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 MAY, 2003

COMMISSION FILE NUMBER 1-15150

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EXHIBIT INDEX

EXHIBIT 1 ENERPLUS ANNOUNCES FIRST QUARTER RESULTS FOR 2003

EXHIBIT 1

FOR IMMEDIATE RELEASE

May 14, 2003

Enerplus Resources Fund

TSX - ERF.un

NYSE - ERF

ENERPLUS ANNOUNCES FIRST QUARTER RESULTS FOR 2003

Enerplus Resources Fund (“Enerplus”) is pleased to announce the results for the first quarter of 2003.

Highlights:

• The Fund paid $1.07 per trust unit ($89.1 million) in cash distributions to Unitholders with respect to the first quarter and retained $0.70 per trust unit ($58.2 million) to reduce bank debt incurred on acquisition and development spending. This represents a 60% payout ratio.

• The Fund experienced significantly higher prices for its crude oil, natural gas and NGLs during the first quarter of 2003 when compared to the first quarter of 2002. Natural gas prices increased 166%, crude oil prices increased 54% and NGL prices increased 100% during this time period.

• Daily production volumes increased by 8% over the same period in 2002 to average 67,893. With the additional production volumes acquired from the PCC acquisition late in the quarter, Enerplus expects to achieve its annual production outlook of 68,900 BOE/day for 2003.

• Acquisition activities during the quarter added approximately 4,800 BOE of daily production and 23 MMBOE of established reserves to the Fund, replacing over 90% of the Fund’s 2003 expected production.

• Enerplus continued with its active development program, investing $36.7 million in development drilling and facility enhancements for the three months ended March 31, 2003. During the quarter, Enerplus drilled 52 gross wells (19.8 net wells) with a 92% success rate.

• Subsequent to the first quarter, Enerplus internalized its management structure by acquiring the shares of the management company, Enerplus Global Energy Management Company, from an indirect subsidiary of El Paso Corporation, for cash consideration of $48.9 million before costs incurred in connection with the acquisition.

Enerplus Resources Fund achieved strong financial and operational results during the first quarter of 2003. Above-average commodity prices combined with operational results in line with expectations resulted in cash flows increasing 165% over the same period in 2002. Unitholders benefited from this increase through a rise in monthly cash distributions and the retention of cash flow that fully funded the first quarter’s capital development spending and partially funded acquisitions. These activities have maintained the strength of the Fund’s balance sheet and positioned the Fund to take advantage of acquisition opportunities as they arise.

Acquisition activities to date have replaced over 90% of the Fund’s 2003 expected production. As we move into the second quarter, a relatively large number of assets and companies have been placed on the market. As with all opportunities, we remain highly selective and continue to proactively focus on transactions where we can add incremental value through the application of

technical or commercial advantages, leveraging our technical expertise to add new core properties in areas consistent with our historic value creation efforts.

Through the first quarter, Enerplus continued with its operating initiatives to build on our ability to create value for our Unitholders. We have moved to further enhance the skill sets within each of our business units by hiring additional highly skilled personnel, utilizing the services of a consulting group to fast track our operating initiatives and selectively reducing staff where necessary. While these initiatives have resulted in higher general and administrative costs during the quarter compared to the prior year, we believe our Unitholders will benefit over the longer-term through improved optimization of the Fund’s portfolio of assets.

SELECTED FINANCIAL AND OPERATING RESULTS

For the three months ended March 31,	2003			2002

Average Daily Production
Natural gas (Mcf/day)	232,911			211,713
Crude oil (bbls/day)	24,500			22,966
NGLs (bbls/day)	4,574			4,374
Total (BOE/day) (6:1)	67,893			62,626
% Natural gas	57		%	56		%
Reserve life index (years)	13.8			14.0

Average Selling Price Pre-Hedging
Natural gas (per Mcf)	$	8.10		$	3.04
Crude oil (per bbl)	43.64			28.29
NGLs (per bbl)	36.34			18.15

Netback per BOE
Oil & Gas Sales Before Hedging	$	46.01		$	21.90
Proceeds (cost) of Hedging	(3.92		)	0.01
Royalties, net of ARTC	9.45			4.70
Operating Costs	5.86			5.38
Operating Netback	26.78			11.83
General and Administrative	0.99			0.60
Management Fees	0.40			0.30
Interest	0.79			0.56
Taxes	0.25			0.20
Funds Flow from Operations (1)	24.35			10.17

Financial (000’s)
Net Income	$	94,837		$	9,367
Funds Flow from Operations (1)	147,283			56,162
Cash Distributed	89,076			47,376
Cash Withheld for Debt Repayment	58,207			11,590
Debt Outstanding	494,643			443,798
Development Capital Spending	36,705			30,978
Acquisitions	187,441			21,205
Divestments	12,400			218

Financial per Unit
Net Income	$	1.14		$	0.13
Funds Flow from Operations (1)	1.77			0.81
Cash Distributed	1.07			0.68
Cash Withheld for Debt Repayment	0.70			0.17

