash flow, although management is prepared to adjust the payout levels in an effort to balance the investor’s desire for distributions with the Fund’s requirement to maintain a prudent capital structure.

The following table reconciles Enerplus’ “Funds Flow from Operations” with the cash available for distribution to unitholders.

Reconciliation of Cash Available for Distribution $millions, except per unit amounts	2002			2001
Funds flow from operations	$	289.9		$	340.2
Cash withheld for debt reduction	(46.3		)	(46.2		)
Enerplus cash flows(Note A)	—			16.9
Accruals(Note B)	3.2			5.6
Cash available for distribution(Note C)	$	246.8		$	316.5
Cash available for distribution per trust unit	$	3.32		$	5.67

Note A: As a result of the Merger, funds flow from operations do not include funds earned by the former Enerplus prior to June 21, 2001. However, cash distributions include the July and August 2001 payments in respect of these funds. As a result, the July and August 2001 payments to unitholders are added to funds flow from operations for purposes of this reconciliation.

Note B: According to the current Royalty Agreement with Enerplus Resources Corporation (“ERC”), the royalty paid to the Fund must be on a cash basis. As a consequence, the change in the accrued net revenues of ERC for the year are added back to funds flow from operations for purposes of this reconciliation. Subsequent to December 31, 2002 the Fund amended the royalty agreement with ERC to allow for the royalty to be paid on an accrued basis.

Note C: The cash available for distribution of $246.8 million in 2002 can be reconciled to the cash paid to unitholders of $233.6 million in the consolidated statement of cash flows by subtracting the January and February 2003 payments to unitholders and adding the January and February 2002 payments to unitholders, as the Consolidated Statement of Cash Flows reflects cash payments to unitholders during the calendar year.

CAPITAL EXPENDITURES

During the year ended December 31, 2002, Enerplus spent $361.7 million compared to $874.4 million in 2001, on capital expenditures and acquisitions net of divestitures. Enerplus finances its capital expenditures through bank borrowing, new equity issues, and by withholding a portion of cash otherwise available for distribution.

Capital Expenditures ($millions)	2002			2001
Development expenditures	$	94.9		$	87.9
Plant and facilities	46.8			53.6
Sub-total	141.7			141.5
Office	4.4			1.8
Sub-total	146.1			143.3
Acquisitions of oil and gas properties	60.6			77.4
Corporate acquisitions	158.1			722.2
Dispositions of oil and gas properties	(3.1		)	(68.5		)
Total Net Capital Expenditures	$	361.7		$	874.4
Established reserves (MBOE):
Net change in established reserves after production	18.1			102.2
Annual production	22.9			19.7
Annual established reserve additions	41.0			121.9
Finding, development and acquisition costs ($/BOE):	$	8.82		$	7.17

Finding, development and acquisition (“FD&A”) costs based on established reserves for the year were $8.82/BOE compared to $7.17/BOE for 2001. The increase in FD&A costs reflect higher prices paid for acquisitions (in an environment of increased oil and gas price expectations); a focus on natural gas acquisitions (which typically trade at a higher FD&A cost due to the attractive economics of natural gas); and the inclusion of Oil Sands Lease #24 (which is a long-term investment with no current production or established reserve value).

Capital Expenditures by Major Property ($millions)	2002		2001
Joarcam	$	22.0	$	5.1
Medicine Hat	13.3		13.1
Hanna/Garden Plains	12.9		26.5
Bantry	6.3		10.6
Verger	6.0		1.3
Mount Benjamin	5.7		6.1
Other	75.5		78.8
Total	$	141.7	$	141.5

Enerplus is forecasting capital expenditures of approximately $155 million in 2003 on existing properties. A total of $95 million or 61% is expected to be invested in development drilling on natural gas projects at Countess, Verger, Bantry, Medicine Hat, Hanna Garden and other areas. In addition to the development drilling on these properties, a number of wells will be restimulated in the Medicine Hat, Bantry and Verger areas to improve natural gas productivity.

A total of $45 million is expected to be invested in further development of the oil properties at Progress, Valhalla, Joarcam, Giltedge, Silver Heights and Cadogan. In addition, Enerplus expects to spend $7 million to develop a steam assisted gravity drainage pilot on the Oil Sands Lease #24 north of Fort McMurray. This 2003 development program includes construction of facilities to steam and produce bitumen from up to three well pairs that are scheduled to come on production in 2004, at a rate of 2000 BOE/day. Enerplus also expects to spend approximately $8 million on land and seismic.

Enerplus routinely evaluates its property portfolio and disposes of properties that are viewed as non-core holdings with limited contribution to cash flow or upside development potential. In 2002, Enerplus sold $3.1 million worth of non-core oil and gas properties. Enerplus expects to continue its process of rationalizing marginal properties and acquiring new properties in 2003.

LIQUIDITY AND CAPITAL RESOURCES

Long-term debt at December 31, 2002 was $361.7 million, which includes $93.4 million of bank indebtedness and $268.3 million of senior unsecured notes. Although the Fund’s investing activities were higher than 2001 primarily due to the acquisition of Celsius Energy Ltd., long-term debt was reduced by the end of the year with net proceeds from the issue of 13.3 million trust units combined with cash from operations that has been withheld for debt repayments.

