EX-1 2 ex1.htm Q1 REPORT Q1 Report
 
EXHIBIT 1
 
ENERPLUS RESOURCES FUND
RESULTS FOR THE THREE MONTHS ENDED MARCH 31, 2005
 
SELECTED FINANCIAL RESULTS
          
           
Three months ended March 31,
  
2005
  
2004
  
               
Financial (000’s)
              
Net Income
  
$
62,192
  
$
45,166
  
Funds Flow from Operations (1)
    
153,741
    
121,239
  
Cash Distributed (2)
    
109,843
    
99,426
  
Cash Withheld
   
43,898
    
21,813
  
Debt Outstanding
   
562,369
    
378,427
  
Development Capital Spending
    
69,303
    
36,690
  
Acquisitions
    
1,820
    
131,436
  
Divestments
    
61,689
    
1,041
  
               
Weighted Average Number of Trust Units Outstanding
   
104,269
    
94,492
  
Debt/Trailing 12 Month Funds Flow Ratio (1)
    
1.0x
    
1.0x
  
               
Financial per Unit
              
Net Income
 
$
0.60
  
$
0.48
  
Funds Flow from Operations (1)
    
1.47
    
1.28
  
Cash Distributed (2)
    
1.05
    
1.05
  
Cash Withheld
   
0.42
    
0.23
  
Payout Ratio
   
71
%
  
82
%
               
Selected Financial Results per BOE
             
Oil & Gas Sales (3)
  
$
42.55
  
$
36.75
  
Royalties
    
(8.78
)
  
(7.52
)
Financial Contracts (4)
    
(2.86
)
  
(2.16
)
Operating Costs
    
(6.98
)
  
(6.53
)
General and Administrative (4)
    
(1.09
)
  
(1.04
)
Interest and Foreign Exchange (4)
    
(0.71
)
  
(0.38
)
Taxes
   
(0.17
)
  
(0.24
)
Restoration and Abandonment
    
(0.29
)
  
(0.26
)
Funds Flow from Operations (1)
  
$
21.67
  
$
18.62
  
               
Average Daily Production
              
Natural gas (Mcf/day)
    
280,463
    
262,096
  
Crude oil (bbls/day)
    
27,448
    
23,248
  
NGLs (bbls/day)
    
4,621
    
4,622
  
Total (BOE/day) (6:1)
    
78,813
    
71,553
  
% Natural gas
    
59
%
  
61
%
               
Net Wells Drilled
    
95
    
59
  
Success Rate
    
100
%
  
99
%
Average Selling Price (3)
              
Natural gas (per Mcf)
  
$
6.58
  
$
6.10
  
Crude oil (per bbl)
  
$
47.61
  
$
38.00
  
NGLs (per bbl)
  
$
43.80
  
$
29.73
  
US$ exchange rate
    
0.82
    
0.76
  
(1)  See the definition of funds flow in Management’s Discussion and Analysis
(2)  Calculated based on distributions paid or payable each month relating to the period
(3)  Including oil and gas transportation costs and before financial contracts
(4)  Non-cash amounts have been excluded

Page 4
 
           
TRUST UNIT TRADING SUMMARY
  
TSX - ERF.un (CDN$)
  
NYSE - ERF (US$)
  
Three months ended March 31, 2005
              
High
  
$
49.16
  
$
39.76
  
Low
  
$
40.00
  
$
32.86
  
Close
  
$
43.88
  
$
36.26
  
 
           
2005 CASH DISTRIBUTIONS PER TRUST UNIT
  
CDN$
  
US$
  
               
Production Month
  
Payment Month
          
                     
January
    
March
  
$
0.35
  
$
0.29
  
February
    
April
    
0.35
    
0.28
 
March
    
May
    
0.35
    
0.28*
 
First Quarter Total
        
$
1.05
  
$
0.85
  
* Calculated using an exchange rate of 1.24

PRESIDENT’S MESSAGE

Enerplus is off to a strong start in 2005. During the first quarter we participated in the drilling of 188 gross wells (94.8 net) achieving a 100% success rate, increased production volumes over first quarter 2004 by 10%, increased funds flow from operations by 27% (15% per unit) and increased the amount of cash retained to fund our capital development program by over 100%. In addition, distributions paid to Unitholders were maintained at $0.35 per unit per month with a 71% payout ratio.

During the quarter we made significant progress on the execution of our strategies in all core focus areas which includes shallow gas development, waterflood projects and joint venture deep natural gas development. In addition we participated in the drilling of 34 gross (21.4 net) wells on our commercial coalbed methane (“CBM”) projects at Trochu, Joffre and Bashaw and pilot CBM programs in several other areas. CBM is a new development focus for Enerplus where we plan to spend $27 million in 2005 participating in 120 wells.

We are also strongly encouraged by the results we are experiencing on the ChevronTexaco properties acquired in 2004 and the opportunities we see for further development of these properties. At Bantry North, for example, we drilled five successful oil wells in the quarter with plans for additional drilling later in the year and into 2006. At the time of acquisition, we had expected to drill only 5 wells in total on this property.

At Joslyn Creek in the Alberta oilsands fairway where we hold a 16% non-operated working interest, performance of the Phase I initial SAGD pilot well pair is meeting expectations. The 10,000 barrel per day (1,600 net) Phase II commercial development is on schedule with the drilling of 15 well pairs expected to be completed by year end and initial steam injection commencing in early 2006.

Through the quarter we continued to seek opportunities to acquire additional oil and gas assets. However, we did not acquire any significant assets in the quarter as successful bid levels exceeded our view of value. This current competitive environment for acquisitions is somewhat reminiscent of what we experienced in 2001. As in 2001, we have a significant inventory of projects that we expect to develop over the next few years to help sustain our production levels. We will continue to seek additional acquisitions, however, we will stay true to our discipline of bidding at levels we believe build longer-term value for our unitholders.

Crude oil and natural gas prices have remained strong. In particular, concern that world demand for oil is outstripping supply, combined with supply disruptions and infrastructure constraints, have resulted in a continued increase in the price of crude oil.

The strength of these commodity prices has provided additional support for our development programs both from a project economics perspective as well as from an internally generated funding perspective. At existing price levels, we expect to fund a majority of our 2005 capital development spending, the largest in our history, from cash retained out of our funds flow from operations.
 
Page 5
 
We believe that supply and demand fundamentals will continue to exert upward pressure on crude oil and natural gas prices over the long term. However, we also believe that there will continue to be volatility in these commodity prices. Accordingly, we will continue to manage our exposure to downside price risk, through the purchase of financial contracts, while positioning to retain exposure to upside price movements. This approach is intended to provide greater protection to our distributions and support the economics of our capital spending.

Our capital spending is on track to achieve our full year target of $275 million. We have successfully executed on our development plans despite weather impacts and high levels of competition for services. We are very encouraged by our production results to date and expect to achieve our annual average production target of 75,500 BOE per day without any acquisitions. Our financial position is strong and we are well on our way to achieving another successful year in 2005.


Gordon J. Kerr
President & Chief Executive Officer


OPERATION’S OVERVIEW
 
Enerplus currently enjoys a healthy inventory of internal development prospects across our asset base. Our ability to mitigate the natural decline inherent in oil and natural gas assets through our development activities not only reduces our reliance on future acquisitions, but helps maintain production volumes year over year. We are currently focused on executing a $275 million capital program, the largest in our history. A meaningful portion of this program is linked to the ChevronTexaco acquisition completed in the first half of 2004, as the development opportunities within these assets are surpassing our original expectations.

Daily production volumes for the first quarter exceeded our target by approximately 1,500 BOE/day, averaging 78,813 BOE/day. Better than expected performance at several of our waterflood and shallow natural gas properties along with an accelerated capital program were the main contributors to these positive results. We experienced our most active first quarter development program ever, investing approximately $70 million which is in line with our full year development budget. Effective planning enabled us to fully execute our drilling program despite warm weather conditions, earlier than normal break-up and a very competitive service environment. During the quarter we also sold approximately 2,200 BOE/day of non-core, low netback properties as planned. These sales resulted in a reduction of just over 1,000 BOE/day to our first quarter average production.

Operating costs in the first quarter were $6.98/BOE. Higher production and divestment of higher cost properties during the first quarter helped offset upward cost pressures driven by high industry activity levels. We expect to see an increase in operating costs in the second quarter due to planned plant turnaround and maintenance activities and as a result, continue to target full year operating costs of $7.45/BOE.