Debt/Trailing 12 month Funds Flow Ratio	1.5x			1.3x

(1) See discussion in the Management Discussion and Analysis

2003 CASH DISTRIBUTIONS PER TRUST UNIT

Production Month	Payment Month	CDN$		US$

January	March	$	0.35	$	0.24
February	April	0.35		0.24
March	May	0.37		0.27		*
First Quarter total		$	1.07	$	0.75

* Calculated using an exchange rate of 1.3952 as of May 8, 2003

Value Creation on Existing Assets

Enerplus completed the first quarter of 2003 on track with our projections on all substantive operational parameters. First quarter average daily production volumes of 67,893 BOE/day, with an exit rate of approximately 71,000 BOE/day, positions Enerplus to meet its 2003 annual production objective of 68,900 BOE/day excluding any further acquisition or divestment activities. Operating costs during the quarter averaged $5.86 per BOE, in line with our previous estimates, despite increasing power costs. This achievement is primarily the result of a number of in-house operating cost management initiatives. In the quarter, Enerplus spent $36.3 million in development capital pursuing opportunities within our existing property portfolio. We continue to forecast a $155 million capital program for the year.

Drilling Activity

Enerplus participated in 52 gross wells during the first quarter including 18 gross operated and 34 gross non-operated wells resulting in 19.8 net wells with an overall success rate of 92%. The majority of this drilling capital was directed at joint interest gas projects and east central Alberta oil. Enerplus also completed and tied in a number of wells that were drilled late in 2002. The Fund continues to expect to drill approximately 300 net wells throughout 2003.

2003 First Quarter Drilling Activity

Crude Oil
Wells

Natural
Gas Wells

Dry &
Abandoned
Wells

Total
Wells

Drilling Activity

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Alberta

9.0

8.6

32.0

9.1

5.0

1.6

46.0

19.3

British Columbia

—

6.0

0.5

—

6.0

0.5

Total

9.0

8.6

38.0

9.6

5.0

1.6

52.0

19.8

Success Rate: 92%

Acquisitions

On March 5, 2003, Enerplus closed the acquisition of all of the outstanding shares of PCC Energy Inc. and PCC Energy Corp. (collectively, “PCC”) for cash consideration of $165.8 million after adjustments. The PCC transaction demonstrates our focus on asset quality as this acquisition provides high-quality, long-life deep gas reserves in large established pools with drilling potential. Enerplus acquired approximately 4,380 BOE/day of production and 17.2 MMBOE of established reserves. With approximately 79% of the value concentrated in eight properties, the asset base is also highly focused.

During the quarter, Enerplus also purchased an additional 58.5% working interest in the Freda Lake Ratcliffe Voluntary Unit #1 in Saskatchewan for $15.6 million. This acquisition increases our total interest in the unit to 95% and adds 5.8 MMBOE of established medium (31°) crude oil reserves and 300 barrels of daily production. The Freda Lake property exhibits common producing characteristics with other long-life, high quality properties including limited reserve risk (under 2% annual decline), limited capital requirements and reasonable operating costs. Following the acquisition, Enerplus assumed unit operatorship and is in a position to add incremental value through a series of low risk, low cost well re-completions. This transaction is consistent with our strategy of acquiring additional interests in existing properties where we can enhance total return through low risk development opportunities.

Divestments

Enerplus pursues an active portfolio management strategy by monetizing higher risk, non-core assets of the Fund. In the first quarter, we divested of $12.4 million of non-core properties that produced 511 BOE/day of production and contained 2.8 million BOE of established reserves. Enerplus is continuing an active divestment program in the second quarter, marketing 4,300 BOE/day in an auction process. Enerplus has established price retention thresholds on all properties and all sales will be contingent upon exceeding those minimum thresholds.

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

The following discussion and analysis of the financial results of Enerplus Resources Fund (“Enerplus” or the “Fund”) should be read in conjunction with:

• the MD&A and Audited Consolidated Financial Statements as at and for the years ended December 31, 2002 and 2001; and

• the Interim Unaudited Consolidated Financial Statements as at March 31, 2003 and for the three months ended March 31, 2003 and 2002.

All amounts are stated in Canadian dollars unless otherwise specified. Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE. In accordance with Canadian practice, production volumes, reserve volumes and revenues are reported on a gross basis (before crown and freehold royalties) unless otherwise indicated.

Throughout the MD&A, Management uses funds flow from operations (“funds flow”) to analyze operating performance and leverage. Funds flow as presented does not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore it may not be comparable with the calculation of similar measures for other entities. Funds flow as presented is not intended to represent operating cash flows or operating profits for the period nor should it be viewed as an alternative to cash funds flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to funds flow throughout this report are based on cash funds flow before changes in non-cash working capital.

RESULTS OF OPERATIONS

Production

Daily production averaged 67,893 BOE/day during the three months ended March 31, 2003, representing an 8% increase over production volumes of 62,626 BOE/day for the same period in 2002.

This increase can be attributed to the acquisition of Celsius Energy Resources Ltd. which closed on October 21, 2002 and property acquisitions at Medicine Hat Glauc.”C” on March 4, 2002 and in the Shorncliff area on December 19, 2002. The first quarter also includes the results of the PCC Energy acquisition for 26 days from the closing date of March 5, 2003 to the end of the quarter.

