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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


FORM 6-K

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

FOR THE MONTH OF NOVEMBER, 2002


COMMISSION FILE NUMBER 1-15150

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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

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1)

Yes  o        No  ý

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)

Yes  o        No  ý

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.

Yes  o        No  ý

EXHIBIT INDEX

EXHIBIT 1

2


EXHIBIT 1

FOR IMMEDIATE RELEASE

EXHIBIT 1:        3RD QUARTERLY REPORT TO UNITHOLDERS, INCLUDING THE INTERIM MANAGEMENT'S DISCUSSION AND ANALYSIS AND FINANCIAL STATEMENTS FOR THE NINE MONTHS PERIOD ENDED SEPTEMBER 30, 2002.

3


ENERPLUS RESOURCES FUND

THIRD QUARTER REPORT FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002
2002 SELECTED COMBINED FINANCIAL AND OPERATING RESULTS

For the nine months ended September 30,
   2002
   2001(1)
OPERATING        
  Average Daily Volumes:        
    Natural gas (Mcf/day)   204,463   203,478
    Crude oil (bbls/day)   23,117   24,330
    NGLs (bbls/day)   4,299   4,777
   
 
  Total (BOE/day) (6:1)   61,493   63,020
  % Natural gas   55%   54%
  Reserve life index (years)(3)   14.0   13.7
 
   CDN$
   US$(2)
For the nine months ended
September 30,
  2002
   2001(1)
   2002
   2001(1)
Average Selling Price Pre-Hedging                        
  Natural gas (per Mcf)   $ 3.44   $ 5.97   $ 2.19   $ 3.88
  Crude oil (per bbl)     33.69     34.08     21.46     22.16
  NGLs (per bbl)     23.06     35.36     14.69     22.99
  Currency exchange rate (CDN$ to US$)   $ 0.6369   $ 0.6502   $ 0.6369   $ 0.6502
FINANCIAL (combined basis, Unaudited) ($000)                        
  Oil and gas sales before Hedging   $ 431,353   $ 603,976   $ 274,730   $ 392,705
  Proceeds (cost) of hedging     (2,945 )   10,787     (1,876 )   7,014
  Royalties     88,515     141,668     56,376     92,112
  Operating costs     95,853     99,293     61,049     64,560
  Operating netback     244,040     373,802     155,429     243,047
  General and administrative     10,085     8,336     6,422     5,420
  Management fees     13,571     9,700     8,644     6,307
  Interest expense, net     12,367     15,333     7,877     9,970
  Capital taxes     3,950     4,150     2,516     2,698
  Site restoration and Abandonment     3,130     1,976     1,993     1,285
  Funds flow from operations     200,937     334,307     127,977     217,367
  Cash withheld for debt Reduction   $ 33,920   $ 40,424   $ 21,604   $ 26,284
(1)
The 2001 operating and financial information reflects the combined results of Enerplus and EnerMark as if the Merger had been effective January 1, 2001. Combined information provides a historical perspective of the capabilities of the combined entity. This information is also relevant as both Enerplus Resources Fund and EnerMark Income Fund have been managed by the same management group since inception. This information is unaudited and does not conform to Canadian Generally Accepted Accounting Principles.

(2)
All US$ amounts shown in the table above were converted using the Canadian to U.S. dollar exchange rate for the applicable periods as indicated within the table.

(3)
Calculated at December 31 of prior year.

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MESSAGE TO UNITHOLDERS

I am pleased to report that Enerplus continued to deliver results in line with our objectives during the third quarter of 2002. Production volumes for the nine month period of 61,493 BOE/day are on target and general and administrative expenses and operating costs continue to be in line with our expectations for the year. A considerable decrease in natural gas prices during the period compared to the previous quarter was partially offset by strengthening crude oil prices as well as the Fund's physical and financial natural gas contracts. Monthly cash distributions to Unitholders were increased by 7% to $0.30 per unit for the months of October and November resulting in total year-to-date distributions paid of $2.40 per unit. In addition, $0.48 per trust unit has been withheld for debt repayment representing a payout ratio of 83%.

On September 12, 2002, Enerplus successfully closed a Canadian equity offering, raising gross proceeds of $127.5 million. This helped to strengthen our balance sheet and replenish credit facilities that were employed to fund development and acquisition activities. During the quarter, over $44 million was invested in the Fund's existing asset base to increase production levels and improve operating efficiencies. Our low-risk exploitation activities resulted in over 135 gross developmental wells drilled with a 99% success rate. In addition, the Fund acquired a 16% working interest in Athabasca Oil Sands Lease #24. This strategic investment in the Canadian oil sands area of Alberta provides the Fund with an entry into this world-class, long reserve life asset. Over the long-term, this investment is expected to provide Enerplus Unitholders with exposure to significant low-cost reserves and stable production growth. Subsequent to the end of the quarter, Enerplus concluded the acquisition of Celsius Energy Resources Ltd. adding approximately 5,700 BOE/day of daily production and approximately 18 MMBOE of established reserves to the Fund. With this acquisition, Enerplus has invested approximately $215 million year-to-date in acquiring high quality oil and natural gas assets and has effectively replaced the Fund's production for 2002.

At this time, I wish to acknowledge the contribution of Mr. Arne Nielsen who has resigned his position with the Board of Directors. Mr. Nielsen has been a director of Enerplus and its predecessors since May of 1994 and has been a valuable contributor to the growth and success of the Fund over the years. We thank him for his contributions and wise counsel and wish him all the best for the future.

Gordon J. Kerr

President & Chief Executive Officer

5

2002 CASH DISTRIBUTIONS PER TRUST UNIT

Production Month
   Payment Month
   CDN$
   US$
January   March   $ 0.20   $ 0.13
February   April     0.20     0.13
March   May     0.28     0.18
       
 
First Quarter total       $ 0.68   $ 0.44
       
 
April   June     0.28     0.18
May   July     0.28     0.18
June   August     0.28     0.18
       
 
Second Quarter total       $ 0.84   $ 0.54
       
 
July   September     0.28     0.18
August   October     0.30     0.19
September   November     0.30     0.19*
       
 
Third Quarter total       $ 0.88   $ 0.56
       
 
Year-to-Date Total       $ 2.40   $ 1.54
       
 

*  Using an estimated Canadian/US dollar exchange rate of 1.57

6

TRUST UNIT TRADING SUMMARY

Three months ended September 30, 2002
   Toronto Stock Exchange ERF.un — (CDN$)
   New York Stock Exchange ERF — (US$)
High   $29.00   $19.08
Low   $24.26   $14.94
Close   $28.50   $17.87
Volume   9,818,554   9,752,600

DEVELOPMENT ACTIVITIES

During the third quarter, Enerplus continued with its capital development activities focusing primarily on the shallow gas developmental drilling program that was initiated in the second quarter. A total of $44.8 million was invested with 135 gross wells drilled, 124 of which were natural gas wells. Year-to-date, a total of 226 gross wells have been drilled and completed with a 99% success rate. Much of the development capital spent in the third quarter should translate into production gains in the fourth quarter as Enerplus moves quickly to tie-in these new wells.