Enerplus employees achieved excellent safety performance with no lost time incidents or recordable injuries (such as those requiring medical aid or resulting in restricted work or lost time) during the first quarter of 2005. Safety performance for contractors as measured by lost time incidents was 0.73 incidents per 200,000 man-hours worked in the first quarter, which matches overall performance for 2004. We are continuing our efforts to reinforce both employee and contractor safety on our work sites to mitigate lost-time accidents.

Drilling Activity

A record number of wells were drilled during our first quarter drilling program. We participated in 188 gross wells (94.8 net) with a 100% success rate. This drilling activity is 57% higher than the number of gross wells drilled during the same period last year. Our activities were concentrated on natural gas and CBM drilling in the Bantry, Trochu, Joffre and the Deep Basin areas. Oil development drilling occurred at our Pembina and Bantry North areas.
 
           
 
Crude Oil
Natural Gas
Service
Dry & Abandoned
Total
 
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Operated Wells
12
11.4
65
56.3
2
1.6
0
0.0
79
69.3
Non-operated Wells
21
3.8
88
21.7
0
0.0
0
0.0
109
25.5
Total Wells Drilled
33
15.2
153
78.0
2
1.6
0
0.0
188
94.8
 
Page 6

Shallow Natural Gas Development

Shallow natural gas development continues to be a major component of our capital program. In 2005, we currently have plans to participate in the drilling of over 400 gross shallow gas wells (225 net) including approximately 90 gross high density shallow gas wells. With a planned capital budget of $54 million this year, we are well on our way to executing our program with first quarter activity totaling approximately $11 million. We followed up on our 2004 high density drilling success by drilling 43 gross wells (39.4 net) in the Bantry area. These wells were drilled and put on production in the first quarter, ahead of schedule. In the second quarter, we will focus our shallow gas drilling at Hanna, where we plan to drill 75 gross wells (70 net) with production expected to be on stream in the third quarter. Significant development is also planned for Shackleton, Verger and Medicine Hat during the remainder of the year. We anticipate our shallow gas program will add approximately 18 MMcf/day net initial production to the Fund in 2005.

Waterflood Development

Strong crude oil prices continue to support and improve the economic returns on our waterflood development activities. Enerplus invested approximately $15 million on waterflood projects in the first quarter of 2005. At Pembina, development activities included water injector optimization, processing facility upgrades and the drilling of 5 oil wells (100% WI) in the Cardium formation. Given the initial success of these wells, we plan to drill 8 additional wells. Total initial production increases from this program are expected to be approximately 500 BOE/day.

In the second quarter, we plan to initiate a significant waterflood and development extension program at Joarcam in the Viking formation. During the course of 2005, we plan to drill up to 21 gross wells and initiate waterflood optimization and facility upgrades. Initial production volumes expected from this program are in the range of 600 BOE/day. Additional development activities, including drilling, production optimization and facility upgrades, are also planned at Virden, Medicine Hat and Giltedge during the remainder of the year.

Joint Venture Deep Gas

Enerplus is on track to participate in approximately 80 gross wells (5 net) in 2005 with experienced partners in this prolific natural gas area of the Western Canadian Sedimentary Basin. During the first quarter of 2005, we invested approximately $6.5 million in joint venture deep gas projects in the Deep Basin and Foothills areas of western Alberta and northeastern British Columbia. Development activities included participation in the drilling of 32 gross wells (1.9 net) and infrastructure investments. Production from these new wells is expected to be tied in and on stream by the third quarter.

Coalbed Methane

Coalbed methane in Alberta has become an important new development area for Enerplus. We have targeted a capital program of $27 million in 2005 and have invested approximately $5 million of this budget during the first quarter. At Trochu, we initiated a 10 gross well (8 net) drilling program that is expected to be tied in and producing later this year. We also plan to drill up to 9 additional wells in this area. At Joffre, we participated in the drilling of 19 gross wells (9.5 net) in the first quarter with more planned in the second and third quarters. Enerplus also drilled 5 gross wells (3.9 net) at Bashaw in the first quarter with up to 30 gross wells to be drilled in the second half of the year. We are on track to participate in over 120 gross development CBM wells (73 net) in 2005, the majority of which will be in the Horseshoe Canyon coal formation. Initial production volumes of approximately 8 MMcf/day net are expected from this drilling activity. Several pilot programs will also be initiated and if successful, will provide further CBM development opportunities into 2006.

Other Conventional Oil and Gas Development

Significant development activity took place at Bantry North, a property acquired via the ChevronTexaco acquisition. In the first quarter, $4.5 million was invested to drill and test 5 new oil wells (100% WI) in the Sunburst formation and to tie in 2 existing wells. Initial results are encouraging and we are proceeding with plans for the installation of a significant new production handling facility to accommodate the incremental production from the new wells. Up to 5 additional oil wells in the Sunburst formation are planned for the latter part of this year with more potential locations tentatively planned for 2006. Once the facility expansion is complete in late 2005, we anticipate approximately 2,000 BOE/day of new production to be on stream. During the first quarter, Enerplus also invested approximately $19 million in other conventional oil and gas drilling and development activities throughout the Western Canadian Sedimentary Basin.

Page 7

SAGD Development

Through our 16% working interest in the Joslyn SAGD project, Enerplus is a participant in the Alberta oil sands, an area that is expected to be the growth engine of Canada’s future oil production. This steam assisted gravity drainage project continues to advance with the completion of the winter drilling program. A total of 183 delineation wells were drilled this winter to increase the total database of wells to more than 800. Production from the SAGD Phase I pilot well pair is continuing to meet expectations and should reach 600 bbls/day gross (96 bbls/day net) of bitumen by the end of 2005. First quarter capital expenditures totaled approximately $8 million. The 10,000 bbl/day (1,600 bbl/day net) Phase II SAGD development is on schedule with engineering, procurement and construction proceeding as planned. Drilling is expected to begin this summer with completion of 15 of the planned 17 well pairs by December 2005. Initial steam injection is planned for early 2006 and initial production should occur in the latter part of 2006.
 
Acquisitions and Divestments

Enerplus made no significant acquisitions during the first quarter of 2005, however, we continued to evaluate opportunities in a disciplined manner, focusing on acquisitions that provide attractive base economics and accretion along with additional development upside.

Strong commodity prices supported the valuation of our previously announced disposition package. We closed the sale of approximately 7.8 million BOE of proved plus probable reserves, representing 2,200 BOE/day of production, for proceeds of $61.7 million. Considering the high operating costs, shorter reserve lives and limited upside potential of these non-core assets, the metrics are attractive at approximately $7.90/BOE of proved plus probable reserves and $28,000/BOE/day of production.

With our focus on portfolio management, we continue to assess acquisition opportunities outside of the conventional Canadian upstream market including U.S. assets as well as other energy related opportunities in infrastructure and oil sands.
 
MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”)
 
The following discussion and analysis of financial results is dated May 5, 2005 and is to be read in conjunction with:
·
the MD&A and audited consolidated financial statements as at and for the years ended December 31, 2004 and 2003; and
·
the unaudited interim consolidated financial statements as at and for the three months ended March 31, 2005 and 2004.

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

Throughout the MD&A, we use the terms funds flow from operations (“funds flow”) and cash available for distribution. These terms as presented do not have any standardized meaning as prescribed by Canadian generally accepted accounting principles (“GAAP”), and therefore they may not be comparable with the calculation of similar measures 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 flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. Funds flow is used by management to analyze operating performance, leverage and liquidity. All references to funds flow throughout this report are based on cash flow from operating activities before changes in non-cash working capital. Cash available for distribution is calculated using funds flow less cash withheld for acquisitions, capital expenditures and debt repayment.

Page 8

OVERVIEW

Higher production from our acquisition and development program along with strong crude oil and natural gas prices helped Enerplus achieve record funds flow in the first quarter. This, together with the proceeds from the sale of non-core properties, more than funded our capital expenditure program for the quarter.
 
RESULTS OF OPERATIONS

Production

After exiting 2004 with production of approximately 80,000 BOE/day, we sold non-core properties representing 2,200 BOE/day. Despite these dispositions, we were able to achieve production of 78,813 BOE/day for the quarter. This represents a 10% increase over average production volumes of 71,553 BOE/day for the first quarter of 2004. This increase can be attributed to the additional volumes resulting from the acquisition of assets from ChevronTexaco Corporation (“ChevronTexaco”), which closed June 30, 2004, as well as our development capital program.