Enerplus expects production levels to increase in the second quarter as a result of the PCC Energy acquisition effective for the entire quarter combined with incremental production gains from capital projects completed in the first quarter of 2003. Exit production rates at the end of March were approximately 71,000 BOE/day. The Fund continues to target average annual production of 68,900 BOE/day for 2003.

Enerplus’ average production portfolio for the three months ended March 31, 2003 was weighted 57% natural gas, 36% crude oil, and 7% natural gas liquids on a per BOE basis. Average production volumes are outlined as follows:

	Three months Ended March 31,		%
	2003	2002	Change
Daily Production Volumes
Natural gas (Mcf/day)	232,911	211,713	10
Crude oil (bbls/day)	24,500	22,966	7
Natural gas liquids (bbls/day)	4,574	4,374	5
Total daily sales (BOE/day)	67,893	62,626	8

Pricing and Price Risk Management

The AECO monthly index price for natural gas increased 137% from $3.34/Mcf in 2002 to $7.92/Mcf in 2003, and the NYMEX price increased 177% from US$2.38/Mcf to US$6.60/Mcf. In comparison, the Fund realized a 166% increase in the average price (before hedging) received on natural gas from $3.04/Mcf for the three months ended March 31, 2002 to $8.10/Mcf for the same period in 2003. The Fund was able to capture a premium to AECO because of aggregator and term sales into the US markets and the strategy of selling at higher AECO daily spot prices versus the monthly index.

The average price that Enerplus received for its crude oil (before hedging) increased 54% from CDN$28.29/bbl for the first quarter of 2002 to CDN$43.64/bbl for the same period in 2003, which compares to a 48% increase in the price of benchmark West Texas Intermediate (WTI) crude oil after adjusting for the change in the US$ exchange rate. The Fund realized a higher crude oil price than the exchange-adjusted WTI benchmark because of better price differentials for Edmonton light sweet crude in the first quarter.

The realized prices for natural gas liquids (“NGLs”) increased 100% from the first quarter of 2002 to average $36.34/bbl for the first quarter of 2003. These realized prices for NGLs were influenced by the corresponding prices for natural gas.

	Three Months Ended March 31,				%
	2003		2002		Change
Average Selling Price (before the effects of hedging)
Natural gas (per Mcf)	$	8.10	$	3.04	166
Crude oil (per bbl)	$	43.64	$	28.29	54
Natural gas liquids (per bbl)	$	36.34	$	18.15	100
Per BOE	$	46.01	$	21.90	110

	Three Months Ended March 31,				%
Average Benchmark Pricing	2003		2002		Change

AECO (30 day) natural gas (per Mcf)	$	7.92	$	3.34	137
NYMEX natural gas (US$ per Mcf)	$	6.60	$	2.38	177
WTI crude oil (US$ per bbl)	$	33.86	$	21.64	56
CDN$/US$ exchange rate	$	0.6626	$	0.6272	6

Enerplus has continued to implement hedging transactions in accordance with its commodity price risk management program during the first quarter. 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. Enerplus’ commodity price risk management program is described in detail in Note 5 to the interim unaudited consolidated financial statements. Enerplus has physical and financial contracts in place for the following production volumes:

Physical & Financial	Contracted Gas volumes (MMcf/day)	% of estimated gross gas production	Contracted oil volumes bbls/day	% of estimated gross oil production
Remainder of 2003	103.4	44	12,000	49
First half of 2004	70.3	30	9,900	40
Second half of 2004	50.0	21	6,400	26

For the three months ended March 31, 2003, Enerplus realized a hedging cost of $16.2 million on natural gas and a hedging cost of $7.7 million on crude oil as the market price for crude oil and natural gas exceeded the Fund’s hedged price ceilings during the quarter. For the comparable period in 2002, Enerplus realized a $0.2 million hedging cost on crude oil and a $0.3 million hedging gain on natural gas.

The mark-to-market value of Enerplus’ forward commodity price contracts at March 31, 2003 represented an unrealized cost of $38.6 million for natural gas and an unrealized cost of $8.6 million for crude oil. In other words, if Enerplus were to settle its forward commodity price contracts at March 31, 2003 with reference to the forward market at that time, it would have to make a payment of approximately $47.2 million. The mark-to-market cost has increased from December 31, 2002 because the forward prices for crude oil and natural gas had strengthened by March 31, 2003. Whether or not actual hedging costs or gains are realized will depend on actual reference prices realized during the applicable price contract periods.

OIL AND GAS SALES

Crude oil and natural gas revenues, including $23.9 million of hedging costs, were $257.2 million for the three months ended March 31, 2003, which was 108% higher than the $123.5 million reported for the same period in 2002. The increased revenues were due to the substantial increase in commodity prices along with increased production volumes that were partially offset by hedging costs.