2002 Third Quarter Drilling Activity

 
    
    
    
    
   Dry & Abandoned Wells
    
    
 
   Crude Oil Wells
   Natural Gas Wells
   Total Wells
Drilling Activity
  Gross
   Net
   Gross
   Net
   Gross
   Net
   Gross
   Net
Alberta   9.0   4.3   99.0   86.6   1.0   1.0   109.0   91.9
Saskatchewan   1.0   1.0   25.0   24.2   —   —   26.0   25.2
   
 
 
 
 
 
 
 
Total   10.0   5.3   124.0   110.8   1.0   1.0   135.0   117.1
   
 
 
 
 
 
 
 
Year-to-Date Total   44.0   20.8   179.0   158.6   3.0   1.6   226.0   181.0
   
 
 
 
 
 
 
 

Success Rate: 99%

Hanna/Garden Plains, Alberta (Operated, W.I. 91%)

At Hanna/Garden Plains, 18 of the 24 natural gas development wells drilled in the second quarter were brought on-stream in July. In order to further optimize the natural gas production, coil tubing strings were inserted into these new wells which produce from the Second White Specks formation. As a result of these activities, incremental production volumes of approximately 900 Mcf/day net to the Fund of sweet natural gas have been added. Late in the third quarter, a second phase of development drilling was initiated, with a total of 31 wells drilled by the end of the quarter. These wells will be tied-in along with the remaining phase one wells in the fourth quarter. In total, Enerplus invested approximately $5.2 million in development capital in the Hanna/Garden Plains areas in the third quarter. The Hanna property produced an average of 12.4 MMcf/day of natural gas net to the Fund during the period.

Medicine Hat North, Alberta (Operated, W.I. 100%)

A 50 well natural gas developmental drilling program that was initiated in the second quarter of 2002 at Medicine Hat North was completed during the third quarter. As a result of this activity, additional compression capacity was installed in August to handle the new natural gas production volumes attributable to this program. At September 30th, a total of 44 wells had been tied-in resulting in incremental production volumes of approximately two million cubic feet of natural gas per day. Coiled tubing strings will be run in the wells in early October to further maximize production. Enerplus

7

invested $6.9 million in developing the Medicine Hat North property in the third quarter. Daily production volumes from the property averaged 2.4 MMcf/day of natural gas during the period.

Medicine Hat Sun Valley, Alberta (Operated, W.I. 100%)

At Medicine Hat Sun Valley, a 30 well developmental drilling program was completed during the third quarter along with the installation of a gathering system. Incremental gas volumes of approximately 1.5 MMcf/day are anticipated to be on stream in the fourth quarter. A total of $2.8 million was invested in this property during the third quarter and it produced an average of 6.9 MMcf/day of natural gas.

Joarcam, Alberta (Operated W.I. 80%)

Three additional Viking oil wells drilled late in the quarter are expected to be on stream during the fourth quarter. Infrastructure upgrades and facility expansions concluded in the second quarter have ensured that incremental production from this drilling activity will be readily handled. Natural gas production from this property was down 43.8% for the third quarter due to reservoir and facility maintenance but has returned to normal levels for the fourth quarter. Enerplus is currently reviewing the results of its capital expenditure activities to date at Joarcam to determine additional recompletion and workover projects. No further drilling activity is planned for the fourth quarter of 2002.

Gleneath Unit, Saskatchewan (Operated, W.I. 81%)

Enerplus continued with its capital expenditures program at Gleneath throughout the third quarter of 2002. The primary focus of this year's program was to improve production levels through low-cost fracture stimulation techniques. The program has been successful with a total of 49 wells completed year to date including 12 re-fracs in the third quarter. Average incremental production volumes from this re-stimulation activity are approximately 340 BOE/day consisting primarily of light sweet crude. Enerplus has scheduled seven additional re-stimulations for the fourth quarter of 2002 to complete this program and is on target to initiate a nine-well infill drilling program during the fourth quarter as well. Production from the Gleneath unit averaged 1,180 BOE/day net to Enerplus during the third quarter.

ACQUISITIONS

Year-to-date, Enerplus has invested approximately $215 million to acquire over 26 MMBOE of established reserves and daily production volumes of approximately 7,100 BOE per day. These transactions more than replace the Fund's anticipated production volumes this year.

During the third quarter of 2002, Enerplus acquired a 16% working interest in Oil Sands Lease #24 (also known as the Joslyn Creek Lease) for $16.4 million. Oil Sands Lease #24 is a 50,000-acre lease situated approximately 40 miles northwest of Fort McMurray strategically situated in the Athabasca Oil Sands fairway of central Alberta, adjacent to the MicMac oil sands mine and the Syncrude mine. Enerplus believes the long-term strategic nature of this investment provides an ideal entry into the development of the Athabasca Oil Sands — a key driver in the future of the Western Canadian Sedimentary Basin. Initial assessment work for a steam assisted gravity drainage ("SAGD") project has been completed on the lease, including the drilling of 230 core hole wells, a third party independent engineering assessment, and the completion of a successful SAGD pilot project. The next phase of the project will consist of a 2,000 barrel of oil per day commercial SAGD development, which is scheduled to begin in early 2003. Oil production from this next phase is expected to commence in 2004. A full-scale commercial 30,000 bbl/day SAGD project is expected to follow, with oil production on stream by 2008. The potential for a second 30,000 bbl/day project also exists on the lease. Enerplus' net capital expenditure commitments for the 2,000 bbl/day project are estimated to be $11.5 million over the next 2 years. Enerplus has the option to participate in further development of the oil sands lease, subject to

8


non-participation provisions, but is under no obligation to do so. Once fully developed, the SAGD projects are expected to have an established Reserve Life Index in excess of 25 years. The recoverable reserves associated with one 30,000 bbl/day SAGD development on the Oil Sands Lease #24 are estimated to be 275 million barrels of oil (44 million barrels net to Enerplus). In keeping with current industry practices, Enerplus expects to record reserves as the Oil Sands Lease #24 is developed over time.

Subsequent to the end of the third quarter, Enerplus purchased Celsius Energy Resources Ltd., a private oil and natural gas producer for $166 million inclusive of working capital adjustments. Celsius' assets are primarily located in Alberta and northeastern British Columbia and provide excellent synergy with Enerplus' existing assets, particularly in the Verger, Countess, Pine Creek and Deep Basin areas. Included in the acquisition are approximately 103,000 net acres of undeveloped land plus seismic data that will provide further development opportunities to the Fund through potential farm-out and swap arrangements. Enerplus has identified over 300 low-risk development drilling locations within the Celsius properties. Capital expenditures for 2003 on the properties are estimated at approximately $17 million. Enerplus acquired daily production volumes of 5,750 BOE/day and 18 MMBOE of established reserves.

MARKETING

NATURAL GAS

After experiencing high prices during the second quarter of 2002, Canadian natural gas prices responded to decreased summer demand and started the third quarter of 2002 at prices as low as CDN$1.60/Mcf. By the end of the third quarter, natural gas prices began to strengthen in response to high crude oil prices. A late summer heat wave, an active storm season in the gulf coast, and questions concerning declining drilling activity and supply, served to push natural gas prices to levels in excess of CDN$5.00/Mcf as the fourth quarter commenced.

Capacity constraints caused by temporary operational maintenance programs on a few of the export pipelines combined with additional US supply created a situation where the difference between the NYMEX Henry Hub ("HH") price and the Canadian AECO price widened considerably to the detriment of Enerplus' Alberta-based natural gas prices. The NYMEX HH price for the third quarter averaged US$3.10/Mcf down only 6% from the previous quarter, while the AECO price averaging CDN$3.25/Mcf, was down 26% from the second quarter.