Our average production during the three months ended March 31, 2005 was weighted 59% natural gas and 41% crude oil and natural gas liquids on a BOE basis. Average production volumes for the three months ended March 31, 2005 and 2004 are outlined below:
 
           
   
Three months ended March 31,
      
Daily Production Volumes
 
2005
  
2004
  
% Change
  
Natural gas (Mcf/day)
    
280,463
    
262,096
    
7
%
Crude oil (bbls/day)
    
27,448
    
23,248
    
18
%
Natural gas liquids (bbls/day)
    
4,621
    
4,622
    
0
%
Total daily sales (BOE/day)
    
78,813
    
71,553
    
10
%

We are expecting lower production during the second quarter as a result of scheduled maintenance and turnarounds, which will interrupt production during the summer months. Furthermore, our disposition package completed throughout the first quarter, will fully impact our second quarter production. On an annual basis, we are maintaining our production estimate of 75,500 BOE/day.

Pricing

Our earnings, funds flow and financial condition are dependent on the prices received for our natural gas and crude oil production. Natural gas and crude oil prices have fluctuated widely during recent years.

The following table compares the Fund’s average selling prices for the three months ended March 31, 2005 and 2004. It also compares the benchmark price indices for the same periods.
 
           
   
Three months ended March 31,
      
Average Selling Price (1)
  
2005
  
2004
  
% Change
  
Natural gas (per Mcf)
  
$
6.58
  
$
6.10
    
8
%
Crude oil (per bbl)
  
$
47.61
  
$
38.00
    
25
%
Natural gas liquids (per bbl)
  
$
43.80
  
$
29.73
    
47
%
Per BOE
  
$
42.55
  
$
36.75
    
16
%

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

           
   
Three months ended March 31,
      
Average Benchmark Pricing
 
2005
  
2004
  
% Change
  
AECO natural gas (CDN$/Mcf)
  
$
6.69
  
$
6.61
    
1
%
NYMEX natural gas (US$/Mcf)
  
$
6.32
  
$
5.69
    
11
%
NYMEX natural gas: CDN$ equivalent (CDN$/Mcf)
  
$
7.71
  
$
7.49
    
3
%
WTI crude oil (US$/bbl)
  
$
49.84
  
$
35.15
    
42
%
WTI crude oil: CDN$ equivalent (CDN$/bbl)
  
$
60.78
  
$
46.25
    
31
%
CDN$/US$ exchange rate
    
0.82
    
0.76
    
8
%
 
Page 9
 
We realized an average price on our natural gas of $6.58/Mcf (net of transportation) during the three months ended March 31, 2005 an increase of 8% from $6.10/Mcf for the same period in 2004. In comparison, the AECO monthly index price for natural gas increased 1% and the NYMEX price, after adjusting for the change in the US$ exchange rate, increased 3% for the same period. In 2005, due in part to incremental production as well as the expiration of some term contracts, we increased the proportion of natural gas being sold at index price. In addition, sales to the aggregator markets achieved better prices and were more aligned with the index compared to 2004.
 
The average price we received for our crude oil during the three months ended March 31, 2005 increased 25% to $47.61/bbl (net of transportation) from $38.00/bbl during the same period of 2004. In comparison, the West Texas Intermediate (“WTI”) crude oil benchmark price after adjusting for the change in the US$ exchange rate increased 31% to $60.78/bbl for the three months ended March 31, 2005 from $46.25/bbl for the corresponding period of 2004. Our average crude oil price did not increase to the extent of the underlying WTI because the price received for our heavy crude oil was adversely affected by the increase in the price differential applied to heavier crude.

The Canadian dollar strengthened 8% against the U.S. dollar during the first quarter of 2005 compared to the same period in 2004. As most of our crude oil and a portion of our natural gas is priced in reference to U.S. dollar denominated benchmarks, this movement in the currency rate reduced the prices that we would have otherwise realized. However, in comparison to the fourth quarter of 2004 the Canadian dollar weakened by 1% during the first quarter of 2005.

Price Risk Management 

We continue to modify our commodity price risk management program which is designed to provide price protection on a portion of our future production. The program is intended to provide a measure of stability to our cash distributions and help realize positive economic returns from our capital development and acquisition activities.

Our commodity price risk management program incurred cash costs of $20.2 million during the three months ended March 31, 2005 compared to $14.0 million during the corresponding period of 2004. The increase in cash costs during 2005 compared to 2004 was primarily due to our three-way crude oil contracts. Continued record high oil prices exceeded our calls, the majority of which were put in place in 2003 and priced at approximately US$30/bbl. We also incurred cash costs on our natural gas contracts, but to a lesser extent than we experienced in 2004. Gas prices fluctuated within the price range of many of our derivative instruments.
 
       
Risk Management Cash Costs
  
Three months ended March 31,
  
($ millions, except per unit amounts)
  
2005
  
2004
  
Crude oil
  
$
18.8
  
$
7.61/bbl
  
$
9.6
  
$
4.54/bbl
  
Natural gas
    
1.4
  
$
0.06/Mcf
    
4.4
  
$
0.18/Mcf
  
Net hedging cost
  
$
20.2
  
$
2.86/BOE
  
$
14.0
  
$
2.16/BOE
  
 
We have adjusted our risk management strategies in response to the high cash costs associated with some of our existing positions. We plan to utilize put protection or put spread protection and incur the upfront costs associated with these contracts. We may sell calls (upside price participation), however we plan to do this for shorter durations, closer to the exercise dates. At the current time we do not have any CDN$/US$ exchange rate hedges associated with our revenues.

The following table summarizes the effects that our financial contracts have had on income for the three months ended March 31, 2005 and 2004.
 
       
   
Three months ended March 31,
  
   
2005
  
2004
  
Commodity Derivative Instruments
  
($ Millions)
  
(Per BOE)
  
($ Millions)
  
(Per BOE)
  
Financial contracts not qualifying as hedges:
                          
Change in fair value - other financial contracts
  
$
31.3
  
$
4.41
  
$
21.3
  
$
3.26
  
Amortization of deferred financial assets
    
1.0
    
0.14
    
5.4
    
0.83
  
Cash costs of financial contracts
   
17.3
    
2.45
    
9.7
    
1.50
  
   
$
49.6
  
$
7.00
  
$
36.4
  
$
5.59
  
Financial contracts qualifying as hedges:
                         
Cash costs of financial contracts
    
2.9
    
0.41
    
4.3
    
0.66
  
Total cost of financial contracts
  
$
52.5
  
$
7.41
  
$
40.74
  
$
6.25
  
 
Page 10
 
The unrealized cost of financial contracts of $31.3 million for the three months ended March 31, 2005 represents the change in fair value of financial contracts not qualifying for hedge accounting and results in a non-cash charge to earnings. The majority of this change results from the positive forward market for commodity prices.

The amortization of deferred financial assets is also a result of our adopting the new accounting rules for hedging relationships. On January 1, 2004, we recorded a deferred financial asset representing the fair value of the financial contracts that ceased to qualify for hedge accounting. The asset has been included in deferred charges and amortization of this asset was $1.0 million for the three months ended March 31, 2005, leaving an unamortized balance of $2.1 million.

The cash costs associated with financial contracts that do not qualify for hedge accounting are segregated from the costs of financial contracts that do qualify for hedge accounting. During the three months ended March 31, 2005 we realized cash costs of $17.3 million (2004 - $9.7 million) for financial contracts that do not qualify for hedge accounting as a result of commodity prices exceeding the ceiling price limits on many of our three-way crude oil contracts. Cash costs for financial contracts that qualify for hedge accounting were $2.9 million (2004 - $4.3 million).