ANALYSIS OF SALES REVENUES ($ millions)

	Crude Oil			NGLs		Natural Gas			Total
2002 – 1^st Quarter Revenues	$	58.3		$	7.1	$	58.1		$	123.5

Price variance	33.8			7.5		106.1			147.4
Volume variance	4.0			0.3		6.0			10.3
Hedging cost variance	(7.5		)	—		(16.5		)	(24.0		)

2003 – 1st Quarter Revenues	$	88.6		$	14.9	$	153.7		$	257.2

Royalties

Royalties increased from $26.5 million (or 21% of oil and gas sales) for the three months ended March 31, 2002 to $57.7 million (or 21% of oil and gas sales) for the three months ended March 31, 2003. The increase in royalties arises from the increase in production volumes and commodity prices.

Operating Expenses

Operating expenses totaled $35.8 million or $5.86/BOE for the three months ended March 31, 2003 compared to $30.3 million or $5.38/BOE for the first quarter of 2002 and $5.86/BOE for the year ended 2002. Enerplus experienced higher electrical costs in the first quarter of 2003, however, it also benefited from a number of initiatives to manage costs more effectively. Enerplus expects operating costs to continue in this range throughout the remainder of the year.

General and Administrative Expenses

General and administrative (“G&A”) expenses were $6.0 million or $0.99/BOE for the three months ended March 31, 2003 compared to $3.4 million or $0.60/BOE for the same period in 2002 and $0.70/BOE for the year ended 2002. The increase in G&A costs for the first quarter of 2003 was due to hiring and severance costs related to organizational restructuring and the incremental cost of consulting services retained to optimize the Fund’s property portfolio. In addition, with the impending internalization of the management contract and changes in the manner that costs are reimbursed by the Fund, Enerplus began to accrue certain annual costs on a quarterly basis throughout the year that had typically been expensed when incurred.

As allowed under the full cost method of accounting, Enerplus capitalized $2.9 million or 25% of gross G&A costs for the three months ended March 31, 2003 compared to $2.0 million or 25% for the same period in 2002. The majority of these capitalized costs represent compensation costs for staff involved in the Fund’s development and acquisition activities.

Enerplus expects G&A costs to average approximately $0.95/BOE for the remainder of the year after the internalization of the management contract, as El Paso Corporation (“El Paso”) will no longer be contributing to a portion of staff compensation, lease costs and other general and administrative costs. This G&A level also reflects the addition of highly skilled staff to enhance the Fund’s optimization initiatives.

Management Fees

On April 23, 2003, following the receipt of unitholder approval, Enerplus completed the purchase of Enerplus Global Energy Management Company (“EGEM”), owner of the Enerplus management contract, from an indirect subsidiary of El Paso, thereby eliminating all external management fees effective April 23, 2003. Under the terms of the transaction, El Paso agreed to fix the management fees for the period January 1, 2003 to April 23, 2003 at an amount of $3.2 million.

For the three months ended March 31, 2003, management fees were $2.4 million or $0.40 /BOE compared to $1.7 million or $0.30 /BOE at March 31, 2002. The management fees in the first quarter of 2002 were uncharacteristically low due to the Fund not accruing a performance fee at that time. As the Fund’s performance improved throughout the remainder of 2002, management fees increased to reflect incremental performance fees earned by the Manager. Had the fixed fee

not been negotiated as part of the internalization transaction, given the performance of the Fund, Enerplus would have accrued a management fee of $6.8 million for the first quarter of 2003.

On a go-forward basis, all management fees are eliminated as of April 23, 2003. Enerplus expects to expense most, if not all, of the internalization costs in the second quarter of 2003 in accordance with the recent draft Emerging Issues Committee abstract issued by the Canadian Institute of Chartered Accountants on accounting for the internalization of the management function in royalty and income trusts.

Interest Expense

Interest expense for the three months ended March 31, 2003 was $4.9 million, an increase from $3.3 million recognized during the comparable period of 2002. The increase is a result of higher average debt outstanding combined with higher average interest rates paid by the Fund during the period. Canadian prime interest rates have increased approximately 20% from the first quarter of 2002 and are expected to increase throughout the remainder of 2003.

As at March 31, 2003, Enerplus paid floating rates with respect to $226.3 million in bank debt and $268.3 million in senior unsecured debentures. However, with respect to this long-term debt, it had interest rate swaps that fixed the rate of interest on $90 million of debt at rates between 3.89% and 5.96% for three-year terms as more fully described in Note 5 to the interim unaudited consolidated financial statements.

Depletion, Depreciation and Amortization

Depletion, depreciation and amortization (“DD&A”) increased to $56.3 million or $9.22/BOE for the three months ended March 31, 2003 from $54.4 million or $9.66/BOE for the same period in 2002. Higher production volumes during the first quarter of 2003 have increased the total amount of DD&A expense, while the increase in the overall depletable proven reserves has decreased the rate of DD&A per BOE. There was a surplus in the Fund’s ceiling test at March 31, 2003.

Taxes

For the three months ended March 31, 2003, a future income tax recovery of $2.3 million was recorded in income as compared to a recovery of $6.5 million for the same period in 2002. The decrease in the tax recovery is a result of higher income before taxes during the first quarter of 2003. 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.