Near term, future natural gas prices are primarily dependent on winter weather conditions. Over the mid to longer term, supply will be affected by the constraints caused by reduced drilling activity, lower capital investment and a lack of exploration success while the demand for natural gas will be dependent upon the timing of an economic recovery in the U.S.

CRUDE OIL

The price of West Texas Intermediate crude oil ("WTI") continued to climb from the lows experienced at the beginning of 2002 to average US$28.27/bbl during the third quarter. This reflects an 8% increase over the previous quarter and brings the nine month average WTI price to US$25.40/bbl. Despite this increase, the year-to-date average price remains lower than the WTI price of US$27.81/bbl realized for the same period in 2001. Near term prices continue to be supported by the continued political tension in the Middle East, while longer term prices appear be more dependent on the actual balance between supply and demand. The price discounts applied to the Fund's heavier crude oil streams lessened during the summer months due to increased demand for asphalt combined with the increased WTI price. As a result, the Fund's heavy oil netbacks improved during this period. Continued weakness in the Canadian dollar benefited the Fund's crude oil revenues as the majority of Canada's crude oil is exported and referenced to US dollar denominated price benchmarks.

9

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:

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.

Third Quarter 2002 Highlights

Important Information Regarding Comparative Financial Statements

On June 21, 2001, the respective Unitholders of EnerMark Income Fund ("EnerMark") and Enerplus Resources Fund overwhelmingly approved a merger combining the two funds (the "Merger"). As the former Unitholders of EnerMark held approximately 69% of the outstanding trust units of the combined fund at the date of acquisition, the Merger was accounted for using the reverse takeover form of the purchase method of accounting for business combinations. For accounting purposes, EnerMark acquired Enerplus effective June 21, 2001 and continues as Enerplus Resources Fund which has a 16-year history, market recognition and a listing on the New York Stock Exchange.

10

With the reverse takeover form of the purchase method of accounting, the unaudited consolidated financial statements presented herein include the accounts of EnerMark and Enerplus as at and for the three and nine months ended September 30, 2002. The historical comparative financial information for the year 2001 presented in the interim unaudited consolidated financial statements includes the results of EnerMark for the entire period, and only the results of Enerplus for the period from the date of the Merger to September 30, 2001.

RESULTS OF OPERATIONS

Production

Daily production averaged 60,730 BOE/day during the three months ended September 30, 2002, representing a 1% increase over production volumes of 60,331 BOE/day for the same period in 2001. Production remained relatively consistent over the periods as natural reservoir declines were more than offset by production gains from acquisition and development activity. This was particularly evident for crude oil as the volumes increased 5% or 1,092 bbls/day for the three months ended September 30, 2002 compared to 2001. The majority of this increase can be attributed to the property acquisition in the Medicine Hat Glauconite "C" area during the first quarter of 2002. Natural gas production during the third quarter of 2002 was lower compared to the three months ended June 30, 2002 due to plant turnarounds and maintenance.

Production for the nine months ended September 30, 2002 increased 19% to 61,493 BOE/day compared to the corresponding period in 2001. This increase is attributable to the Merger that occurred on June 21, 2001. The nine month comparison of 2001 production reflects the volumes of the predecessor Enerplus Resources Fund only from the date of the Merger.

Enerplus expects production levels to increase in the fourth quarter as a result of the Celsius acquisition combined with incremental production gains as wells drilled in the third quarter are brought on stream. Production from the Celsius acquisition is not recorded in the third quarter as the transaction closed October 21, 2002 and production from the newly acquired Oil Sands Lease #24 is not expected until 2004.

Enerplus' average production portfolio for the three months ended September 30, 2002 was weighted 54% natural gas, 39% crude oil, and 7% natural gas liquids on a per BOE basis. Average production volumes are outlined as follows:

 
   Three Months ended September 30,
    
   Nine Months ended September 30,
    
 
   % Change
   % Change
 
   2002
   2001
   2002
   2001
Daily Sales Volumes                        
  Natural gas (Mcf/day)   198,452   199,823   (1% ) 204,463   167,304   22%
  Crude oil (bbls/day)   23,560   22,468   5%   23,117   19,760   17%
  NGLs (bbls/day)   4,095   4,559   (10% ) 4,299   3,879   11%
   
 
 
 
 
 
  Total daily sales (BOE/day)   60,730   60,331   1%   61,493   51,523   19%
   
 
 
 
 
 

Pricing and Price Risk Management

Although the AECO monthly index price decreased 17% from $3.92/Mcf in 2001 to $3.25/Mcf in 2002, the Fund experienced only a 2% decline in the average price (before hedging) received on natural gas from $3.43/Mcf for the three months ended September 30, 2001 to $3.37/Mcf for the same period in 2002. Enerplus was able to moderate the decline in the AECO index through the benefit of a number of

11

fixed price natural gas delivery contracts. For the nine months ended September 30, 2002, Enerplus' natural gas prices (before hedging) decreased 39% from the comparable period 2001. This decline is consistent with the sharp reduction in the AECO and NYMEX price indices from the peak experienced during the first half of 2001.

The average price that Enerplus received for its crude oil (before hedging) increased 7% from CDN$35.11/bbl for the third quarter of 2001 to CDN$37.41/bbl in the same quarter in 2002, which corresponds with the increase in the price of benchmark West Texas Intermediate (WTI) crude oil after adjusting for the change in the US$ exchange rate. For the nine months ended September 30, 2002 the average price received for crude oil (before hedging) decreased 1% from the comparable period in 2001, lower than the 9% decrease in price of the WTI crude oil. This difference is mainly due to the different product mix recognized in 2002 as a result of the Merger.

The realized prices for natural gas liquids ("NGLs") decreased 2% from the third quarter of 2001 to average $25.81/bbl for the third quarter of 2002. For the nine months ended September 30, 2002, NGL prices decreased 34% from the comparable period in 2001. In both the three and nine month comparisons, the realized prices for NGLs were influenced by the corresponding prices for natural gas.

 
   Three Months ended September 30,
    
   Nine Months ended September 30,
    
  
 
   % Change
   % Change
  
 
   2002
   2001
   2002
   2001
  
Average Selling Price (before hedging)                                  
  Natural gas (per Mcf)   $ 3.37   $ 3.43   (2% ) $ 3.44   $ 5.68   (39% )
  Crude oil (per bbl)   $ 37.41   $ 35.11   7%   $ 33.69   $ 33.93   (1% )
  NGLs (per bbl)   $ 25.81   $ 26.29   (2% ) $ 23.06   $ 34.79   (34% )
  Total daily sales (per BOE)   $ 27.24   $ 26.38   3%   $ 25.69   $ 34.08   (25% )
 
   Three Months ended September 30,
    
   Nine Months ended September 30,
    
  
 
   % Change
   % Change
  
 
   2002
   2001
   2002
   2001
  
Benchmark Pricing                                  
  AECO (30 day) natural gas (per Mcf)   $ 3.25   $ 3.92   (17% ) $ 3.67   $ 7.30   (50% )
  NYMEX natural gas (US$ per Mcf)   $ 3.26   $ 2.98   9%   $ 3.01   $ 5.01   (40% )
  WTI crude oil (US$ per bbl)   $ 28.27   $ 26.76   6%   $ 25.39   $ 27.82   (9% )
  Currency $1 CDN in US $   $ 0.6398   $ 0.6472   (1% ) $ 0.6369   $ 0.6502   (2% )

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

Physical & Financial
   Contracted Gas volumes (MMcf/day)
   % of estimated gross gas production*
   Contracted Oil volumes bbls/day
   % of estimated gross oil production*
Remainder 2002   66.0   29%   11,175   45%
2003   75.0   33%   11,000   44%
2004   44.0   19%   6,500   26%

*  Production volumes measured with reference to year-to-date production adjusted for the Celsius acquisition.