Our current commodity risk management positions are fully described in Note 6. The following is a summary of the physical and financial contracts in place as at April 22, 2005 with floor protection and ceiling caps as a percentage of net production volumes:
 
       
 
2005
2006
2007
 
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Crude Oil (bbls/day)
                
Floor Protection
12,000
13,500
10,500
6,000
6,000
-
-
-
%
54
62
50
29
29
0
0
0
                 
Upside Capped
11,700
9,000
6,000
4,500
4,500
-
-
-
%
53
42
28
22
22
0
0
0
                 
Natural Gas (MMcf/day)
                
Floor Protection
95.0
92.2
79.6
35.2
25.7
25.7
10.0
-
%
43
43
38
17
13
13
5
0
                 
Upside Capped
88.7
73.2
66.9
35.2
25.7
25.7
10.0
-
%
40
34
32
17
13
13
5
0
Percentages are net of royalties and are based on forecast production including a decline rate throughout the year.
 
REVENUES

Crude oil and natural gas revenues for the three months ended March 31, 2005 were $301.8 million ($309.0 million, net of $7.2 million transportation) compared to $239.3 million ($245.6 million, net of $6.3 million transportation) for the same period in 2004. The increase of $62.5 million or 26% is primarily due to higher crude oil and natural gas prices as well as increased production resulting from the ChevronTexaco acquisition and our capital development program.
 
Analysis of Sales Revenue (1)                  
 
($ millions)
  
Crude Oil
  
NGLs
  
Natural Gas
  
Total
  
Quarter ended March 31, 2004
  
$
80.4
  
$
12.5
  
$
146.4
  
$
239.3
  
Price variance (1)
    
23.7
    
5.8
    
12.0
    
41.5
  
Volume variance
    
13.5
    
(0.1
)
  
7.6
    
21.0
  
Quarter ended March 31, 2005
  
$
117.6
  
$
18.2
  
$
166.0
  
$
301.8
  
 (1)  Net of oil and gas transportation costs, but before the effects of commodity derivative instruments

ROYALTIES

Royalties are paid to various government entities and other land and mineral rights owners. For the three months ended March 31, 2005 royalties increased to $62.3 million compared to $49.0 million during 2004, both approximately 20% of oil and gas sales, net of transportation. The increase is consistent with our revenue analysis of higher production and commodity prices during the first quarter. We expect royalties to remain at approximately 20% of oil and gas sales for the remainder of the year.
 
Page 11
 
OPERATING EXPENSES

Operating expenses for the three months ended March 31, 2005 were $49.5 million or $6.98/BOE compared to $42.5 million or $6.53/BOE for the same period in 2004, and $7.14/BOE for the year ended 2004. Total operating costs are in line with our expectations for the first quarter and are slightly lower on a BOE basis as a result of higher than expected production. Scheduled maintenance and turnarounds along with lower production are expected to increase operating costs both in total and per BOE during the second quarter. We are anticipating savings from the sale of non-core properties that will help offset cost increases and as a result we are maintaining our operating cost target of approximately $7.45/BOE for 2005.
 
GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative (“G&A”) expenses were $11.3 million or $1.60/BOE for the three months ended March 31, 2005 compared to $7.1 million or $1.10/BOE for the first quarter of 2004. The main reason for this increase relates to non-cash charges for our trust unit rights incentive plan. Cash G&A expenses were in line with expectations at $1.09/BOE in the first quarter of 2005 compared to $1.04/BOE in the first quarter of 2004 and $1.06/BOE for the
year 2004.

For the three months ended March 31, 2005 the non-cash charges were $3.6 million or $0.51/BOE compared to $0.4 million or $0.06/BOE for the first quarter of 2004. These non-cash charges relate to trust unit rights and are based on the excess of the trust unit price over the exercise price of the right. Changes in the value of unvested rights are amortized over the remaining vesting period. Any changes in the value of vested rights are charged to income in the period. The rights expense in the first quarter increased because a significant number of vested rights increased in value. Based on the vesting schedule and the additional production anticipated through the remainder of the year, we expect the rights expense per BOE to decrease by the end of 2005. See Note 5.

We continue to expect G&A costs to average approximately $1.45/BOE during 2005, which includes non-cash charges for the trust unit rights plan.

The following table summarizes the cash and non-cash expenses recorded in G&A:
 
       
General and Administrative Costs
 
Three months ended March 31,
  
($ millions)
  
2005
  
2004
  
Cash
  
$
7.7
  
$
6.7
  
Trust unit rights incentive plan (non-cash)
    
3.6
    
0.4
  
Total G&A
  
$
11.3
  
$
7.1
  
 
INTEREST EXPENSE

Interest expense increased to $5.9 million for the first quarter of 2005 from $4.0 million during the same period of 2004 due to higher average debt outstanding. Debt at March 31, 2005 was $562.4 million, an increase from $378.4 million at March 31, 2004 and the average bank prime rate increased only slightly from 4.23% in the first quarter of 2004 to 4.25% in the first quarter of 2005. At March 31, 2005, 25% of our debt was based on fixed interest rates while 75% was floating.
 
FOREIGN EXCHANGE

Non-cash gains or losses result from translating our US$54 million senior unsecured notes at period end. In addition, we incur minimal cash gains or losses from day-to-day transactions denominated in U.S. dollars. We experienced a foreign exchange loss of $0.3 million during the three months ended March 31, 2005 compared to a loss of $1.1 million for the same period in 2004. See Note 4 for details.
 
CAPITAL EXPENDITURES

During the three months ended March 31, 2005 we spent $69.3 million on development drilling and facilities compared to $36.7 million during the same period in 2004. We achieved a 100% success rate in drilling 94.8 net wells during the quarter focusing primarily on shallow gas development, waterflood development and our SAGD development project at Joslyn Creek.

Page 12
 
In the first quarter of 2005 we substantially completed our non-core property divestment program (approximately 2,200 BOE/day of production) raising $61.7 million. In addition, we completed $1.8 million of property acquisitions. This compares to $1.1 million of divestments and $131.4 million of acquisitions during the same period in 2004.

Our capital expenditures were financed through this divestment of non-core properties and by withholding a portion of cash otherwise available for distribution. Total net capital expenditures of $9.9 million for the first quarter of 2005 compared to $167.1 million for the first quarter of 2004 are outlined below.
 
       
Capital Expenditures
  
Three months ended March 31,
  
($ millions)
  
2005
  
2004
  
Development expenditures
  
$
54.3
  
$
27.4
  
Plant and facilities
    
15.0
    
9.3
  
Sub-total
    
69.3
    
36.7
  
Office
   
0.5
    
0.1
  
Sub-total
    
69.8
    
36.8
  
Acquisitions of oil and gas properties
    
1.8
    
0.9
  
Corporate acquisitions
    
-
    
130.5
  
Dispositions of oil and gas properties
    
(61.7
)
  
(1.1
)
Total Net Capital Expenditures
  
$
9.9
  
$
167.1
  

We continue to expect total capital expenditures in 2005 to be approximately $275 million, however, we may increase our capital program as we identify and execute on more of the opportunities within our existing properties, especially if higher commodity prices prevail.
 
DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION (“DDA&A”)

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

For the three months ended March 31, 2005, DDA&A increased to $12.26/BOE compared to $11.27/BOE during the corresponding period in 2004. The increase in DDA&A per BOE is due to the acquisition of ChevronTexaco properties, as well as higher production volumes.

No impairment of the Fund’s assets existed at March 31, 2005 using year-end reserves updated for acquisitions, divestitures and management’s estimates of future prices.
 
TAXES

Future income taxes arise from differences between the accounting and tax bases of the operating companies’ assets and liabilities. In our current structure, payments are made between the operating entities and the Fund, ultimately transferring both income and future income tax liability to our unitholders. Therefore, it is our opinion that no cash income taxes are expected to be paid by the operating entities in the future, and as such, the future income tax liability recorded on the balance sheet should be recovered through earnings over time.

For the three months ended March 31, 2005, a future income tax recovery of $29.6 million was recorded in income compared to $23.7 million for the same period in 2004. The increased recovery was mainly the result of increased net income of the Fund during 2005.
 