Netbacks

	For the three months ended March 31
Netbacks per BOE of production (6:1)	2003			2002

Production per day	67,893			62,626

Weighted average price (net of hedging)	$	42.09		$	21.91
Royalties, net of ARTC	(9.45		)	(4.70		)
Operating costs	(5.86		)	(5.38		)
Operating netback	$	26.78		$	11.83
General and administrative	(0.99		)	(0.60		)
Management fees	(0.40		)	(0.30		)
Interest expense, net of interest and other income	(0.79		)	(0.56		)
Capital taxes	(0.25		)	(0.20		)
Total cash netback per BOE	$	24.35		$	10.17

Net Income and Funds Flow From Operations

Net income for the three months ended March 31, 2003 was $94.8 million or $1.14 per trust unit compared to $9.4 million or $0.13 per trust unit in 2002. 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 $147.3 million for the three months ended March 31, 2003 or $1.77 per trust unit compared to $56.2 million or $0.81 per trust unit for the same period in 2002. This increase in net income and funds flow from operations is a result of higher production volumes and higher average crude oil and natural gas prices recognized during the first quarter of 2003 compared to the same period in 2002.

Cash Available for Distribution

Enerplus makes monthly cash distributions based upon net cash flow from its crude oil and natural gas operations. A portion of this cash flow is withheld to repay bank debt incurred with respect to acquisitions and capital spending. For the three months ended March 31, 2003, Enerplus generated $147.3 million in funds flow from operations. Of this amount $89.1 million ($1.07 per trust unit) was paid to unitholders and $58.2 million ($0.70 per trust unit) was retained for debt reduction.

Management monitors the Fund’s distribution payout policy with respect to forecast cash flows, debt levels, and spending plans. 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	Three months ended March 31,
Distribution for the Period	2003			2002
($ millions except per trust unit amounts)
Funds flow from operations	$	147.3		$	56.2
Cash withheld for debt reduction	(58.2		)	(11.6		)
Accruals (1)	—			2.8
Cash available for distribution	$	89.1		$	47.4
Cash available for distribution per trust unit	$	1.07		$	0.68

(1) Pursuant to the 2002 Royalty Agreement with Enerplus Resources Corporation, the royalty paid to the Fund was determined on a cash basis. Accordingly, the change in accrued net revenues for the period is added back to funds flow for purposes of this reconciliation. The Royalty Agreement was amended in 2003 to reflect accrual accounting.

Capital Expenditures

During the three months ended March 31, 2003, Enerplus spent $211.7 million (2002 - $52.0 million) on capital expenditures and acquisitions net of divestitures. Enerplus finances its capital expenditures through bank borrowings, new equity issues, and by withholding a portion of cash otherwise available for distribution.

Capital Expenditures	Three months ended March 31,
($ millions)	2003			2002

Development expenditures	$	29.1		$	18.3
Plant and facilities	6.0			10.6
Land and seismic	1.2			1.2
Sub-total	36.3			30.1
Office	0.4			0.9
Sub-total	36.7			31.0
Acquisitions of oil and gas properties	21.6			21.2
Corporate acquisitions	165.8			—
Dispositions of non-core oil and gas properties	(12.4		)	(0.2		)
Total Net Capital Expenditures	$	211.7		$	52.0

Enerplus drilled 19.8 net wells during the quarter and completed and tied in a number of wells spud in 2002. Approximately one third of the $36.3 million in development capital was directed toward non-operated properties and the remaining two thirds was directed toward operated projects. The operated projects included $7.2 million spent on shallow gas projects and $5.6 million spent on waterflood optimization activities.

Acquisition of oil and natural gas properties for the three months ended March 31, 2003 are comprised primarily of a 58.5% working interest at Freda Lake Ratcliffe Voluntary Unit #1 for $15.6 million. Enerplus acquired all of the outstanding shares of PCC Energy Inc. and PCC Energy Corp. (collectively “PCC”) which were wholly-owned Canadian subsidiaries of US-based PetroCorp Incorporated for cash consideration of $165.8 million after adjustments.

During the three months ended March 31, 2003 Enerplus divested $12.4 million of non-core properties comprised primarily of the Jayar property for $10.1 million. Enerplus continually pursues divestment opportunities to upgrade its portfolio of properties by monetizing higher risk non-core assets with limited development potential.

Liquidity and Capital Resources

Long-term debt at March 31, 2003 was $494.6 million, which includes $226.3 million of bank indebtedness and $268.3 million of senior unsecured notes. The $132.9 million increase from December 31, 2002 can be attributed to an increase in investing activities including the acquisition of PCC, offset partially with cash from operations withheld for debt repayments.

Financial Leverage and Coverage Ratios	Three months ended March 31, 2003		Year ended December 31, 2002

Long-term debt to EBITDA(1)	1.2	x	1.1	x
EBITDA to interest expense(2)	19.2	x	15.8	x
Long-term debt to long-term debt plus equity	24	%	19	%

(1) EBITDA may be used 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 as prescribed by GAAP and may not be comparable to similar measures presented by other entities.