During 2002, Enerplus diversified its debt portfolio through the issuance of US$175.0 million senior, unsecured notes with a coupon rate of 6.62% priced at par (the “Notes”). The Notes have a final maturity of June 19, 2014, with amortizing payments of 20% per annum on each of the five anniversary dates commencing on June 19, 2010. Concurrent with the issuance of the Notes, Enerplus swapped the US$175.0 million into Canadian dollar denominated floating rate debt at an exchange rate of 1.5333 for gross proceeds of $268.3 million at a floating interest rate, based on Canadian three month banker’s

acceptances, plus 1.18%. This cross currency swap on the senior unsecured notes represented a mark-to-market gain of $37.1 million at December 31, 2002.

On November 7, 2002 the Fund’s $620 million borrowing base with respect to its bank credit facilities and senior unsecured notes increased to $700 million resulting in the bank credit facilities increasing by $80 million from $351.7 million to $431.7 million. The limit is based on the bank’s evaluation of the value of Enerplus’ proven oil and gas reserves and reflected the additional values attributable to acquisitions completed during the year.

Enerplus plans to finance future commitments with a combination of cash flow from operations, debt, and equity raised in the Canadian and US markets.

Key financial ratio’s for the year were as follows:

Financial Leverage and Coverage	2002		2001
Long-term debt to EBITDA(1)	1.1	x	1.2	x
Funds flow from operations to interest expense	15.8		19.3
Debt to debt plus equity	19	%	23	%

(1)EBITDA is provided to assist management and investors in determining the ability of the Fund to generate cash from operations. It is calculated from the consolidated statement of income as revenue less operating expenses, general and administrative expenses, and management fees. This measure does not have any standardized meaning prescribed by GAAP and may not be comparable to similar measures presented by other entities.

TRUST UNIT INFORMATION

Enerplus had 82,898,000 trust units outstanding at December 31, 2002 compared to 69,532,000 trust units at December 31, 2001. The weighted average basic number of trust units outstanding during 2002 was 71,946,000 (2001 – 54,907,000).

FORWARD-LOOKING STATEMENTS

This discussion and analysis contains forward-looking statements relating to future events or future performance. In some cases, forward-looking statements can be identified by terminology such as “may”, “will”, “should”, “expects”, “projects”, “plans”, “anticipates” and similar expressions. These statements represent management’s expectations or beliefs concerning, among other things, future operating results and various components thereof or the economic performance of Enerplus. Undue reliance should not be placed on these forward-looking statements which are based upon management’s assumptions and are subject to known and unknown risks and uncertainties, including the business risks discussed above, which may cause 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. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted. Enerplus undertakes no obligation to update publicly or revise any forward-looking statements contained herein and such statements are expressly qualified by the cautionary statement.

ENERPLUS RESOURCES FUND

CONSOLIDATED BALANCE SHEET

As at December 31 ($thousands)	2002			2001
ASSETS
Current assets
Cash	$	718		$	979
Accounts receivable	92,986			100,089
Other current	1,975			4,869
	95,679			105,937
Property, plant and equipment	3,071,298			2,667,504
Accumulated depletion and depreciation	(697,153		)	(489,188		)
	2,374,145			2,178,316
Deferred charges (Note 2)	1,807			—
	$	2,471,631		$	2,284,253
LIABILITIES
Current liabilities
Accounts payable	$	79,189		$	72,341
Distributions payable to unitholders	24,870			20,860
Payable to related party (Note 5)	19,038			7,915
	123,097			101,116
Long-term debt (Note 2)	361,729			412,589
Future income taxes (Note 4)	340,269			333,560
Accumulated site restoration	59,038			55,403
Deferred credits	4,266			6,591
Payable to related party (Note 5)	1,400			1,909
	766,702			810,052
EQUITY
Unitholders’ capital (Note 3)	2,156,999			1,826,507
Accumulated income	440,446			324,570
Accumulated cash distributions	(1,015,613		)	(777,992		)
	1,581,832			1,373,085
	$	2,471,631		$	2,284,253

ENERPLUS RESOURCES FUND
CONSOLIDATED STATEMENT OF INCOME

For the year ended December 31 ($thousands except per trust unit amounts)	2002			2001

REVENUES
Oil and gas sales	$	621,450		$	639,379
Crown royalties	(99,503		)	(101,114		)
Freehold and other royalties	(32,334		)	(31,546		)
	489,613			506,719
Interest and other income	559			858
	490,172			507,577
EXPENSES
Operating	134,387			120,082
General and administrative	16,039			12,971
Management fees (Note 5)	21,576			9,323
Interest on long-term debt	18,287			17,605
Depletion, depreciation and amortization	213,908			194,080
	404,197			354,061
Income before taxes	85,975			153,516
Capital taxes	5,483			4,722
Future income taxes (Note 4)	(35,384		)	(31,475		)
	(29,901		)	(26,753		)
NET INCOME	$	115,876		$	180,269
Net income per trust unit
Basic	$	1.61		$	3.28
Diluted	$	1.61		$	3.28
Weighted average number of trust units outstanding (thousands)
Basic	71,946			54,907
Diluted	72,084			54,956

CONSOLIDATED STATEMENT OF ACCUMULATED INCOME

For the year ended December 31 ($thousands)	2002		2001

Accumulated income, beginning of year	$	324,570	$	144,301
Net income	115,876		180,269
Accumulated income, end of year	$	440,446	$	324,570