Page 13
 
SELECTED FINANCIAL RESULTS
       
Per BOE of production (6:1)
  
Three months ended March 31,
  
   
2005
  
2004
  
               
Production per day
    
78,813
    
71,553
  
Weighted average sales price (1)
  
$
42.55
  
$
36.75
  
Royalties
    
(8.78
)
  
(7.52
)
Financial contracts
    
(7.41
)
  
(6.25
)
Add back: Non-cash financial contracts
    
4.55
    
4.09
  
Operating costs
    
(6.98
)
  
(6.53
)
General and administrative
   
(1.60
)
  
(1.10
)
Add back: Non-cash G&A expense (trust unit rights)
    
0.51
    
0.06
 
Interest expense, net of interest and other income
    
(0.72
)
  
(0.37
)
Foreign exchange gain/(loss)
   
(0.04
)
  
(0.16
)
Add back: Non-cash foreign exchange gain/(loss)
    
0.05
    
0.15
  
Capital taxes
    
(0.17
)
  
(0.24
)
Restoration and abandonment cash costs
    
(0.29
)
  
(0.26
)
Funds flow from operations
    
21.67
    
18.62
  
Restoration and abandonment cash costs
    
0.29
    
0.26
  
Non-cash items:
              
Depletion, depreciation, amortization and accretion
    
(12.26
)
  
(11.27
)
Financial contracts
    
(4.55
)
  
(4.09
)
G&A expense (trust unit rights)
    
(0.51
)
  
(0.06
)
Foreign exchange
    
(0.05
)
  
(0.15
)
Future income tax recovery
   
4.18
    
3.63
  
Total net income per BOE
  
$
8.77
  
$
6.94
  
(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments


FUNDS FLOW FROM OPERATIONS AND NET INCOME

Funds flow from operations for the three months ended March 31, 2005 was $153.7 million or $1.47 per trust unit compared to $121.2 million or $1.28 per trust unit for the three months ended March 31, 2004. The increase in funds flow from operations was a result of higher production and commodity prices during the first quarter of 2005 compared to 2004, offset in part by the cash losses from our price risk management program and higher
operating costs.

Net income for the first quarter of 2005 was $62.2 million or $0.60 per trust unit compared to $45.2 million or $0.48 per trust unit for the first quarter of 2004. The increase in net income was largely due to more favourable commodity prices coupled with higher production. This was offset by changes in the fair values of financial contracts as well as increases in operating costs and depletion expense.
 
QUARTERLY FINANCIAL INFORMATION

Generally, oil and gas sales have increased due to higher prices and production both through acquisitions and capital development during the last two years, offset by an increased Canadian/U.S. dollar exchange rate. Oil and gas sales have dipped slightly from the fourth quarter of 2004 to the first quarter of 2005 partially due to the divestment of approximately 2,200 BOE/day of non-core properties. Net income has been affected by the fluctuations in oil and gas sales, the increase in risk management costs, the strengthening Canadian dollar, the internalization of the management contract during 2003, increasing operating costs and changes to accounting policies adopted during 2003 and 2004. Changes in the fair values of our financial contracts caused net income to fluctuate drastically between the fourth quarter of 2004 and the first quarter of 2005. A gain of $47.6 million on financial contracts increased 2004 fourth quarter net income while a loss of $32.3 million reduced 2005 first quarter net income.
 
Page 14
 
                   
Quarterly Financial Information
                 
($ millions, except per trust unit amounts)
  
Oil and Gas
  
Net
  
Net income per trust unit
  
   
Sales(1)
  
Income
  
Basic
  
Diluted
  
2005
                          
First quarter
  
$
301.8
  
$
62.2
  
$
0.60
  
$
0.59
  
2004
                          
Fourth quarter
  
$
317.5
  
$
114.5
  
$
1.10
  
$
1.10
  
Third quarter
    
302.2
    
50.6
    
0.49
    
0.49
  
Second quarter
    
265.6
    
48.0
    
0.51
    
0.51
  
First quarter
    
239.3
    
45.2
    
0.48
    
0.48
  
Total
  
$
1,124.6
  
$
258.3
  
$
2.60
  
$
2.60
  
2003 (Restated)
                          
Fourth quarter
  
$
201.5
  
$
40.6
  
$
0.45
  
$
0.45
  
Third quarter
    
219.7
    
59.2
    
0.67
    
0.67
  
Second quarter
    
233.5
    
53.4
    
0.64
    
0.64
  
First quarter
    
281.1
    
94.8
    
1.14
    
1.14
  
Total
  
$
935.8
  
$
248.0
  
$
2.88
  
$
2.87
  
(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments
 
CASH AVAILABLE FOR DISTRIBUTION

We monitor the distribution payout with respect to forecasted funds flow, debt levels and spending plans. The level of cash retained typically varies between 10% and 30% of annual funds flow, however we are prepared to adjust the payout levels in an effort to balance the investor’s desire for distributions with the Fund’s requirement to maintain a prudent capital structure. Our payout ratio for the first quarter of 2005 was 71% compared to a payout ratio of 82% for the first quarter of 2004.

The following table reconciles Enerplus’ funds flow from operations with the cash available for distribution to unitholders.
       
Reconciliation of Cash Available for Distribution
  
Three months ended March 31,
  
($ millions, except per unit amounts)
  
2005
  
2004
  
Funds flow from operations
  
$
153.7
  
$
121.2
  
Cash withheld for acquisitions, capital expenditures and debt repayment
    
(43.9
)
  
(21.8
)
Cash available for distribution *
  
$
109.8
  
$
99.4
  
Cash available for distribution per trust unit
  
$
1.05
  
$
1.05
  
Payout ratio
    
71
%
  
82
%
* Cash available for distribution will differ from Cash Distributions to Unitholders on the Consolidated Statements of Cash Flows due to the timing of distribution declaration and actual payments.


LIQUIDITY AND CAPITAL RESOURCES

Long-term debt at March 31, 2005 was $562.4 million, a decrease of $22.6 million from December 31, 2004. The decrease in debt is the result of increased funds flow from operations as well as proceeds from the disposition of non-core properties. Should commodity prices remain at current levels we expect to fund the bulk of our 2005 capital programs without incurring additional debt or issuing equity.

Long-term debt at March 31, 2005 is comprised of $228.7 million of bank indebtedness and $65.4 million and $268.3 million of Canadian dollar equivalent debt related to the US$54 million and US$175 million senior unsecured notes, respectively.

Working capital, excluding deferred credits, did not significantly change at March 31, 2005 compared to March 31, 2004. The fair value of instruments that do not qualify as hedges have been recorded as deferred credits and included in current liabilities on the balance sheet. These costs will fluctuate depending on the commodity prices at the time of settlement and will be paid from future production that is not yet recorded in the financial statements. Therefore, in the context of liquidity, deferred credits have been excluded from working capital.

Page 15
 
We continue to maintain a conservative balance sheet as demonstrated below:
 
     
Financial Leverage and Coverage
March 31, 2005
December 31, 2004
     
Long-term debt to funds flow
1.0x
1.1x
Funds flow to interest expense
25.2x
26.0x
Long-term debt to long-term debt plus equity
22%
23%
 
Funds flow and interest expense are 12-months trailing.
  
Enerplus has an $850 million bank credit facility (the “Bank Credit Facility”) through its wholly-owned subsidiary EnerMark Inc. The Bank Credit Facility is an unsecured, covenant-based, three-year committed credit agreement with nine North American banks. We have the ability to extend the facility each year or repay the entire balance at the end of the three-year term. As at March 31, 2005, we had $621.3 million of available borrowing capacity under this facility. This bank debt carries floating interest rates that are expected to range between 65 and 87.5 basis points over Bankers Acceptance rates, depending on Enerplus’ ratio of senior debt to earnings before interest, taxes and non-cash items.

Payments with respect to the bank facilities, senior unsecured notes and other third party debt have priority over claims of and future distributions to the unitholders. Unitholders have no direct liability should funds flow be insufficient to repay this indebtedness.

We anticipate that we will continue to have adequate liquidity to fund future working capital and planned capital expenditures during 2005 primarily through funds flow from operations. Most of Enerplus’ $275 million capital budget for 2005 is discretionary and can be revised downward in the event of a significant commodity price downturn or similar economic event.
 
COMMITMENTS

There were no material changes to our commitments at March 31, 2005 compared to December 31, 2004.
 
TRUST UNIT INFORMATION

We had 104,586,000 trust units outstanding at March 31, 2005 compared to 94,687,000 trust units at March 31, 2004 and 104,124,000 at December 31, 2004. The weighted average basic number of trust units outstanding during the first quarter of 2005 was 104,269,000 (2004 - 94,492,000).

During the three months ended March 31, 2005, 462,000 trust units (2004 - 338,000) were issued pursuant to the Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan (“DRIP”) and the trust unit rights plan. This resulted in $14.6 million (2004 - $9.3 million) of additional equity to the Fund. For further details see Note 5.
 