(2) EBITDA to interest expense ratio is based on the first three months of 2003 plus the last nine months of 2002.

As at March 31, 2003, Enerplus had a borrowing base of $700 million with respect to its bank credit facilities and senior unsecured debentures. This amount is based on the bank’s evaluation of the value of Enerplus’ proven oil and gas reserves. This borrowing base is currently under

review and is expected to increase to approximately $850 million on May 31, 2003 to reflect the additional value of oil and natural gas reserves.

On April 23, 2003, Enerplus completed the purchase of EGEM, as described in Note 3 to the interim unaudited consolidated financial statements, for consideration of approximately $48.9 million. This acquisition was financed from Enerplus’ revolving credit facility.

Trust Unit Information

Enerplus had 83,219,000 trust units outstanding at March 31, 2003 compared to 69,667,000 trust units at March 31, 2002. The weighted average number of trust units outstanding during the first quarter of 2003 was 83,085,000 (2002 – 69,593,000). During the first quarter 2003, $3.9 million in equity was raised pursuant to the monthly Distribution Reinvestment and Unit Purchase Plan (“DRIP”) and $4.3 million in equity was issued pursuant to trust unit options and rights plans.

Taxability of Distributions

In the current commodity price environment, Enerplus expects that approximately 75% of the distributions paid to Canadian unitholders in 2003 will be taxable and the remaining 25% will be treated as a tax deferred return of capital.

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. The projections, estimates and beliefs contained in such forward-looking statements necessarily involve 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 RESOURCES FUND

CONSOLIDATED BALANCE SHEET

($ thousands) (Unaudited)	March 31, 2003			December 31, 2002

ASSETS
Current assets
Cash and cash equivalents	$	370		$	718
Accounts receivable	107,092			92,986
Other current	2,484			1,975
	109,946			95,679

Property, plant and equipment	3,285,352			3,071,298
Accumulated depletion and depreciation	(752,128		)	(697,153		)
	2,533,224			2,374,145

Deferred charges	1,768			1,807

	$	2,644,938		$	2,471,631

LIABILITIES
Current liabilities
Accounts payable	$	106,906		$	79,189
Distributions payable to unitholders	29,143			24,870
Payable to related party (Note 3)	10,849			19,038
	146,898			123,097

Long-term debt	494,643			361,729
Future income taxes	339,181			340,269
Accumulated site restoration	59,340			59,038
Deferred credits	3,685			4,266
Payable to related party (Note 3)	1,273			1,400
	898,122			766,702

EQUITY
Unitholders’ capital (Note 2)	2,165,088			2,156,999
Accumulated income	535,283			440,446
Accumulated cash distributions	(1,100,453		)	(1,015,613		)
	1,599,918			1,581,832

	$	2,644,938		$	2,471,631

Number of Trust Units outstanding (thousands)	83,219			82,898

ENERPLUS RESOURCES FUND

CONSOLIDATED STATEMENT OF INCOME

($ thousands except per unit amounts) (Unaudited)	Three Months Ended March 31
	2003			2002

REVENUES
Oil and gas sales	$	257,162		$	123,504
Crown royalties	(43,406		)	(20,117		)
Freehold and other royalties	(14,333		)	(6,357		)
	199,423			97,030
Interest and other income	88			99
	199,511			97,129

EXPENSES
Operating	35,779			30,312
General and administrative	6,030			3,365
Management fees (Note 3)	2,422			1,696
Interest	4,858			3,295
Depletion, depreciation and Amortization	56,345			54,444
	105,434			93,112

Income before taxes	94,077			4,017
Capital taxes	1,529			1,178
Future income tax recovery	(2,289		)	(6,528		)
NET INCOME	$	94,837		$	9,367

Net income per trust unit
Basic	$	1.14		$	0.13

Diluted	$	1.14		$	0.13

Weighted average number of Units outstanding (thousands)
Basic	83,085			69,593
Diluted	83,301			69,642

CONSOLIDATED STATEMENT OF ACCUMULATED INCOME

($ thousands) (Unaudited)	Three Months Ended March 31
	2003		2002

Accumulated income, beginning of period	$	440,446	$	324,570
Net income	94,837		9,367

Accumulated income, end of Period	$	535,283	$	333,937

ENERPLUS RESOURCES FUND

CONSOLIDATED STATEMENT OF CASH FLOWS

($ thousands) (Unaudited)	Three Months Ended March 31
	2003			2002
OPERATING ACTIVITIES
Net income	$	94,837		$	9,367
Depletion, depreciation and amortization	56,345			54,444
Future income tax recovery	(2,289		)	(6,528		)
Site restoration and abandonment costs incurred	(1,610		)	(1,121		)
Funds flow from operations	147,283			56,162
Decrease in non-cash operating working capital	2,998			15,104