12

For the three months ended September 30, 2002, Enerplus realized a hedging gain of $0.8 million on natural gas and a hedging loss of $1.7 million on crude oil as a result of its price risk management program. This realized loss is mainly due to an improvement in the markets for crude oil while the realized gain was due to a decrease in natural gas prices during the quarter. For the nine months ended September 30, 2002, Enerplus has realized a hedging loss on both natural gas and crude oil of $0.5 million and $2.4 million respectively. For the comparable period in 2001, Enerplus realized a $3.1 million hedging loss on crude oil and a $16.2 million hedging gain on natural gas. The mark-to-market value of Enerplus' forward commodity price contracts at September 30, 2002 represented an unrealized loss of $18.0 million for natural gas and an unrealized loss of $9.0 million for crude oil. In other words, if Enerplus was to settle its forward commodity price contracts at September 30, 2002 with reference to the forward market at that time, it would have to make a payment of approximately $27.0 million. The mark-to-market loss has widened from the second quarter because the forward prices for crude oil and natural gas had strengthened by September 30, 2002.

13


OIL AND GAS SALES

Crude oil and natural gas revenues, including net hedging costs, were $151.3 million for the three months ended September 30, 2002, which was 8% lower than the $163.8 million reported for the same period in 2001. The decreased revenue was primarily due to a gain of $18.9 million realized in 2001 on natural gas hedging contracts. For the nine months ended September 30, 2002, crude oil and natural gas revenues, including net hedging costs, were $428.4 million compared to $492.4 million for the comparable period in 2001.

ANALYSIS OF SALES REVENUES ($ millions)

 
   Crude Oil
   NGLs
   Natural Gas
   Total
  
2001 — 3rd Quarter Revenues   $ 71.0   $ 11.0   $ 81.8   $ 163.8  
Price variance     5.0     (0.2 )   (1.1 )   3.7  
Volume variance     3.6     (1.1 )   (0.4 )   2.1  
Hedging cost variance     (0.2 )   —     (18.1 )   (18.3 )
   
 
 
 
 
2002 — 3rd Quarter Revenues   $ 79.4   $ 9.7   $ 62.2   $ 151.3  
   
 
 
 
 

Royalties

Royalties decreased from $32.9 million or 20% of oil and gas sales for the three months ended September 30, 2001 to $29.0 million or 19% for the three months ended September 30, 2002. For the nine months ended September 30, 2002 royalties decreased from $115.6 million or 23% of oil and gas sales in 2001 to $88.5 million or 21% of oil and gas sales. In the three and nine month comparisons, the decline in royalties as a percentage of oil and gas sales is attributable to a lower reference natural gas price used to calculate crown royalties during 2002.

Operating Expenses

Operating expenses totaled $34.7 million or $6.21/BOE for the three months ended September 30, 2002 compared to $34.7 million or $6.25/BOE for the third quarter of 2001. Third quarter operating expenses tend to be higher as a result of increased maintenance costs, plant turnarounds and property tax charges which are incurred during this period. Operating expenses for the nine months ended September 30, 2002 increased 18% to $95.9 million from the comparable period in 2001 due to the Merger, however, after reflecting the higher production levels, operating expenses per BOE have been reduced to $5.71/BOE from $5.77/BOE during this time period. Enerplus expects operating costs to continue in this range to the end of 2002.

General and Administrative Expenses

General and administrative ("G&A") expenses were $3.4 million or $0.60/BOE for the three months ended September 30, 2002 compared to $1.6 million or $0.29/BOE for the same period in 2001. Net G&A costs for the third quarter of 2001 were lower than expected due to one-time adjustments for cost recoveries. G&A expenses for the nine months ended September 30, 2002 of $10.1 million are in line with annual expectations of $0.60/BOE.

In accordance with the full cost method of accounting, Enerplus capitalized $2.0 million or 25% of gross G&A costs for the three months ended September 30, 2002 compared to $1.8 million or 28% for the same period in 2001. For the nine month period ended September 30, 2002, Enerplus capitalized $6.1 million of gross G&A costs compared to $4.6 million for the comparable period in 2001. The majority of these capitalized costs represent compensation costs for staff involved in development and acquisition activities.

14


Management Fees

 
   Three Months
ended September 30,
   Nine Months
ended September 30,
($ millions)
  2002
   2001
   2002
   2001
Base management fees   $ 2.3   $ 2.5   $ 6.3   $ 7.0
Performance fees     4.9     —     7.3     —
   
 
 
 
Total management fees   $ 7.2   $ 2.5   $ 13.6   $ 7.0
   
 
 
 

Base management fees, which are calculated based on 2.75% of net operating income, decreased to $2.3 million during the three months ended September 30, 2002 from $2.5 million for the same period in 2001. The decrease is a result of lower net operating income experienced during the period. For the nine months ended September 30, 2002, base management fees decreased to $6.3 million from $7.0 million for the same period in 2001. The decrease in the nine month comparison is a result of lower net operating income experienced during the period, offset slightly by the increase in the rate used to calculate the base management fees from 2.20% to 2.75%, as a result of the restructured management fee associated with the Merger.

The performance fee can range between 0% and 4% of the Fund's annual operating income based on the total return of the Fund and the relative performance compared to other senior oil and gas trusts. Although the performance fee is determined on December 31, 2002, management has accrued a performance fee based on the fact that, had the calculation been performed at September 30, 2002, the performance fee for 2002 would be 3.0% of net operating income. The $7.3 million is an estimate that may increase or decrease throughout the remainder of the year until the performance fee is calculated and finalized at December 31.

Interest Expense

Interest expense for the three months ended September 30, 2002 was $5.2 million, an increase from $5.1 million recognized during the comparable period of 2001. Although the Fund's average long-term debt has decreased compared to the same period in 2001, the average floating interest rate paid by the Fund has increased.

For the nine months ended September 30, 2002, interest expense was $12.7 million, a decrease from $13.5 million recognized during the comparable period of 2001. The decrease is attributable to lower outstanding average long-term debt along with a reduction in interest rates over the period.

As at September 30, 2002, Enerplus had floating interest rates with respect to $94.2 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 on $75.0 million that fixed the rate of interest before stamping fees between 3.89% and 4.70% for three-year terms.