CANADIAN AND U.S. TAXPAYERS

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

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

In May 2005, Enerplus estimated its non-resident ownership to be approximately 72%.

ADDITIONAL INFORMATION

Additional information relating to Enerplus Resources Fund, including the Fund’s Annual Information Form, is available under the Fund’s profile on the SEDAR website at www.sedar.com and at www.enerplus.com.
 
Page 16
 
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 affecting the economic performance of Enerplus. Undue reliance should not be placed on these forward-looking statements which are based upon management’s assumptions and are subject to known and unknown risks and uncertainties, including the business risks discussed above, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted.
 
Page 17
 
ENERPLUS RESOURCES FUND
CONSOLIDATED BALANCE SHEETS
 
           
(CDN$ thousands) (Unaudited)
  
March 31, 2005
  
December 31, 2004
  
               
ASSETS
              
Current assets
              
Accounts receivable
  
$
117,881
  
$
107,996
  
Other current
    
13,604
    
9,602
  
     
131,485
    
117,598
  
Property, plant and equipment (Note 3)
    
2,946,017
    
3,029,007
  
Goodwill
   
29,082
    
29,082
  
Deferred charges (Note 2)
    
4,006
    
5,061
  
   
$
3,110,590
  
$
3,180,748
  
LIABILITIES
             
Current liabilities
              
Accounts payable
  
$
167,473
  
$
179,568
  
Distributions payable to unitholders
   
36,607
    
36,443
  
Deferred credits (Note 2)
    
73,593
    
42,303
  
     
277,673
    
258,314
  
Long-term debt
   
562,369
    
584,991
  
Future income taxes
   
205,915
    
235,551
  
Asset retirement obligations
   
97,978
    
105,978
  
     
866,262
    
926,520
  
EQUITY
              
Unitholders’ capital (Note 5)
    
2,849,512
    
2,831,277
  
Accumulated income
    
1,038,329
    
976,137
  
Accumulated cash distributions
   
(1,921,186
)
  
(1,811,500
)
     
1,966,655
    
1,995,914
  
   
$
3,110,590
  
$
3,180,748
  

 
Page 18
 
ENERPLUS RESOURCES FUND
CONSOLIDATED STATEMENTS OF INCOME
 
       
   
Three months ended March 31,
  
(CDN$ thousands except per trust unit amounts) (Unaudited)
  
2005
  
2004
  
               
REVENUES
              
Oil and gas sales
  
$
308,960
  
$
245,595
  
Royalties
    
(62,268
)
  
(48,988
)
Derivative instruments (Note 6)
              
Financial contracts - qualified hedges (Note 2)
    
(2,892
)
  
(4,288
)
Other financial contracts (Note 2)
    
(49,649
)
  
(36,420
)
Interest and other income
    
808
    
1,575
  
     
194,959
    
157,474
  
EXPENSES
              
Operating
    
49,477
    
42,535
  
General and administrative (Note 5)
    
11,329
    
7,138
  
Transportation
   
7,159
    
6,299
  
Interest on long-term debt
   
5,921
    
3,959
  
Foreign exchange loss (Note 4)
    
313
    
1,059
  
Depletion, depreciation, amortization and accretion
    
86,963
    
73,373
  
     
161,162
    
134,363
  
Income before taxes
    
33,797
    
23,111
  
Capital taxes
    
1,241
    
1,607
  
Future income tax recovery
   
(29,636
)
  
(23,662
)
NET INCOME
  
$
62,192
  
$
45,166
  
               
Net income per trust unit
              
Basic
  
$
0.60
  
$
0.48
  
Diluted
  
$
0.59
  
$
0.48
  
Weighted average number of trust units outstanding (thousands)
             
Basic
    
104,269
    
94,492
  
Diluted
    
104,777
    
94,717
  

 
CONSOLIDATED STATEMENTS OF ACCUMULATED INCOME
 
       
   
Three months ended March 31,
  
(CDN$ thousands) (Unaudited)
  
2005
  
2004
  
Accumulated income, beginning of period
   
976,137
    
717,821
  
Net income
    
62,192
    
45,166
  
Accumulated income, end of period
  
$
1,038,329
  
$
762,987
  
 
Page 19
 
ENERPLUS RESOURCES FUND
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
       
   
Three months ended March 31,
  
(CDN$ thousands) (Unaudited)
  
2005
  
2004
  
               
OPERATING ACTIVITIES
              
Net income
  
$
62,192
  
$
45,166
  
Non-cash items add/(deduct):
              
Depletion, depreciation, amortization and accretion
    
86,963
    
73,373
  
Non-cash financial contracts (Note 2)
    
32,296
    
26,704
  
Non-cash foreign exchange loss (Note 4)
    
324
    
978
  
Unit based compensation (Note 5)
    
3,648
    
359
  
Future income tax recovery
   
(29,636
)
  
(23,662
)
Asset retirement costs incurred
   
(2,046
)
  
(1,679
)
Funds flow from operations
    
153,741
    
121,239
  
(Increase)/decrease in non-cash working capital
    
(23,382
)
  
6,413
  
     
130,359
    
127,652
  
FINANCING ACTIVITIES
              
Issue of trust units, net of issue costs (Note 5)
    
14,587
    
9,280
  
Cash distributions to unitholders
    
(109,686
)
  
(99,326
)
(Decrease)/increase in bank credit facilities
   
(22,946
)
  
39,332
  
Decrease in non-cash financing working capital
    
164
    
131
  
     
(117,881
)
  
(50,583
)
INVESTING ACTIVITIES
              
Capital expenditures
    
(69,747
)
  
(36,801
)
Property acquisitions
    
(1,820
)
  
(892
)
Property dispositions
    
61,689
    
1,041
  
Corporate acquisitions
   
-
    
(121,171
)
(Increase)/decrease in non-cash investing working capital
   
(2,600
)
  
338
  
     
(12,478
)
  
(157,485
)
Change in cash
   
-
    
(80,416
)
Cash, beginning of period
    
-
    
80,416
  
Cash, end of period
  
$
-
  
$
-
  
SUPPLEMENTARY CASH FLOW INFORMATION
             
Cash income taxes paid
  
$
-
  
$
-
  
Cash interest paid
  
$
2,385
  
$
566
  

CONSOLIDATED STATEMENTS OF ACCUMULATED CASH DISTRIBUTIONS

       
   
Three months ended March 31,
  
(CDN$ thousands) (Unaudited)
  
2005
  
2004
  
               
Accumulated cash distributions, beginning of period
  
$
1,811,500
  
$
1,388,189
  
Cash distributions
    
109,686
    
99,326
  
Accumulated cash distributions, end of period
  
$
1,921,186
  
$
1,487,515
  
 
Page 20

ENERPLUS RESOURCES FUND
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars and thousands of units except per unit amounts) (Unaudited)


1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The interim consolidated financial statements of Enerplus Resources Fund (“Enerplus” or the “Fund”) have been prepared by management following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2004. 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, 2004. The disclosures provided below are incremental to those included in the 2004 annual consolidated financial statements.
 
2.  DEFERRED CHARGES AND DEFERRED CREDITS
       
Deferred Charges
     
Deferred charges as at December 31, 2004
 
$
5,061
  
Amortization of deferred financial assets
    
(1,006
)
Amortization of debt issue costs
    
(49
)
Deferred charges as at March 31, 2005
  
$
4,006
  
       
Deferred Credits
     
Deferred credits as at December 31, 2004
 
$
42,303
  
Change in fair value - other financial contracts (1)
    
31,290
  
Deferred credits as at March 31, 2005
  
$
73,593
  
(1) Changes in the fair value of financial contracts that do not qualify for hedge accounting are taken into income during the period as other financial contracts and reflected as an increase or decrease in the deferred financial liability.

The following table summarizes the income statement effects of other financial contracts:
       
   
Three months ended March 31,
  
Other Financial Contracts
    
2005
    
2004
  
Change in fair value
 
$
31,290
  
$
21,298
  
Amortization of deferred financial assets
    
1,006
    
5,406
  
Realized cash costs, net
   
17,353
    
9,716
  
Other financial contracts
  
$
49,649
  
$
36,420
  
 
In addition during the three months ended March 31, 2005 we realized cash costs of $2,892,000, net of gains and losses from financial contracts that qualified as hedges compared to cash costs of $4,288,000 during the same period of 2004.
 