	150,281			71,266
FINANCING ACTIVITIES
Issue of trust units, net of issue costs (Note 2)	8,089			3,101
Cash distributions to unitholders	(84,840		)	(45,253		)
Increase in bank credit facilities	132,914			31,209
Payment of related party note (Note 3)	(127		)	(128		)
Decrease (increase) in non-cash financing working capital	4,273			(6,926		)
	60,309			(17,997		)
INVESTING ACTIVITIES
Capital expenditures	(36,705		)	(52,183		)
Property acquisitions	(21,626		)	—
Property dispositions	12,400			218
Corporate acquisitions, net of cash received	(165,815		)	—
Decrease (increase) in non-cash investing working capital	808			(764		)
	(210,938		)	(52,729		)

Change in cash	(348		)	540
Cash, beginning of period	718			979
Cash, end of period	$	370		$	1,519

SUPPLEMENTARY CASH FLOW INFORMATION
Cash income taxes paid	$	—		$	—
Cash interest paid	$	1,279		$	3,783

CONSOLIDATED STATEMENT OF ACCUMULATED CASH DISTRIBUTIONS

($ thousands) (Unaudited)	Three Months Ended March 31
	2003		2002

Accumulated cash distributions, Beginning of period	$	1,015,613	$	777,992
Cash distributions to unitholders	84,840		45,253

Accumulated cash distributions, end of period	$	1,100,453	$	823,245

SELECTED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Tabular amounts in thousands of Canadian dollars) (Unaudited)

1. 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, 2002. 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, 2002. The disclosures provided below are incremental to those included in the 2002 annual consolidated financial statements. Prior year amounts have been adjusted to reflect current period presentation.

2. FUND CAPITAL

(a) Unitholders’ Capital

Authorized: Unlimited Number of Trust Units

	Three months ended March 31, 2003					Year Ended December 31, 2002
Issued: (thousands)	Units		Amount			Units	Amount

Balance, beginning of period	82,898		$	2,156,999		69,532	$	1,826,507
Redemption of units	(6	)	(156		)	—	—
Issued for cash:
Pursuant to public offerings	—		—			12,709	314,624
Pursuant to option and rights plans	181		4,318			140	2,844
Distribution Reinvestment & Unit Purchase Plan	146		3,928			486	12,284
Issued for acquisition of Property interests	—		—			31	740
Balance, end of period	83,219		$	2,165,089		82,898	$	2,156,999

(b) Trust Unit Option Plan

As at March 31, 2003, 103,000 options issued pursuant to the Trust Unit Option Plan were outstanding, representing 0.1% of the total units outstanding. Activity for options issued is summarized as follows:

	Three months ended March 31, 2003				Year Ended December 31, 2002
(thousands)	Number of Options		Weighted Average Exercise Price		Number of Options		Weighted Average Exercise Price


Options outstanding, beginning of period	123		$	21.93	264		$	20.93
Exercised	(19	)	$	20.76	(118	)	$	19.53
Cancelled	(1	)	$	22.90	(23	)	$	22.78
Options outstanding, end of period	103		$	22.14	123		$	21.93
Options exercisable, end of period	48		$	21.69	67		$	21.43

The following table summarizes information with respect to the outstanding Trust Unit Options as at March 31, 2003:

(thousands)	Options Outstanding at March 31, 2003	Exercise Prices		Expiry Date December 31,	Options Exercisable March 31, 2003

	10	$	17.10	2003	10
	93	$	22.90	2004	38
	103	$	22.14		48

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

(c) Trust Unit Rights Incentive Plan

As at March 31, 2003, a total of 1,967,000 rights, representing 2.0% of the total trust units were outstanding pursuant to the Trust Unit Rights Incentive Plan (“Rights Plan”) of which 410,000 were exercisable. Under the Rights Plan, distributions per trust unit to 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. Results from the first quarter of 2003 reduce the exercise price by $0.31per trust unit effective June 2003.

The exercise price of the rights granted under the Fund’s Rights Plan may be reduced in the future. The amount of the price reduction of the rights 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. Accordingly, it is not possible to determine a fair value for the rights granted under this 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 period ended March 31, 2003, net income would be reduced by $539,000 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:

	Three months ended March 31, 2003				Year ended December 31, 2002
(thousands except per Unit amounts)	Number of Rights		Weighted Average Exercise Price (1)		Number of Rights		Weighted Average Exercise Price

Rights outstanding at beginning of period	2,028		$	25.11	1,318		$	24.50
Granted	147		27.70		873		26.18
Exercised	(162	)	24.18		(22	)	24.31
Cancelled	(46	)	25.21		(141	)	24.44
Outstanding at end of period	1,967		25.28		2,028		25.11
Rights exercisable at end of period	410		24.17		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 Trust Unit Rights as at March 31, 2003:

(thousands)	Rights Outstanding at March 31, 2003	Adjusted Exercise Prices		Expiry Date December 31,	Rights Exercisable March 31, 2003

	978	$	24.17	2007	410
	22	$	25.24	2008	—
	52	$	26.19	2008	—
	64	$	27.19	2008	—
	704	$	26.09	2008	—
	147	$	27.70	2009	—
	1,967	$	25.28		410

3. RELATED PARTY TRANSACTIONS

Management, advisory and administration services have historically been supplied to the Fund on a fee and cost reimbursement basis, pursuant to an agreement with Enerplus Global Energy Management Company (“EGEM”).