ENERPLUS RESOURCES FUND
CONSOLIDATED STATEMENT OF CASH FLOWS

For the year ended December 31 ($thousands)	2002			2001

OPERATING ACTIVITIES
Net income	$	115,876		$	180,269
Depletion, depreciation and amortization	213,908			194,080
Future income taxes (recovery)	(35,384		)	(31,475		)
Site restoration and abandonment costs incurred	(4,548		)	(2,628		)
Funds flow from operations	289,852			340,246
Decrease (increase) in non-cash working capital	15,162			(52,928		)
	305,014			287,318
FINANCING ACTIVITIES
Issue of trust units, net of issue costs (Note 3)	329,752			151,411
Cash distributions to unitholders	(233,611		)	(328,899		)
Increase (decrease) in bank credit facilities	(319,188		)	58,021
Issuance of senior unsecured notes	268,328			—
Payment to related party	(509		)	(127		)
Deferred charges (Note 2)	(1,892		)	—
	42,880			(119,594		)
INVESTING ACTIVITIES
Capital expenditures	(146,116		)	(143,280		)
Property acquisitions	(60,581		)	(77,432		)
Property dispositions	3,058			68,496
Corporate acquisitions (Note 6)	(161,403		)	(14,522		)
Change in non-cash investing working capital	16,887			(853		)
	(348,155		)	(167,591		)
Change in cash	(261		)	133
Cash, beginning of year	979			846
Cash, end of year	$	718		$	979
SUPPLEMENTARY CASH FLOW INFORMATION
Cash income taxes paid	$	—		$	—
Cash interest paid	$	17,740		$	17,162

CONSOLIDATED STATEMENT OF ACCUMULATED CASH DISTRIBUTIONS

For the year ended December 31 ($thousands)	2002		2001

Accumulated cash distributions, beginning of year	$	777,992	$	447,158
Cash distributions	237,621		330,834
Accumulated cash distributions, end of year	$	1,015,613	$	777,992

ENERPLUS RESOURCES FUND
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Management of Enerplus Resources Fund (“Enerplus” or the “Fund”) prepares the financial statements in accordance with Canadian generally accepted accounting principles (“GAAP”). The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The following significant accounting policies are presented to assist the reader in evaluating these consolidated financial statements and, together with the following notes, should be considered an integral part of the consolidated financial statements.

(a) Organization and Basis of Accounting

The Fund is an open-end investment trust created under the laws of the Province of Alberta operating pursuant to the Amended and Restated Trust Indenture between EnerMark Inc., its wholly-owned subsidiary, Enerplus Resources Corporation (“ERC”) and CIBC Mellon Trust Company as Trustee. The beneficiaries of the Fund (the “unitholders”) are holders of trust units (the “trust units”) issued by the Fund. The Fund is a limited-purpose trust whose purpose is to invest in securities of its wholly-owned subsidiary EnerMark Inc., invest in royalties granted by EnerMark Inc. and ERC, administer the assets and liabilities of the Fund and make distributions to the unitholders.

The Fund’s financial statements include the accounts of the Fund, EnerMark Inc. and its subsidiaries on a consolidated basis. All inter-entity transactions have been eliminated.

(b) Property, Plant and Equipment

The Fund follows the full cost method of accounting. All costs of acquiring oil and natural gas properties and related development costs are capitalized and accumulated in one cost centre. Maintenance and repairs are charged against earnings, and renewals and enhancements which extend the recoverable reserves of the property, plant and equipment are capitalized. Gains and losses are not recognized upon disposition of oil and natural gas properties unless such a disposition would significantly alter the rate of depletion.

The Fund places a limit on the aggregate carrying value of property, plant and equipment which may be amortized against revenues of future periods (the “ceiling test”). The ceiling test is a cost recovery test whereby the capitalized costs less accumulated depletion and depreciation, accumulated site restoration and future income taxes are limited to an amount equal to estimated undiscounted future net revenues from proven reserves, plus the unimpaired costs of non-producing properties, less estimated future general and administrative expenses, site restoration costs, management fees, financing costs and income taxes. Costs and prices at the balance sheet date are used in determining ceiling test amounts. Any costs carried on the balance sheet in excess of the ceiling test limitation are charged to income.

(d) Depletion and Depreciation

The provision for depletion and depreciation of oil and natural gas assets is calculated using the unit-of-production method based on the Fund’s share of estimated proven reserves before royalties. Reserves and production are converted to equivalent units on the basis of 6 Mcf = 1 bbl reflecting the approximate relative energy content.

(e) Site Restoration and Abandonment

The provision for estimated site restoration costs is determined using the unit-of-production method and is included in depletion, depreciation and amortization expense. Actual site restoration costs are charged against the accumulated liability.

(f) Income Taxes

The Fund is a taxable entity under the Income Tax Act (Canada) and is taxable only on income that is not distributed or distributable to the unitholders. As the Fund distributes all of its taxable income to the unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Fund, no provision for income tax has been made in the Fund, except for its subsidiaries as noted below.

The Fund follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements of the Fund’s corporate subsidiaries and their respective tax bases, using enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs.

(g) Financial Instruments

The Fund is exposed to market risks resulting from fluctuations in commodity prices, and interest rates in the normal course of operations. The Fund uses various types of financial instruments to manage these market risks. Proceeds and costs realized from holding the crude oil and natural gas contracts are recognized in oil and gas revenues at the time each transaction under a contract is settled. The costs or proceeds realized from holding the interest rate swaps are recognized in interest expense at the time each transaction is settled.

(h) Foreign Currency Translation

Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at the balance sheet date. Revenues and expenses are translated at the monthly average rates of exchange. Translation gains and losses are included in income in the period in which they arise.