Depletion, Depreciation and Amortization

Depletion, depreciation and amortization decreased to $52.7 million or $9.42/BOE for the three months ended September 30, 2002 from $55.4 million or $9.98/BOE for the same period in 2001. Included in the 2001 balance are amortization costs related to deferred hedging assets amounting to $3.9 million that were fully amortized by the end of 2001. For the nine months ended September 30, 2002, depletion, depreciation and amortization was $158.9 million or $9.47/BOE compared to $135.9 million or $9.66/BOE for the same period in 2001. These differences are a result of the Merger. Higher production volumes during 2002 have increased the amount of depletion, depreciation and amortization expense, while the change in the overall depletable reserves has decreased the rate of

15

depletion, depreciation and amortization per BOE. When applying a ceiling test to our capital assets as at September 30, 2002, no write down was required.

Taxes

For the three months ended September 30, 2002, a future income tax recovery of $11.1 million was recorded in income. Under Canadian generally accepted accounting principles, the Fund does not recognize any future income taxes as taxable income is distributed to Unitholders in the form of taxable distributions. However, the Fund's operating companies are required to account for future income taxes. Future income taxes for the operating companies are dependent upon the method by which funds are transferred to the Fund from the operating companies. The future income tax recovery occurs when tax deductible distributions, which can take the form of interest or royalties, are transferred from the operating companies to the Fund's Unitholders. During the quarter, increased tax deductible distributions were made from the operating companies to the Fund.

Netbacks

 
   Three Months
ended September 30,
   Nine Months
ended September 30,
  
Netbacks per BOE of production (6:1)

  
For the period ended September 30,
  
  2002
   2001
   2002
   2001
  
Oil and gas sales   $ 27.08   $ 29.51   $ 25.52   $ 35.01  
Royalties     (5.19 )   (5.94 )   (5.27 )   (8.22 )
Operating costs     (6.21 )   (6.25 )   (5.71 )   (5.77 )
   
 
 
 
 
Operating netback per BOE   $ 15.68   $ 17.32   $ 14.54   $ 21.02  
General and administrative costs     (0.60 )   (0.29 )   (0.60 )   (0.45 )
Management fees     (1.30 )   (0.45 )   (0.80 )   (0.49 )
Net interest     (0.92 )   (0.90 )   (0.74 )   (0.91 )
Capital taxes     (0.22 )   (0.25 )   (0.24 )   (0.26 )
   
 
 
 
 
Total cash netback per BOE   $ 12.64   $ 15.43   $ 12.16   $ 18.91  
   
 
 
 
 

Net Income and Funds Flow From Operations

 
   Three Months
ended September 30,
   Nine Months
ended September 30,
($ millions) except per trust unit amounts
  2002
   2001
   2002
   2001
Net income   $ 29.1   $ 25.1   $ 64.5   $ 143.3
Net income per trust unit   $ 0.41   $ 0.39   $ 0.92   $ 2.82
Funds flow from operations   $ 69.6   $ 85.0   $ 200.9   $ 264.6
Funds flow from operations per trust unit   $ 0.98   $ 1.31   $ 2.87   $ 5.22

The increase in net income for the three months ended September 30, 2002, is a result of higher average crude oil prices recognized during the third quarter of 2002 compared to the same period in 2001, offset slightly by the additional performance fee that has been accrued during the period. The decrease in funds flow from operations for the three months ended September 30, 2002 is due to an $18.9 million gain recognized from natural gas hedging contracts during the same period in 2001.

The change in net income and funds flow from operations for the nine months ended September 30, 2002, is due to a combination of a $16.2 million gain recognized from natural gas hedging contracts during 2001, a sharp decline in natural gas prices realized during 2002 from those experienced during

16


the first and second quarters of 2001 and the fact that the 2001 year-to-date results are those strictly of EnerMark to the date of the Merger.

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" as per the Statement of Cash Flows with the cash available for distribution to Unitholders.

 
   Three Months
ended September 30,
   Nine Months
ended September 30,
  
Reconciliation of Cash Available for Distribution for the Period
($ millions except per unit amounts)
  
  2002
   2001
   2002
   2001
  
Funds flow from operations   $ 69.6   $ 84.9   $ 200.9   $ 264.6  
Cash withheld for debt reduction     (3.9 )   (5.6 )   (33.9 )   (32.2 )
Enerplus cash flows     —     —     —     16.9  
Accruals *     (1.2 )   2.3     3.5     4.6  
   
 
 
 
 
Cash available for distribution   $ 64.5   $ 81.6   $ 170.5   $ 253.9  
   
 
 
 
 
Cash available for distribution per trust unit   $ 0.88   $ 1.25   $ 2.40   $ 4.77  
*
According to the Royalty Agreement with Enerplus Resources Corporation, the royalty paid to the Fund must be on a cash basis. As a consequence, the change in accrued net revenues for the period is added back to (deducted from) funds flow from operations for purposes of this reconciliation.

With respect to the third quarter of 2002, Enerplus distributed $64.5 million, or $0.88 per trust unit in cash distributions to Unitholders (94% of funds flow from operations) and withheld $3.9 million or $0.05 per trust unit for debt reduction (6% of funds flow from operations). For the nine month period, Enerplus has distributed $170.5 million, or $2.40 per trust unit (83% of funds flow from operations) and withheld $33.9 million or $0.48 per trust unit for debt reduction (17% of funds flow from operations).

Cash available for distribution per trust unit of $0.88 for the three months ended September 30, 2002 represents what an Enerplus Unitholder will have received from the production relating to the third quarter of 2002 (paid to Unitholders on September 20, October 20, and November 20, 2002). Cash available for distribution was $1.25 per trust unit for the same period in 2001.

Capital Expenditures

During the three months ended September 30, 2002, Enerplus spent $46.1 million (2001 — $41.9 million) on capital expenditures prior to acquisitions and divestitures with a focus on development drilling in the Joarcam area. During the nine months ended September 30, 2002, Enerplus spent $101.0 million (2001 — $95.0 million) on capital expenditures prior to acquisitions and divestitures. The capital program to enhance light oil production at Joarcam invested $19.5 million to drill, complete and tie-in 11 Viking Oil wells and construct the associated production facilities. The Medicine Hat North 50 well shallow natural gas development program is near completion and additional compression capacity has been completed at a cost of $8.6 million. Enerplus participated in the drilling of three natural gas wells at Mount Benjamin, a non-operated property, at a cost of $4.7 million. Two of the wells were successfully completed with the third near completion at the end of the quarter.

17

Capital expenditures are in line with those anticipated for the three and nine months ended September 30, 2002. The Fund expects annual capital expenditures of approximately $145.0 million in 2002 which has increased from the original estimate of $130.0 million as a result of opportunities identified in acquired and existing properties.

 
   Three Months
ended September 30,
   Nine Months
ended September 30,
  
Capital Expenditures
($ millions)
  
  2002
   2001
   2002
   2001
  
Development drilling and recompletions   $ 32.0   $ 25.9   $ 60.4   $ 53.7  
Plant and facilities     12.8     15.2     34.7     36.2  
Land and seismic     0.3     0.3     2.0     4.0  
Office     1.0     0.5     3.9     1.1  
   
 
 
 
 
Total capital spending     46.1     41.9     101.0     95.0  
Acquisitions of oil and gas properties     25.4     57.2     48.3     60.0  
Dispositions of non-core oil and gas properties     (0.3 )   (34.8 )   (2.4 )   (54.8 )
   
 
 
 
 
Net capital expenditures   $ 71.2   $ 64.3   $ 146.9   $ 100.2  
   
 
 
 
 

Acquisitions of oil and natural gas properties for the nine months ended September 30, 2002 are comprised primarily of the acquisition of a 16% working interest in Oil Sands Lease #24 for $16.4 million, along with the acquisition of an additional interest in the Medicine Hat Glauconite C property during the first quarter 2002 for $20.5 million.