3.  PROPERTY, PLANT AND EQUIPMENT
           
   
March 31, 2005
  
December 31, 2004
  
Property, plant and equipment
  
$
4,307,849
  
$
4,305,584
  
Accumulated depletion and depreciation
    
(1,361,832
)
  
(1,276,577
)
Net property, plant and equipment
  
$
2,946,017
  
$
3,029,007
  

Capitalized development general and administrative expenses of $2,508,000 (2004 - $2,038,000) is included in property, plant and equipment (“PP&E”) for the three months ended March 31, 2005. Excluded from PP&E for the depletion and depreciation calculation is $36,134,000 (2004 - $24,860,000) related to the Joslyn development project that has not commenced commercial production.

Page 21
 
4.  FOREIGN EXCHANGE
       
   
Three months ended March 31,
  
   
2005
  
2004
  
Unrealized foreign exchange loss on translation of U.S. dollar denominated senior notes
  
$
324
  
$
978
  
Realized foreign exchange (gain)/loss
    
(11
)
  
81
  
Foreign exchange loss
  
$
313
  
$
1,059
  
 
The US$54,000,000 senior unsecured notes that are exposed to foreign currency fluctuations are translated into Canadian dollars at the exchange rate in effect at the balance sheet date. Foreign exchange gains and losses are included in the determination of net income for the period.

5.  FUND CAPITAL

(a) Unitholders’ Capital

Trust Units

Authorized: Unlimited number of trust units
 
           
   
Three months ended
  
Year ended
  
   
March 31, 2005
  
December 31, 2004
  
Issued:
 
Units
  
Amount
  
Units
  
Amount
  
Balance before Contributed Surplus, beginning of period
    
104,124
  
$
2,826,641
    
94,349
  
$
2,510,011
  
Issued for cash:
                          
Pursuant to public offerings
    
-
    
-
    
8,800
    
286,248
  
Pursuant to rights plan
    
379
    
10,935
    
648
    
16,947
  
Trust unit rights incentive plan (non-cash) - exercised
    
-
    
1,320
    
-
    
1,396
  
DRIP*, net of redemptions
   
83
    
3,652
    
302
    
11,114
  
Issued for acquisition of corporate and property interests
    
-
    
-
    
25
    
925
  
     
104,586
    
2,842,548
    
104,124
    
2,826,641
  
Contributed Surplus (Trust Unit Rights Plan)
   
-
    
6,964
    
-
    
4,636
  
Balance, end of period
   
104,586
  
$
2,849,512
    
104,124
  
$
2,831,277
  
* Distribution Reinvestment and Unit Purchase Plan 

           
   
Three months ended
  
Year ended
  
Contributed Surplus
 
March 31, 2005
  
December 31, 2004
  
Balance, beginning of period
  
$
4,636
  
$
1,364
  
Trust unit rights incentive plan (non-cash) - exercised
    
(1,320
)
  
(1,396
)
Trust unit rights incentive plan (non-cash) - expensed
    
3,648
    
4,668
  
Balance, end of period
  
$
6,964
  
$
4,636
  
 
(b) Trust Unit Rights Incentive Plan

As at March 31, 2005, a total of 2,137,000 rights pursuant to the Trust Unit Rights Incentive Plan (“Rights Plan”) at an average exercise price of $35.95 were outstanding. This represents 2.0% of the total trust units outstanding of which 270,000 rights with an average exercise price of $28.75 were exercisable. Under the Rights Plan, distributions per trust unit to Enerplus unitholders in a calendar quarter which represent a return of more than 2.5% of the net PP&E of Enerplus at the end of such calendar quarter may result in a reduction in the exercise price of the rights. Results for the three months ended March 31, 2005 reduced the exercise price of the outstanding rights by $0.35 per trust unit effective July 2, 2005.

Page 22
 
Activity for the rights issued pursuant to the Rights Plan is as follows:
 
           
   
Three months ended
  
Year ended
  
   
March 31, 2005
  
December 31, 2004
  
   
Number
  
Weighted
  
Number
  
Weighted
  
   
of
  
Average
  
of
  
Average
  
   
Rights
  
Exercise
  
Rights
  
Exercise
  
   
(000’s)
  
Price (1)
  
(000’s)
  
Price (1)
  
Trust unit rights outstanding
                          
Beginning of period
    
2,401
  
$
34.33
    
2,192
  
$
30.05
  
Granted
    
129
    
45.55
    
1,002
    
40.22
  
Exercised
    
(379
)
  
28.89
    
(644
)
  
26.16
  
Cancelled
    
(14
)
  
38.43
    
(149
)
  
30.94
  
End of period
    
2,137
    
35.95
    
2,401
    
34.33
  
Rights exercisable at the end of the period
    
270
  
$
28.75
    
551
  
$
27.84
  
(1) Exercise price reflects grant prices less reduction in strike price discussed above.

Non-cash compensation costs of $3,648,000 ($0.03 per unit) related to the rights issued since January 1, 2003 have been charged to general and administrative expense during the three months ended March 31, 2005 (2004 - $359,000, $nil per unit).

The following table outlines the estimated compensation cost associated with the rights issued during 2002 and the pro forma effects on net income and net income per unit, had CICA Handbook section 3870 been applied retroactive to 2002.
 
       
   
Three months ended March 31,
  
($ thousands, except per unit amounts)
  
2005
  
2004
  
Net income as reported
  
$
62,192
  
$
45,166
  
Compensation expense for rights issued in 2002
    
(696
)
  
(818
)
Pro forma net income
  
$
61,496
  
$
44,348
  
Net income per trust unit - basic
              
Reported
 
$
0.60
  
$
0.48
  
Pro forma
  
$
0.59
  
$
0.47
  
Net income per trust unit - diluted
              
Reported
  
$
0.59
  
$
0.48
  
Pro forma
  
$
0.59
  
$
0.47
  
 
 
6.  FINANCIAL INSTRUMENTS

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

The carrying value of accounts receivable, current liabilities and outstanding bank credit facility balances approximate their fair value. Other current assets are comprised of prepaid expenses and marketable securities. The marketable securities are carried on the balance sheet at the lower of cost and fair value. The fair value of the marketable securities at March 31, 2005 exceeded the cost of these securities by $7,895,000. The Fund carried US$54,000,000 of fixed rate debt. In addition, it carried US$175,000,000 of fixed rate debt that was converted to CDN$268,328,000 floating rate debt through a cross-currency swap with a syndicate of financial institutions. At March 31, 2005 the fair values of the senior unsecured notes were $65,419,000 and $224,901,000 respectively. In addition $2,137,000 in deferred charges related to derivative instruments that no longer qualify for hedge accounting treatment will be amortized over the next year.

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

(a) Derivative Financial Instruments

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The Fund uses certain derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. The fair values of these instruments are based on an approximation of the amounts that would have been paid to or received from counterparties to settle the instruments outstanding as at March 31, 2005 with reference to forward prices and market valuations provided by independent sources.

The fair values of derivative financial instruments are as follows: 

Interest Rate and Cross Currency Swaps

The Fund has entered into interest rate swaps on $75,000,000 of notional debt at rates varying from 3.74% to 4.70% before banking fees that are expected to range between 0.65% and 0.875%. These interest rate swaps mature between June 2006 and January 2007. The fair value of the $75,000,000 interest rate swaps as at March 31, 2005 represents an unrealized cost of $1,235,000. These swaps have been designated as hedges for accounting purposes.

The fair value of the cross currency swap related to the US$175,000,000 senior unsecured notes as at March 31, 2005 represents an unrealized cost of $50,018,000 where as the fair value of the underlying debt instrument as at March 31, 2005 represents an unrealized gain of $43,427,000.

Crude Oil Instruments

Enerplus has entered into the following financial option contracts to reduce the impact of a downward movement in crude oil prices. The fair value of the financial crude oil contracts that do not qualify for hedge accounting are described in Note 2. The fair value of the financial crude oil contracts that qualify for hedge accounting reflects an unrealized cost of $20,448,000 at March 31, 2005.