(i) Accounting for Stock Based Compensation

Effective for the fiscal years beginning on or after January 1, 2002, the Fund adopted the recommendations of the CICA on accounting for stock based compensation which apply to new rights granted on or after that date. The Fund has elected to continue to measure compensation cost based on the intrinsic value of the award at the date of the grant and

recognize that cost over the vesting period. The cash received upon exercise of the rights is credited to unitholders’ capital.

2. LONG-TERM DEBT

($ thousands)	2002		2001
Bank credit facilities(a)	$	93,401	$	412,589
Senior unsecured notes(b)	268,328		—
Total long-term debt	$	361,729	$	412,589

(a) Bank Credit Facilities

On March 1, 2002, Enerplus renegotiated its bank facilities into a single unsecured syndicated facility (the “Facility”) in the amount of $620,000,000. The Facility consisted of a $590,000,000 revolving committed line with an incremental two-year term, and a $30,000,000 demand operating line. The Facility amounts were adjusted upon the issuance of the Senior Unsecured Notes on June 19, 2002, as described below, to a $322,000,000 revolving committed line and a $29,672,000 demand operating line. On November 7, 2002, the Fund’s borrowing base was increased by $80,000,000 to $700,000,000 and accordingly the revolving committed line was increased to $402,000,000 along with the total Facility, which at December 31, 2002 was $431,672,000. Various borrowing options are available under the Facility including prime rate based advances and banker’s acceptance loans.

In the event that the revolving bank line is not extended at the end of the 364 day revolving period, no payments are required to be made to non-extending lenders during the first year of the term period. However, Enerplus will be required to maintain certain minimum balances on deposit with the syndicate agent.

Since a demand for payment with respect to the operating facility would be financed by the revolving facility, no portion of the operating facility has been considered as current.

(b) Senior Unsecured Notes

On June 19, 2002 Enerplus replaced a portion of its bank debt with senior unsecured notes (“the Notes”) in the amount of US$175,000,000. They have a final maturity of June 19, 2014 and bear interest at 6.62% per annum, with interest paid semi-annually on June 19 and December 19 of each year. The Notes Purchase Agreement requires the Fund to make five annual amortizing principal repayments of 20% of the initial principal amount, commencing on June 19, 2010.

Concurrent with the issuance of the Notes, the Fund entered into a cross currency swap, with a syndicate of major financial institutions. Under the terms of the swap, the amount of the Notes was fixed for purposes of interest and principal repayments at a notional amount of CDN$268,328,000. Interest payments are made on a floating rate basis, set at the rate for three-month Canadian banker’s acceptances, plus 1.18%. Costs incurred in connection with issuing the Notes, in the amount of $1,892,000 are classified as deferred charges on the balance sheet and are being amortized over the term of the Notes. As at December 31, 2002, the amount remaining to be amortized associated with these costs was $1,807,000.

The Bank Credit Facilities and the Senior Unsecured Notes (the “Combined Facilities”) are the legal obligation of EnerMark Inc. and are guaranteed by ERC. Although payments to unitholders are subordinated to the Combined Facilities, unitholders have no direct liability should cash flow be insufficient to repay the Combined Facilities. However, payments with respect to the Combined Facilities have priority over claims of and future distributions to the unitholders.

3. FUND CAPITAL

(a) Unitholders’ Capital

Trust Units (thousands)

Authorized: Unlimited Number of Trust Units

	2002			2001
Issued:	Units	Amount		Units	Amount
Balance, beginning of year	69,532	$	1,826,507	40,925	$	1,050,986
Issued for cash:
Pursuant to public offerings	12,709	314,624		4,313	101,039
Pursuant to option and rights plans	140	2,844		135	2,530
Pursuant to the exercise of warrants	—	—		1,197	33,319
Expiry of warrants	—	—		—	2,846
Issued pursuant to the deemed acquisition of Enerplus (Note 6)	—	—		20,863	582,364
Issued pursuant to the management agreement	—	—		173	5,000
Distribution Reinvestment and Unit Purchase Plan	486	12,284		659	16,577
Issued for acquisition of corporate and property interests	31	740		1,267	31,846
Balance, end of year	82,898	$	2,156,999	69,532	$	1,826,507

During the fourth quarter 2002, the Fund completed an equity offering of 7,959,300 trust units at a price of $26.00 per trust unit for gross proceeds of $206,942,000 ($193,738,000 net of issuance costs).

On September 12, 2002, Enerplus completed an equity offering of 4,750,000 trust units at a price of $26.85 per trust unit for gross proceeds of $127,538,000 ($120,886,000 net of issuance costs).

On November 15, 2001, the Fund issued 4,312,500 trust units at a price of $24.75 per trust unit, to raise gross proceeds of $106,734,000 ($101,039,000 net of issuance costs).

At January 1, 2001, Enerplus had 3,045,000 warrants outstanding with an additional 390,000 issued during the year. During 2001, 1,197,000 warrants were exercised and the remaining 2,238,000 warrants expired.

In accordance with the merger of EnerMark Income Fund (“EnerMark”) and Enerplus, (the “Merger”), EnerMark was deemed to have acquired the net assets of Enerplus in exchange for the 20,863,000 trust units of the Fund which were outstanding at June 21, 2001, the date of the acquisition. The deemed trust unit gross consideration was recorded in the amount of $582,817,000 ($582,364,000 net of issuance costs).