Through the remainder of the year, Enerplus will continue to pursue acquisition opportunities while maintaining a focused effort on the development of existing reserves that provide attractive potential economic returns to Unitholders.

Liquidity and Capital Resources

Enerplus' long-term debt as at September 30, 2002 of $362.5 million, which was comprised of bank credit facilities of $94.2 million and senior unsecured notes of $268.3 million was lower than long-term debt of $412.6 million as at December 31, 2001. The decrease in debt can be attributed to the equity issue on September 12, 2002 combined with cash from operations that has been withheld for debt repayments.

Financial Leverage and Coverage Ratios
   Nine Months ended
September 30, 2002
   Year ended
December 31, 2001
Long-term debt to funds flow from operations   1.3 x   1.2 x
Funds flow from operations to interest expense*   16.4 x   19.3 x
Long-term debt to long-term debt plus equity   21%   23%
*
Funds flow from operations to interest expense ratio is based on the first nine months of 2002 plus the last three months of 2001.

During the second quarter of 2002, Enerplus diversified its debt portfolio through the issuance of US$175 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 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

18


unsecured notes represented a mark-to-market gain of $40.0 million as at September 30, 2002. The Notes provide the Fund with a new source of financing and the assurance of long-term credit commitments at attractive rates.

On September 12, 2002, Enerplus closed 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 (net $120,886,000). These proceeds were used to reduce the amounts outstanding on the bank credit facilities.

As at September 30, 2002, Enerplus had a borrowing base limit of $620 million with respect to its bank credit facilities and senior unsecured debentures. This limit is based on the bank's evaluation of the value of Enerplus' proven oil and gas reserves. As of November 7, 2002, this limit was increased to $700 million. As a result, Enerplus' bank credit facilities were increased by $80 million from $351.7 million to $431.7 million.

On October 21, 2002, Enerplus closed the acquisition of Celsius Energy Resources Ltd. for total consideration of $165.9 million. This acquisition was financed from Enerplus' revolving credit facility.

Trust Unit Information

Enerplus had 74,751,000 trust units and no warrants outstanding at September 30, 2002 compared to 65,044,000 trust units and 2,238,000 warrants at September 30, 2001. The weighted average number of trust units outstanding during the third quarter of 2002 was 70,850,000 (2001 — 64,776,000). The weighted average number of trust units outstanding for the nine months ended September 30, 2002 was 70,066,000 (2001 — 50,738,000).

Taxability of Distributions

In the current commodity price environment, Enerplus expects that approximately 65% of the distributions paid to Canadian Unitholders in 2002 will be taxable and the remaining 35% 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.

19

ENERPLUS RESOURCES FUND
CONSOLIDATED BALANCE SHEET

($ thousands)
(Unaudited)
   September 30, 2002
   December 31, 2001
  
ASSETS              
Current assets              
  Cash and cash equivalents   $ 3,471   $ 979  
  Accounts receivable     75,638     100,089  
  Other current     3,377     4,869  
   
 
 
      82,486     105,937  
   
 
 
Property, plant and equipment     2,814,368     2,667,504  
Accumulated depletion and depreciation     (643,572 )   (489,188 )
   
 
 
      2,170,796     2,178,316  
   
 
 
Deferred charges (Note 4)     1,847     —  
   
 
 
    $ 2,255,129   $ 2,284,253  
   
 
 
LIABILITIES              
Current liabilities              
  Accounts payable   $ 76,582   $ 72,341  
  Distributions payable to unitholders     22,426     20,860  
  Payable to related party (Note 3)     10,392     7,915  
   
 
 
      109,400     101,116  
   
 
 
Long-term debt (Note 4)     362,458     412,589  
Future income taxes     314,222     333,560  
Accumulated site restoration     58,538     55,403  
Deferred credits     4,848     6,591  
Payable to related party (Note 3)     1,525     1,909  
   
 
 
      741,591     810,052  
   
 
 
EQUITY              
  Unitholders' capital (Note 2)     1,958,521     1,826,507  
  Accumulated income     389,069     324,570  
  Accumulated cash distributions     (943,452 )   (777,992 )
   
 
 
      1,404,138     1,373,085  
   
 
 
    $ 2,255,129   $ 2,284,253  
   
 
 
Number of Trust Units outstanding (thousands)     74,751     69,532  
   
 
 

20

ENERPLUS RESOURCES FUND
CONSOLIDATED STATEMENT OF INCOME

 
   Three Months Ended September 30
   Nine Months Ended September 30
  
($ thousands except per unit amounts)
(Unaudited)
  
  2002
   2001
   2002
   2001
  
REVENUES                          
  Oil and gas sales   $ 151,286   $ 163,824   $ 428,408   $ 492,420  
  Crown royalties     (21,161 )   (24,231 )   (66,013 )   (89,536 )
  Freehold and other royalties     (7,823 )   (8,713 )   (22,502 )   (26,032 )
   
 
 
 
 
      122,302     130,880     339,893     376,852  
  Interest and other income     31     110     338     680  
   
 
 
 
 
      122,333     130,990     340,231     377,532  
   
 
 
 
 
EXPENSES                          
  Operating     34,689     34,717     95,853     81,157  
  General and administrative     3,352     1,633     10,085     6,367  
  Management fees (Note 3)     7,216     2,497     13,571     6,957  
  Interest (Note 5)     5,169     5,121     12,705     13,473  
  Depletion, depreciation and Amortization     52,656     55,423     158,906     135,885  
   
 
 
 
 
      103,082     99,391     291,120     243,839  
   
 
 
 
 
Income before taxes     19,251     31,599     49,111     133,693  
Capital taxes     1,294     1,352     3,950     3,624  
Future income tax     (11,124 )   5,106     (19,338 )   (13,260 )
   
 
 
 
 
NET INCOME   $ 29,081   $ 25,141   $ 64,499   $ 143,329  
   
 
 
 
 
Net income per trust unit                          
  Basic   $ 0.41   $ 0.39   $ 0.92   $ 2.82  
   
 
 
 
 
  Diluted   $ 0.41   $ 0.39   $ 0.92   $ 2.82  
   
 
 
 
 
Weighted average number of Units outstanding (thousands)                          
  Basic     70,850     64,776     70,066     50,738  
   
 
 
 
 
  Diluted     71,019     64,853     70,181     50,817  
   
 
 
 
 

21

CONSOLIDATED STATEMENT OF ACCUMULATED INCOME

 
   Three Months Ended September 30
   Nine months Ended September 30
($ thousands)
(Unaudited)
  2002
   2001
   2002
   2001
Accumulated income, beginning of period   $ 359,988   $ 262,489   $ 324,570   $ 144,301
Net income     29,081     25,141     64,499     143,329
   
 
 
 
Accumulated income, end of Period   $ 389,069   $ 287,630   $ 389,069   $ 287,630
   
 
 
 

22

ENERPLUS RESOURCES FUND
CONSOLIDATED STATEMENT OF CASH FLOWS

 
   Three Months Ended September 30
   Nine Months Ended September 30
  
($ thousands)
(Unaudited)
  