On April 23, 2003, following the receipt of unitholder approval, the Fund internalized its management structure by acquiring the shares of the management company, EGEM, from an indirect subsidiary of El Paso Corporation (“El Paso”) for consideration of $48,900,000 before costs incurred in connection therewith and working capital adjustments. In conjunction with this transaction, El Paso agreed to fix the management fee for the period January 1, 2003 to April 23, 2003 at an amount of $3,200,000 of which $2,422,000 was recognized for the three months ended March 31, 2003.

Pursuant to a share purchase agreement dated June 21, 2001, the Fund acquired all of the outstanding common shares of Enerplus Resources Corporation (“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 of

management fees. At March 31, 2003, the amount remaining pursuant to this agreement was $1,782,000 ($1,273,000 long term and $509,000 current).

In addition to the transactions described above, Enerplus has entered into financial instrument contracts at market rates with an indirect subsidiary of El Paso Corporation, who prior to April 23, 2003, was the ultimate parent of EGEM, as described in Note 5.

4. CORPORATE ACQUISITIONS

PCC Energy Inc. and PCC Energy Corp.

On March 5, 2003, the Fund executed an agreement to purchase all of the outstanding shares of PCC Energy Inc. and PCC Energy Corp. (collectively, “PCC”), which immediately prior to the acquisition were wholly owned Canadian subsidiaries of U.S.-based PetroCorp Incorporated, for cash consideration of $165,815,000. Available lines of credit financed the acquisition that is being accounted for using the purchase method of accounting for business combinations. A portion of the properties acquired through the acquisition of PCC is subject to a royalty arrangement that is structured as a net profits interest with a private U.S. company. Results from the operations of PCC, excluding the net profits interest, have been included in the Fund’s consolidated financial statements subsequent to March 5, 2003.

The allocation to the fair value of the assets acquired and liabilities assumed, plus the future tax cost are summarized as follows:

Property, plant and equipment	$	168,123
Cash	8,846
Working capital deficiency	(9,953		)
Future income taxes	(1,201		)
	$	165,815

5. 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 market values of the current assets and liabilities approximate their carrying amount due to the short-term maturity of these instruments. The carrying value of the bank credit facilities approximate their fair value as the vast majority of borrowings are made through short-term banker’s acceptances. The fair value of the senior unsecured notes is approximately $286,764,000, 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. The Fund is exposed to market risks resulting from fluctuations in commodity price, 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 March 31, 2003 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:

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 were initially entered for three-year terms and mature between January 18^th

and June 4^th 2005. Additionally, as a result of the acquisition of PCC, Enerplus assumed a $15,000,000 interest rate swap at a fixed rate of 5.96%. This swap matures August 29, 2003.

The mark-to-market value of the $90,000,000 interest rate swaps as at March 31, 2003 represents an unrealized cost of $1,224,000. The mark-to-market value of the cross currency swap related to the Senior Unsecured Notes as at March 31, 2002 represents an unrealized gain of $18,436,000.

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 March 31, 2003 reflects an unrealized cost of $8,620,000.

The following table summarizes the Fund’s crude oil risk management positions at March 31, 2003:

		WTI US$/bbl
	Daily Volumes bbls/day	Sold Call		Purchased Put		Sold Put
Term
Jul. 1, 2003 – Sep. 30, 2003
3-Way option	1,000	$	32.00	$	28.00	$	23.75
Oct. 1, 2003 – Dec. 31, 2003
3-Way option	1,000	$	30.00	$	28.00	$	23.95
Apr. 1, 2003 –Sep. 30, 2004
3-Way option	1,500	$	29.00	$	22.00	$	19.25
Apr. 1, 2003 – Sep. 30, 2004
3-Way option	1,500	$	30.00	$	23.00	$	20.00
Apr. 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
Apr. 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
Apr. 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	1,000	$	28.50	$	25.00	$	22.00
3-Way option (1)	1,400	$	28.00	$	23.00	$	19.50

(1) Financial option transactions entered into during the first quarter of 2003.

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 March 31, 2003 reflects an unrealized cost of $38,623,000.

The following table summarizes the Fund’s natural gas risk management positions at March 31, 2003:

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

Apr. 1, 2003 – Oct. 31, 2003
Physical	2.8	—		—		—		$	2.64	—
Collar (1)	7.1	$	5.27	$	3.69	—		—		—
Put (1)	7.1	—		$	3.69	—		—		—
Apr. 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	—
Apr. 1, 2003 – Jun. 30, 2004
3-way option	9.5	$	7.39	$	4.75	$	3.17	—		—
Apr. 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	—		—
Apr. 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	9.5	$	7.91	$	5.80	$	4.22	—		—
Apr. 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 prior to April 23, 2003 was the ultimate parent of EGEM (refer to Note 3). The option premiums for these instruments are $1,186,000 and are being amortized over their remaining terms.

A complete copy of the First Quarter Report for 2003 will be available at www.enerplus.com on Tuesday, May 20, 2003. For further information and a complete copy of the 1^st Quarter Report for 2003, 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’ 2002 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: May 15, 2003