Under the terms of the agreement for the provision of management, advisory and administrative services with a related party (Note 5), the Fund issued 172,500 trust units at a recorded value of $5,000,000.

The acquisition of the remaining 11.35% non-controlling interest of Cabre Exploration Ltd. (“Cabre”) was completed on January 8, 2001 and resulted in the issuance of 1,267,000 additional trust units, at $25.20 per trust unit for gross consideration of $31,924,000 ($31,846,000 net of issuance costs) and 390,000 additional warrants at $1.27 per warrant for an ascribed value of $496,000. Enerplus has entered into joint venture agreements (the “Arrangements”) with independent corporations (the “Corporations”) whose sole purpose is to hold oil and natural gas interests earned under each Arrangement. The terms of the Arrangements require the Corporations to commit funds to be spent in joint ventures with Enerplus. In addition, each Corporation has been granted the option to put its common shares to Enerplus at their fair value as determined by an independent evaluator on specified dates (the “Specified Dates”). Enerplus may elect to pay for the shares by way of cash or through the issuance of trust units of the Fund. If trust units are issued they are to be valued at 95% of their average closing price, for the 60 day period preceding the specified dates. On May 22, 2002, the Corporations involved in the 1999 Arrangement, exercised the option to put their common shares to Enerplus. Enerplus acquired the shares of the Corporation by issuing 31,000 trust units with a value of $740,000. The 2000 Arrangement has an approximate funding commitment of $5.4 million and a Specified Date of February 1, 2003. The 2001 Arrangement has an approximate funding commitment of $2.7 million and a Specified Date of March 1, 2004.

Pursuant to the monthly Distribution Reinvestment and Unit Purchase Plan (“DRIP”) which applies only to Canadian unitholders, unitholders are entitled to reinvest cash distributions in additional trust units of the Fund. Trust units are issued at a discount of 5% below the weighted average market price on the Toronto Stock Exchange for the twenty trading days preceding a distribution payment date and without service charges or brokerage fees. Unitholders are also entitled to make optional cash payments to acquire additional trust units. Trust units issued pursuant to optional cash payments are issued on the same basis as reinvested cash distributions except no discount applies. During 2002, $12,284,000 was raised pursuant to the DRIP (2001 - $16,577,000).

Trust units are redeemable at any time, on demand by unitholders, at 85% of the market price in effect from time to time. Redemptions cannot exceed $500,000 during any calendar month.

(b) Trust Unit Option Plan

As at December 31, 2002, 123,000 options issued pursuant to the Trust Unit Option Plan were outstanding, representing 0.1% of the total trust units outstanding. Activity for the options issued pursuant to the Trust Unit Option Plan is summarized as follows:

	2002				2001
(thousands)	Number Of Options		Weighted Average Exercise Price		Number Of Options		Weighted Average Exercise Price
Trust Unit Options outstanding
Beginning of year	264		$	20.93	363	(1)	$	21.03
Exercised	(118	)	$	19.53	(55	)	$	21.94
Cancelled	(23	)	$	22.78	(44	)	$	20.47
Outstanding at end of year	123		$	21.93	264		$	20.93
Options exercisable at the end of the year	67		$	21.43	99		$	19.48

(1)Number of options represent the balance at June 21, 2001 after the Merger of EnerMark and Enerplus

The following table summarizes information with respect to outstanding Unit Options as at December 31, 2002:

(thousands)

Options Outstanding at December 31, 2002	Exercise Prices		Expiry Date December 31	Options Exercisable December 31, 2002

17	$	17.10	2003	17
106	$	22.90	2004	50
123	$	21.93		67

No new options have been granted under the Trust Unit Option Plan as this plan has been superseded by the Trust Unit Rights Incentive Plan as discussed below.

As at December 31, 2002, a total of 2,028,000 rights, representing 2.0% of the total trust units were outstanding pursuant to the Trust Unit Rights Incentive Plan (“Rights Plan”) of which 571,000 rights 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 property, plant and equipment of Enerplus at the end of such calendar quarter result in a reduction in the exercise

price of the rights. As at December 31, 2002, the exercise price has been calculated to be reduced by $0.53 per trust unit of which a $0.14 reduction is effective January 2003 and a $0.20 reduction is effective April 2003.

The exercise price of the rights granted under the Fund’s Rights Plan may be reduced in the future. The amount of the reduction cannot be reasonably determined as it is dependent on a number of factors including but not limited to, future prices received on the sale of oil and natural gas, future production of oil and natural gas, determination of the amounts to be withheld from future distributions to fund capital expenditures and the purchase and sale of property, plant and equipment. Therefore, it is not possible to determine a fair value for the rights granted under the plan.

Compensation costs for pro forma disclosure purposes have been determined based on the excess of the trust unit price over the exercise price of the rights at the date of the financial statements. For the year ended December 31, 2002, net income would be reduced by $181,000 for the estimated compensation cost associated with the rights granted under the Rights Plan on or after January 1, 2002 with a negligible impact on net income per trust unit.