  2002
   2001
   2002
   2001
  
OPERATING ACTIVITIES                          
Net income   $ 29,081   $ 25,141   $ 64,499   $ 143,329  
Depletion, depreciation and Amortization     52,656     55,423     158,906     135,885  
Future income tax     (11,124 )   5,106     (19,338 )   (13,260 )
Site restoration and abandonment Costs incurred     (1,023 )   (719 )   (3,130 )   (1,343 )
   
 
 
 
 
Funds flow from operations     69,590     84,951     200,937     264,611  
Decrease (increase) in non-cash Operating working capital     1,787     (7,565 )   21,832     (35,779 )
   
 
 
 
 
      71,377     77,386     222,769     228,832  
   
 
 
 
 
FINANCING ACTIVITIES                          
Issue of trust units, net of Issue costs     124,591     11,253     131,274     45,845  
Cash distributions to unitholders     (61,323 )   (92,677 )   (163,894 )   (252,512 )
Increase (decrease) in long-term Debt     (78,351 )   79,768     (50,131 )   93,325  
Payment to related party (Note 3)     (128 )   (127 )   (384 )   (127 )
Deferred charges      —      —     (1,892 )   —  
   
 
 
 
 
      (15,211 )   (1,783 )   (85,027 )   (113,469 )
   
 
 
 
 
INVESTING ACTIVITIES                          
Property, plant and equipment     (54,366 )   (101,495 )   (137,696 )   (156,323 )
Proceeds on sale of property, Plant and equipment     308     34,755     2,446     61,581  
Corporate acquisitions      —      (8,792 )    —      (20,594 )
   
 
 
 
 
      (54,058 )   (75,532 )   (135,250 )   (115,336 )
   
 
 
 
 
Increase in cash     2,108     71     2,492     27  
Cash, beginning of period     1,363     802     979     846  
   
 
 
 
 
Cash, end of period   $ 3,471   $ 873   $ 3,471   $ 873  
   
 
 
 
 
Funds flow from operations per unit   $ 0.98   $ 1.31   $ 2.87   $ 5.22  
   
 
 
 
 
SUPPLEMENTARY CASH FLOW INFORMATION                          
  Cash income taxes paid   $  —    $ —   $  —    $ —  
  Cash interest paid   $ 2,099   $ 5,373   $ 9,483   $ 13,278  
   
 
 
 
 

23

CONSOLIDATED STATEMENT OF ACCUMULATED CASH DISTRIBUTIONS

 
   Three Months Ended September 30
   Nine Months Ended September 30
($ thousands)
(Unaudited)
  2002
   2001
   2002
   2001
Accumulated cash distributions, Beginning of period   $ 881,863   $ 619,051   $ 777,992   $ 447,158
Cash distributions to unitholders     61,589     87,712     165,460     259,605
   
 
 
 
Accumulated cash distributions, end of period   $ 943,452   $ 706,763   $ 943,452   $ 706,763
   
 
 
 

24

SELECTED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

1.    SIGNIFICANT ACCOUNTING POLICIES

2.    FUND CAPITAL

25

 
   September 30, 2002
   December 31, 2001
Issued: (thousands)
  Units
   Amount
   Units
   Amount
Balance, beginning of period   69,532   $ 1,826,507   40,925   $ 1,050,986
Issued for cash:                    
  Pursuant to public offerings   4,750     120,886   4,313     101,039
  Pursuant to Option Plans   98     1,905   135     2,530
  Pursuant to exercise of warrants    —       —    1,197     33,319
  Pursuant to expiry of warrants    —       —    —     2,846
Issued pursuant to the deemed Acquisition of Enerplus (Note 1)   —     —   20,863     582,364
Issued pursuant to the management agreement (Note 3)   —     —   173     5,000
Distribution Reinvestment & Unit Purchase Plan   340     8,483   659     16,577
Issued for acquisition of Property interests   31     740   1,267     31,846
   
 
 
 
Balance, end of period   74,751   $ 1,958,521   69,532   $ 1,826,507
   
 
 
 
 
   September 30, 2002
   December 31, 2001
(thousands except per Unit amounts)
   Number of Options
   Weighted Average Exercise Price
   Number of Options
   Weighted Average Exercise Price
Options outstanding at beginning of period   264   $ 20.93   363 (1) $ 21.03
Exercised   (98 ) $ 19.55   (55 ) $ 21.94
Cancelled   (16 ) $ 22.73   (44 ) $ 20.47
   
       
     
Options outstanding at end of period   150   $ 21.75   264   $ 20.93
   
       
     
Options exercisable at end of period   119         99      
   
       
     

26

 
   September 30, 2002
   December 31, 2001
(thousands except per Unit amounts)
   Number of Rights
   Weighted Average Exercise Price
   Number of Rights
   Weighted Average Exercise Price
Rights outstanding at Beginning of period   1,318   $ 24.50   —     —
Granted   145   $ 26.66   1,360   $ 24.50
Cancelled   (115 ) $ 24.47   (42 ) $ 24.50
   
       
     
Rights outstanding at End of period   1,348   $ 24.63   1,318   $ 24.50
   
       
     

3.    RELATED PARTY TRANSACTIONS

27

4.    LONG-TERM DEBT

 
   September 30, 2002
   December 31, 2001
Bank credit facilities   $ 94,130   $ 412,589
Senior unsecured notes     268,328     —
   
 
Total long-term debt   $ 362,458   $ 412,589
   
 

5.    FINANCIAL INSTRUMENTS

28

Term
   Notional Amount
   Fixed Rate(1)
January 18, 2002 to January 18, 2005   $ 25 million   3.89%
June 3, 2002 to June 3, 2005     25 million   4.70%
June 4, 2002 to June 4, 2005     25 million   4.65%
   
   
    $ 75 million    
   
   
 
    
   WTI Crude Oil Price US $
Term
   Volume Bbls/day
  Sold Call
   Purchased Put
   Sold Put
July 1, 2002 – Dec. 31, 2002                      
  3-way   1,500   US$ 27.00   US$ 19.50   US$ 16.00
  3-way(1)   1,500   US$ 25.00   US$ 19.50   US$ 17.00
  3-way   2,175   US$ 27.00   US$ 19.50   US$ 17.00
  3-way   1,500   US$ 28.00   US$ 20.10   US$ 17.00
  3-way(2)   1,500   US$ 31.00   US$ 22.00   US$ 19.50
  3 way(2)   1,500   US$ 30.00   US$ 24.00   US$ 21.35
Oct. 1, 2002 – Sept. 30, 2004                      
  3-way(2)   1,500   US$ 29.00   US$ 22.00   US$ 19.25
Jan. 1, 2003 – Sept. 30, 2004                      
  3-way(2)   1,500   US$ 30.00   US$ 23.00   US$ 20.00
Jan. 1, 2003 – Dec. 31, 2003                      
  3-way   1,500   US$ 27.00   US$ 19.50   US$ 17.00
  3-way   1,500   US$ 28.00   US$ 20.15   US$ 17.00
  3-way(2)   1,500   US$ 28.51   US$ 22.00   US$ 19.50
Jan. 1, 2003 – June 30, 2004                      
  3-way(2)   1,500   US$ 28.00   US$ 22.50   US$ 19.60
  3-way(2)   500   US$ 28.00   US$ 22.50   US$ 19.90
Jan. 1, 2003 – December 31, 2004                      
  3-way(3)   1,500   US$ 29.50   US$ 22.00   US$ 20.00