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

	2002				2001
(thousands)	Number Of Rights		Weighted Average Exercise Price(1)		Number Of Rights		Weighted Average Exercise Price
Trust Unit Rights outstanding
Beginning of year	1,318		$	24.50	—		—
Granted	873		26.18		1,360		$	24.50
Exercised	(22	)	24.31		—		—
Cancelled	(141	)	24.44		(42	)	24.50
Outstanding at end of year	2,028		25.11		1,318		$	24.50
Rights exercisable at the end of the year	571		$	24.31	—		—

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

The following table summarizes information with respect to outstanding Unit Rights as at December 31, 2002:

(thousands)

Rights Outstanding at December 31, 2002	Exercise Prices		Expiry Date December 31	Rights Exercisable December 31, 2002
1,159	$	24.31	2007	571
24	25.38		2008	—
53	26.33		2008	—
64	27.33		2008	—
728	26.09		2008	—
2,028	$	25.11		571

(d) Calculation of Dilutive Instruments

No dilutive instruments have been excluded from the calculation of dilutive trust units outstanding at December 31, 2002. There have been no adjustments to net income in calculating dilutive per unit amounts.

4. INCOME TAXES

(a) Enerplus Resources Fund

The Fund is an inter vivos trust for income tax purposes. As such, the Fund is taxable on any income which is not allocated to the unitholders. The Fund intends to allocate all income to unitholders. Should the Fund incur any income taxes, the cash flow available for distribution will be reduced accordingly.

For 2002, the Fund had taxable income of $157,100,000 (2001 - $181,300,000) or $2.15 per trust unit (2001 - $4.71 per trust unit) which was allocated to unitholders. Taxable income of the Fund is comprised of income on securities issued by EnerMark and royalty income, less deductions for Canadian oil and gas property expense (“COGPE”), which is claimed at a rate of 10% on a declining balance basis and the allowable portion of the cost of issuing new trust units during the period. Any losses which occur in the Fund must be retained in the Fund and may be carried forward and deducted from taxable income for a period of seven years. As at December 31, 2002, the Fund had no losses available for carry forward.

The amounts of COGPE and issue costs remaining in the Fund at December 31, 2002 are $355,456,000 and $22,608,000 respectively (2001 - $381,563,000 and $10,063,000).

(b) Corporate Subsidiaries

The temporary differences, tax effected at the enacted rate, comprising the future income tax liability are as follows:

($ thousands)	2002			2001
Excess of net book value of property, plant and equipment over the underlying tax bases	$	358,058		$	350,754
Future site restoration deductions	(18,584		)	(17,643		)
Other	795			449
Future income tax liability	$	340,269		$	333,560

The provisions for income taxes vary from the amounts that would be computed by applying the combined Canadian federal and provincial income tax rates for the following reasons:

($ thousands)	2002			2001
Net income before taxes	$	85,975		$	153,516
Computed income tax expense at the enacted rate of 42.12% (42.62% for 2001)	$	36,213		$	65,429
Increase (decrease) resulting from:
Effect of change in tax rate	(1,668		)	(7,062		)
Net income attributed to the Fund	(65,803		)	(95,671		)
Non-deductible crown royalties and other payments	30,962			43,309
Federal resource allowance	(24,135		)	(43,658		)
ARTC	(311		)	(214		)
Adjustments related to prior acquisitions	(10,642		)	6,392
Future income taxes (recovery)	$	(35,384	)	$	(31,475	)

5. RELATED PARTY TRANSACTIONS

Management, advisory and administration services are supplied to the Fund on a fee and cost reimbursement basis, pursuant to an agreement with Enerplus Global Energy Management Company (“EGEM”). As at December 31, 2002, $18,529,000 (2001 - $7,406,000) was payable to EGEM, pursuant to this agreement.

Management fees of $21,576,000 are reported on the Consolidated Statement of Income for the year ended December 31, 2002 (2001 - $9,323,000). This amount is comprised of a base management fee earned equal to $9,208,000 (2001 - $9,323,000) and a performance fee of $12,368,000 (2001 – nil). Performance fees are based on both the total return of the Fund and its relative performance as compared to other senior conventional oil and gas trusts. For the year ended December 31, 2002, performance fees were calculated at 3.5% of net operating income. There was no performance fee recorded for 2001 pursuant to the terms of the management agreement however, in conjunction with the Merger, EGEM received a minimum fee of 172,500 Enerplus trust units with an assigned value of $5,000,000. The fee was accounted for as a cost of the Merger.

Pursuant to a share purchase agreement related to the Merger, the Fund acquired all of the outstanding common shares of ERC from EGEM resulting in ERC becoming a wholly-owned subsidiary of Enerplus. Consideration for the shares was $2,545,000 and is payable over five years in installments of $509,000 through a reduction in management fees. At December 31, 2002, the amount remaining pursuant to this agreement was $1,909,000 ($1,400,000 long term and $509,000 current).

In addition to the transactions described above, Enerplus has entered into financial instrument contracts at prevailing market rates with an indirect subsidiary of El Paso Corporation, the ultimate parent of EGEM, as described in Note 7.

On March 6, 2003 Enerplus announced plans to internalize its management structure by acquiring the shares of the management company, Enerplus Global Energy Management Company (“EGEM”), from an indirect subsidiary of El Paso Corporation (“El Paso”) for consideration of approximately $48.9 million. In addition, El Paso agreed to fix the management fee for the period January 1, 2003 to April 23, 2003 in an amount of $3.2 million. The proposed transaction will eliminate all management fees effective April 23, 2003. The transaction is subject to unitholder approval at the annual general and special meeting to be held on April 23, 2003.