29

 
   MMcf/day
   AECO $/Mcf CDN$
Term
   Daily Volumes
   Sold Call
   Purchased Put
   Sold Put
   Fixed Price
   Escalated Price
July 1, 2002 – Oct. 31, 2002                                  
  Physical   3.8     —     —     —   $ 2.63     —
  Physical   8.5     —     —     —   $ 3.97     —
  Collar(1)   9.5   $ 5.27   $ 3.69     —     —     —
  Put(1)   9.5     —   $ 3.69     —     —     —
  3-way   9.5   $ 4.22   $ 3.29   $ 2.37     —     —
July 1, 2002 – Dec. 31, 2002                                  
  Physical   2.8     —     —     —   $ 2.64     —
  Physical   2.0     —     —     —     —   $ 2.01
  Swap   3.8     —   $ 2.90     —     —     —
  Collar   7.6   $ 4.22   $ 3.43     —     —     —
  Collar   5.7   $ 4.81   $ 3.43     —     —     —
  Collar   14.2   $ 4.22   $ 3.32     —     —     —
Nov. 1, 2002 – Dec. 31, 2002                                  
  Collar(1)   7.1   $ 5.27   $ 3.69     —     —     —
  Put(1)   7.1     —   $ 3.69     —     —     —
  Call   9.5   $ 6.33     —     —     —     —
Nov. 1, 2002 – Mar. 31, 2003                                  
  3-way(2)(3)   4.8   $ 7.39   $ 5.28   $ 4.22     —     —
  3-way(4)(5)   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     —     —     —

30

Jan. 1, 2003 – Dec. 31, 2003                                  
  Physical   2.0     —     —     —     —   $ 2.23
  Swap   3.8     —   $ 2.90     —     —     —
  3-way   9.5   $ 7.91   $ 4.27   $ 3.17     —     —
Jan. 1, 2003 – June 30, 2004                                  
  3-way   9.5   $ 7.39   $ 4.75   $ 3.17     —     —
Jan. 1, 2003 – Sept. 30, 2004                                  
  3-way(2)   9.5   $ 6.67   $ 4.75   $ 3.17     —     —
  3-way(2)   9.5   $ 7.39   $ 4.75   $ 3.69     —     —
Jan. 1, 2003 – Oct. 31, 2006                                  
  Swap(5)   9.5     —   $ 5.47     —     —     —
Apr.1, 2003 – Oct. 31, 2003                                  
  Collar(2)   4.8   $ 6.25   $ 4.75     —     —     —
  Collar(5)   4.8   $ 6.25   $ 4.75     —     —     —
Jan. 1, 2004 – Oct. 31, 2004                                  
  Swap   3.8     —   $ 2.90     —     —     —
2004 – 2010                                  
  Physical   2.0     —     —     —     —   $ 2.33

6.    COMMITMENTS AND CONTINGENCIES

7.    SUBSEQUENT EVENT

31

32

DIRECTORS

Douglas R. Martin(3)(4)(5)(8)
President, Charles Avenue Capital Corp.
Calgary, Alberta

André Bineau(1)
Vice President, Association de bienfaisance et de retraite des
policiers et policières de la Ville de Montréal
Montréal, Québec

Derek J.M. Fortune(3)(4)(9)
Secretary/Manager, Superannuation Fund,
City of Ottawa
Ottawa, Ontario

Gordon J. Kerr(4)
President & Chief Executive Officer,
Enerplus Global Energy Management Company
Calgary, Alberta

Robert L. Normand(1)(3)(6)
Corporate Director,
Montréal, Québec

Eric P. Tremblay(2)
Senior Vice President, Capital Markets,
Enerplus Global Energy Management Company
Calgary, Alberta

Harry B. Wheeler(1)(2)(7)
President,
Colchester Investments Ltd.
Calgary, Alberta

Robert L. Zorich
Managing Director,
EnCap Investments L.C.
Houston, Texas

(1)
Audit & Risk Management Committee

(2)
Environment, Safety & Reserves Committee

(3)
Corporate Governance Committee

(4)
Compensation & Human Resources Committee

(5)
Chairman of the Board

(6)
Chairman of the Audit & Risk Management Committee

(7)
Chairman of the Environment, Safety & Reserves Committee

(8)
Chairman of the Corporate Governance Committee

(9)
Chairman of the Compensation & Human Resources Committee

OFFICERS

Gordon J. Kerr
President & Chief Executive Officer


Robert J. Waters
Senior Vice President & Chief Financial Officer

Heather J. Culbert
Senior Vice President, Corporate Services

Garry A. Tanner(10)
Senior Vice President, Business Development

Eric P. Tremblay
Senior Vice President, Capital Markets

Jo-Anne M. Caza
Vice President, Investor Relations

Daryl W. Cook
Vice President, Operations

Wayne T. Foch
Vice President, Finance

Gerald F. Stevenson
Vice President, Acquisitions

Rodney D. Gray
Controller, Finance

Christina S. Meeuwsen
Corporate Secretary

Wayne G. Ford
Controller, Operations

(10)
Officer of Enerplus Global Energy Management Company only

CORPORATE INFORMATION

OPERATING COMPANIES OWNED BY
ENERPLUS RESOURCES FUND

EnerMark Inc.
Enerplus Resources Corporation

LEGAL COUNSEL
Blake, Cassels & Graydon LLP
Calgary, Alberta and Toronto, Ontario

AUDITORS
Deloitte & Touche LLP
Calgary, Alberta

TRANSFER AGENT
The CIBC Mellon Trust Company
Calgary, Alberta
Toll free: 1-800-387-0825
Email: inquiries@cibcmellon.com

CO-TRANSFER AGENT
Mellon Investor Services L.L.C.
Ridgefield, New Jersey

INDEPENDENT RESERVE ENGINEERS
Sproule Associates Limited
Calgary, Alberta

STOCK EXCHANGE LISTINGS AND
TRADING SYMBOLS
New York Stock Exchange:    ERF
Toronto Stock Exchange:    ERF.un

HEAD OFFICE

The Dome Tower
3000, 333 - 7th Avenue S.W.
Calgary, Alberta T2P 2Z1

Telephone: (403) 298-2200
Toll free: 1-800-319-6462
Fax: (403) 298-2211
Email: investorrelations@enerplus.com

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

ABBREVIATIONS
AECO    Alberta Energy Company interconnect with the Nova Gas System
ARTC    Alberta Royalty Tax Credit
bbl(s)/day    barrel(s) per day
BOE(s)/day    barrel of oil equivalent per day (6 Mcf gas = 1 bbl crude oil)
Mbbls    thousand barrels
MBOE    thousand barrels of oil equivalent
Mcf/day    thousand cubic feet per day
MMbbl(s)    million barrels
MMBOE    million barrels of oil equivalent
MMcf/day    million cubic feet per day
NYSE    New York Stock Exchange
TSX    Toronto Stock Exchange
W.I.    percentage working interest of ownership
WTI    West Texas Intermediate oil at Cushing, Oklahoma

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
Corporate Secretary
 		 

DATE:  November 14, 2002



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