6. CORPORATE ACQUISITIONS

The fair value of the assets acquired and liabilities assumed for the following acquisitions are summarized as follows:

($ thousands)	2002 Celsius			2001 Cabre(1)			2001 Merger
Property, plant and equipment	$	200,156		$	18,803		$	704,838
Working capital	3,340			—			(10,415		)
Long-term debt assumed	—			—			(78,624		)
Site restoration and abandonment	—			—			(14,530		)
Future income taxes	(42,093		)	(11,396		)	(524		)
Non-controlling interest	—			25,013			—
Net assets acquired	$	161,403		$	32,420		$	600,745

(1) Represents the acquisition of the remaining 11.35% non-controlling interest

(a) Celsius Energy Resources Ltd.

On October 21, 2002, the Fund acquired all the outstanding common shares and retired the debt of Celsius Energy Resources Ltd. (“Celsius”), a private Alberta corporation, for consideration of $161,403,000 which comprised of $160,950,000 in cash and related costs of $453,000. Available lines of credit financed the acquisition which is being accounted for using the purchase method of accounting for business combinations. Results from operations

subsequent to October 21, 2002 are included in the Fund’s financial statements.

Celsius was amalgamated with EnerMark Inc. effective October 22, 2002 and the amalgamated entity was continued under the name of EnerMark Inc.

(b) Cabre Exploration Ltd.

On January 8, 2001, pursuant to an offer to purchase, initially expiring December 21, 2000 and subsequently extended to January 8, 2001, Enerplus acquired all of the outstanding common shares of Cabre, a public Alberta corporation, of which Enerplus held an 88.65% controlling interest as at December 31, 2000.

On January 17, 2001, Cabre was formally amalgamated with EnerMark Inc. Total consideration for the remaining 11.35% interest was $32,420,000 which consisted of 1,267,000 trust units with a recorded value of $31,924,000 and 390,000 warrants with a recorded value of $496,000.

The Merger of EnerMark and Enerplus which occurred on June 21, 2001 was accounted for using the reverse take-over form of the purchase method of accounting for business combinations as the unitholders of EnerMark became the controlling unitholders of the Fund after the Merger. EnerMark is deemed to have acquired all of the outstanding trust units of Enerplus on June 21, 2001 for fair market value consideration totaling $600,745,000. The 20,863,000 trust units of Enerplus which were outstanding prior to the Merger were recorded as deemed consideration at a value of $582,817,000 representing an exchange value of $27.94 per trust unit. In addition, costs and other charges of $17,928,000 related to the acquisition were recorded.

All disclosures of trust units, warrants and options and per unit data up to the June 21, 2001 Merger date have been restated using the Merger exchange ratio of 0.173 Enerplus unit for each EnerMark unit.

7. FINANCIAL INSTRUMENTS

The Fund’s financial instruments that are included in the balance sheet are comprised of current assets, current liabilities, bank credit facilities, and the senior unsecured notes.

The fair values of the current assets and liabilities approximate their carrying amounts due to the short-term maturity of these instruments. The carrying value of the bank credit facilities approximate their fair value as the borrowings have been made through short term banker’s acceptances. The fair value of the senior unsecured notes is approximately $305,456,000 which represents the discounted net present value of the future U.S. dollar interest and principal payments based on current interest and foreign exchange rates.

Virtually all of the Fund’s accounts receivables are with customers in the oil and gas industry and are subject to normal industry credit risks. The carrying value of accounts receivable reflects the Fund’s assessment of the credit risk associated with its customers.

The Fund is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. The Fund uses various types of financial instruments to manage these market risks. 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 December 31, 2002 with reference to forward

prices and mark-to-market valuations provided by independent sources. The Fund may be exposed to losses in the event of default by the counterparties to these instruments. This credit risk is controlled by the Fund through the selection of financially sound counterparties.

INTEREST RATE AND CROSS CURRENCY SWAPS

In addition to the cross currency swap described in Note 2, the Fund has entered into interest rate swaps on $75,000,000 of bank debt at an average fixed interest rate of 4.40% before banking fees that are expected to range between 0.85% and 1.05%. These interest rate swaps are outstanding for three year terms and mature between January 18^th and June 4^th 2005.

The mark-to-market value of the $75,000,000 interest rate swaps as at December 31, 2002 represents an unrealized loss of $2,000,000. The mark-to-market value of the cross currency swap related to the Senior Unsecured Notes as at December 31, 2002 represents an unrealized gain of $37,100,000.

CRUDE OIL INSTRUMENTS

Enerplus has entered into the following financial option contracts that are designed to reduce a downward impact of crude oil prices. The mark-to-market value of the financial crude oil contracts outstanding as at December 31, 2002 reflects an unrealized cost of $8,514,000.

The following table summarizes the Fund’s crude oil commodity risk management positions as at December 31, 2002:

		WTI US$/bbl
	Daily Volumes bbls/day	Sold Call		Purchased Put		Sold Put
Term
Jul. 1, 2003 – Sep. 30, 2003
3-Way option(1)	1,000	$	32.00	$	28.00	$	23.75
Oct. 1, 2003 – Dec. 31, 2003
3-Way option(1)	1,000	$	30.00	$	28.00	$	23.95
Jan. 1, 2003 – Sep. 30, 2004
3-Way option	1,500	$	29.00	$	22.00	$	19.25
Jan. 1, 2003 – Sep. 30, 2004
3-Way option	1,500	$	30.00	$	23.00	$	20.00
Jan. 1, 2003 – Dec. 31, 2003
3-Way option	1,500	$	27.00	$	19.50	$	17.00
3-Way option	1,500	$	28.00	$	20.15	$	17.00
3-Way option	1,500	$	28.51	$	22.00	$	19.50
Jan. 1, 2003 – Jun. 30, 2004
3-Way option	1,500	$	28.00	$	22.50	$	19.60
3-Way option	500	$	28.00	$	22.50	$	19.90
Jan. 1, 2003 – Dec. 31, 2004
3-Way option	1,500	$	29.50	$	22.00	$	20.00
Jan. 1, 2004 – Dec. 31, 2004
3-Way option	1,000	$	28.10	$	23.00	$	20.50
3-Way option(1)	1,000	$	28.50	$	25.00	$	22.00

(1)Transactions entered into subsequent to December 31, 2002 that are not included in the mark-to-market values.

NATURAL GAS INSTRUMENTS

Enerplus has the following physical and financial contracts in place on its gross natural gas production as described below. The mark-to-market value of the financial natural gas contracts outstanding as at December 31, 2002 reflects an unrealized cost of $34,190,000.

The following table summarizes the Fund’s natural gas commodity risk management positions as at December 31, 2002:

		AECO$/Mcf CDN$
	Annualized Daily Volumes MMcf/d	Sold Call		Purchased Put		Sold Put		Fixed Price and Swaps		Escalated Price
Term

Jan. 1, 2003 – Mar. 31, 2003
3-way option(3)	4.8	$	7.39	$	5.28	$	4.22	—		—
3-way option(4)	4.8	$	7.39	$	5.28	$	4.22	—		—
Jan. 1, 2003 – Mar. 31, 2003
Call	9.5	$	6.33	—		—		—		—
Jan. 1, 2003 – Oct. 31, 2003
Physical	2.8	—		—		—		$	2.64	—
Collar(1)	7.1	$	5.27	$	3.69	—		—		—
Put(1)	7.1	—		$	3.69	—		—		—
Jan. 1, 2003 – Dec. 31, 2003
Physical	2.0	—		—		—		—		$	2.23
3-way option	9.5	$	7.91	$	4.27	$	3.17	—		—
Swap	5.7	—		—		—		$	5.80	—
Jan. 1, 2003 – Jun. 30, 2004
3-way option	9.5	$	7.39	$	4.75	$	3.17	—		—
Jan. 1, 2003 – Sep. 30, 2004
3-way option	9.5	$	6.67	$	4.75	$	3.17	—		—
3-way option	9.5	$	7.39	$	4.75	$	3.69	—		—
Jan. 1, 2003 – Oct. 31, 2006
Swap	9.5	—		—		—		$	5.47	—
Swap	4.8	—		—		—		$	5.25	—
Swap	4.8	—		—		—		$	5.24	—
Swap	4.8	—		—		—		$	5.28	—
Apr. 1, 2003 – Oct. 31, 2003
Collar	4.8	$	6.33	$	4.75	—		—		—
Collar	4.8	$	6.18	$	4.75	—		—		—
Apr. 1, 2003 – Dec. 31, 2004
3-way option(2)	9.5	$	7.91	$	5.80	$	4.22	—		—
Jan. 1, 2003 – Oct. 31, 2004
Swap	3.8	—		—		—		$	2.90	—
Jan. 1, 2004 – Dec. 31, 2004
Swap	2.8	—		—		—		$	5.51	—
2004-2010
Physical	2.0	—		—		—		—		$	2.52

(1) The counterparty to these natural gas collars and puts, is a subsidiary of El Paso Corporation which is the ultimate parent of EGEM (refer to Note 5). The option premiums for these instruments are $1,694,000 and are being amortized over their remaining terms.

(2) Transactions entered into subsequent to December 31, 2002 that are not included in the mark-to-market values.

(3) Enerplus sells physical gas at the month index less $0.05/Mcf

(4) Enerplus sells physical gas at the Month Index less $0.11/Mcf

8. COMMITMENTS AND CONTINGENCIES

Pipeline Transportation

Enerplus has contracted to transport natural gas with various pipelines totaling 15 MMcf per day until 2008 and a further 5 MMcf per day until 2015. These transportation contracts apply to approximately 10% of the Fund’s natural gas production.

Oil Sands Lease #24

During 2002, the Fund acquired a 16% working interest in the Oil Sands Lease #24 (Josyln Creek Lease). The acquisition included the assumption of approximately $4,179,000 in contingent project debt that was comprised of $3,360,000 of principal and approximately $819,000 in accrued interest at December 31, 2002. Interest is accrued at the Bank of Canada prime business rate and is not compounded. The debt is contingent on both production and pricing hurdles with respect to development on the lease. As it is too early in the development of this project to determine if these hurdles will be satisfied, the contingent debt has not been accrued in the consolidated financial statements.

9. EVENT SUBSEQUENT TO DECEMBER 31, 2002

Subsequent to December 31, 2002, the Fund acquired all of the issued and outstanding shares of PCC Energy Inc. and PCC Energy Corp. (collectively “PCC”) for total cash consideration of $167,600,000. The acquisition will be accounted for using the purchase method of accounting for business combinations with the results of operations included in the consolidated financial statements of the Fund from the closing date of March 5, 2003.

For further information and a complete copy of the Annual Report for 2002, please contact Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com.

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. Many of these risks and uncertainties are described in Enerplus’ 2001 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.

Eric P. Tremblay

Senior Vice-President, Capital Markets

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ENERPLUS RESOURCES FUND


BY: /s/	Christina S. Meeuwsen
	Christina S. Meeuwsen
	Assistant Corporate Secretary


DATE: March 7, 2003