The following table summarizes the Fund’s crude oil risk management positions at April 22, 2005:
 
           
       
WTI US$/bbl
  
   
Daily Volumes
  
Sold
  
Purchased
  
Sold
  
Term
  
bbls/day
  
Call
  
Put
  
Put
  
April 1, 2005 - May 31, 2005
                          
Call(1)
    
1,000
  
$
55.00
    
-
    
-
  
Call(1)
    
1,000
  
$
55.00
    
-
    
-
  
Call(1)
    
1,000
  
$
55.00
    
-
    
-
  
April 1, 2005 - June 30, 2005
                          
3-way option
    
1,500
  
$
28.00
  
$
24.00
  
$
21.00
  
Put *
    
1,500
    
-
  
$
36.10
    
-
  
June 1, 2005 - June 30, 2005
                          
Call(1)
    
1,000
  
$
60.00
    
-
    
-
  
Call(1)
    
1,000
  
$
60.75
    
-
    
-
  
April 1, 2005 - September 30, 2005
                          
3-way option
    
1,500
  
$
29.50
  
$
24.50
  
$
21.50
  
3-way option
    
1,500
  
$
29.40
  
$
24.50
  
$
21.50
  
July 1, 2005 - September 30, 2005
                          
Put *
    
1,500
    
-
  
$
35.10
    
-
  
April 1, 2005 - December 31, 2005
                          
3-way option
    
1,500
  
$
30.00
  
$
27.23
  
$
23.00
  
3-way option
    
1,500
  
$
30.00
  
$
25.35
  
$
22.00
  
Costless Collar *
    
1,500
  
$
40.10
  
$
31.00
    
-
  
Put*(1)
    
1,500
    
-
  
$
41.50
    
-
  
Put (1)
    
1,500
    
-
    
-
  
$
35.00
  
October 1, 2005 - December 31, 2005
                          
Put *
    
1,500
    
-
  
$
34.25
    
-
  
July 1, 2005 - June 30, 2006
                          
3-way option
   
1,500
  
$
45.80
  
$
31.50
  
$
27.50
  
Put*(1)
    
1,500
    
-
  
$
41.50
    
-
  
Put (1)
    
1,500
    
-
    
-
  
$
35.00
  
January 1, 2006 - June 30, 2006
                          
Costless Collar *
    
1,500
  
$
35.35
  
$
30.00
    
-
  
Costless Collar *
    
1,500
  
$
37.00
  
$
30.00
    
-
  
* Financial contracts that qualify as hedges. 
(1) Financial contracts entered into during the first quarter of 2005.
 
Page 24

Natural Gas Instruments

Enerplus has physical and financial contracts in place on its natural gas production as described below. The fair value of the financial natural gas contracts that do not qualify for hedge accounting at March 31, 2005 is described in Note 2. The fair value of the financial natural gas contracts that qualify for hedge accounting reflects an unrealized cost of $39,950,000 at March 31, 2005.

The following table summarizes the Fund’s natural gas risk management positions at April 22, 2005:
 
           
       
AECO CDN$/Mcf
 
Term
  
Daily Volumes MMcf/day
  
Sold Call
  
Purchased
Put
  
Sold
Put
  
Fixed Price and Swaps
  
May 1, 2005 - May 31, 2005
                                
Call(1) 
    
9.5
  
$
7.54
    
-
    
-
    
-
  
April 1, 2005 - June 30, 2005
                                
3-way option
    
2.8
  
$
7.12
  
$
5.69
  
$
4.75
    
-
  
Call(1) 
    
9.5
  
$
7.60
    
-
    
-
    
-
  
April 1, 2005 - October 31, 2005
                                
3-way option
   
9.5
  
$
8.23
  
$
6.33
  
$
5.01
    
-
  
Costless Collar *(1)
    
4.8
  
$
8.44
  
$
5.54
    
-
    
-
  
Costless Collar *(1)
    
4.8
  
$
8.44
  
$
5.80
    
-
    
-
  
Put*(1)
    
9.5
    
-
  
$
6.33
    
-
    
-
  
April 1, 2005 - December 31, 2005
                                
3-way option
    
9.5
  
$
6.65
  
$
5.61
  
$
4.75
    
-
  
3-way option
    
9.5
  
$
6.60
  
$
5.65
  
$
4.75
    
-
  
3-way option
    
9.5
  
$
6.86
  
$
5.81
  
$
4.75
    
-
  
Put *
    
9.5
    
-
  
$
6.39
    
-
    
-
  
November 1, 2005 - March 31, 2006
                                
3-way option
   
9.5
  
$
9.92
  
$
7.12
  
$
5.80
    
-
  
April 1, 2005 - October 31, 2006
                                
Swap *
    
9.5
    
-
    
-
    
-
  
$
5.47
  
Swap *
    
4.8
    
-
    
-
    
-
  
$
5.25
  
Swap *
    
4.8
    
-
    
-
    
-
  
$
5.24
  
Swap *
    
4.8
    
-
    
-
    
-
  
$
5.28
  
2005 - 2010
                                
Physical (escalated pricing)
    
2.0
    
-
    
-
    
-
  
$
2.52
  
* Financial contracts that qualify as hedges. 
(1) Financial contracts entered into during the first quarter of 2005.
 
Electricity Instrument

The Fund has entered into an electricity swap contract that has fixed the price of electricity on 5MWh of Alberta Power Pool electricity consumption at $49.99/MWh from January 1, 2005 to December 31, 2006. This has been designated as a hedge and the fair value of this instrument as at March 31, 2005 reflects an unrealized gain of $386,000.
 
Page 25
 
BOARD OF DIRECTORS

Douglas R. Martin  (1)(2)
President
Charles Avenue Capital Corp.
Calgary, Alberta

Edwin Dodge (3)(9)(11)
Corporate Director
Calgary, Alberta

Gordon J. Kerr 
President & Chief Executive Officer
EnerMark Inc.
Calgary, Alberta

Robert L. Normand (6)(9)
Corporate Director
Rosemere, Québec

Glen D. Roane (5)(10)
Corporate Director
Canmore, Alberta

Donald T. West (7)(12)
Corporate Director
Calgary, Alberta

Harry B. Wheeler (5)(8)
President
Colchester Investments Ltd.
Calgary, Alberta

Robert L. Zorich (4)(11)
Managing Director
EnCap Investments L.P.
Houston, Texas

(1)
Chairman of the Board
(2)
Ex-Officio member of all Committees of the Board
(3)
Member of the Corporate Governance and Nominating Committee
(4)
Chairman of the Corporate Governance and Nominating Committee
(5)
Member of the Audit and Risk Management Committee
(6)
Chairman of the Audit and Risk Management Committee
(7)
Member of the Reserves Committee
(8)
Chairman of the Reserves Committee
(9)
Member of the Compensation and Human Resources Committee
(10)
Chairman of the Compensation and Human Resources Committee
(11)
Member of the Environment, Health and Safety Committee
(12)
Chairman of the Environment, Health and Safety Committee

OFFICERS

Gordon J. Kerr
President & Chief Executive Officer

Heather J. Culbert
Senior Vice President, Corporate Services

Ian C. Dundas
Senior Vice President, Business Development

Page 26
 
Garry A. Tanner
Senior Vice President & Chief Operating Officer

Eric P. Tremblay
Senior Vice President, Capital Markets

Robert J. Waters
Senior Vice President & Chief Financial Officer

Jo-Anne M. Caza
Vice President, Investor Relations

Daryl W. Cook
Vice President, Operations

Rodney D. Gray
Vice President, Finance

David A. McCoy
Vice President, General Counsel & Corporate Secretary

Daniel M. Stevens
Vice President, Development Services

Wayne G. Ford
Controller, Operations

Christina Meeuwsen
Assistant Corporate Secretary

CORPORATE INFORMATION


OPERATING COMPANIES OWNED BY ENERPLUS RESOURCES FUND

EnerMark Inc.
Enerplus Resources Corporation
Enerplus Oil & Gas Ltd.
Enerplus Commercial Trust


LEGAL COUNSEL

Blake, Cassels & Graydon LLP
Calgary, Alberta

AUDITORS

Deloitte & Touche LLP
Calgary, Alberta


TRANSFER AGENT

CIBC Mellon Trust Company
Calgary, Alberta
Toll free: 1-800-387-0825
Email: inquiries@cibcmellon.com
 
Page 27

CO-TRANSFER AGENT

Mellon Investor Services L.L.C.
Ridgefield, New Jersey


INDEPENDENT RESERVE ENGINEERS

Sproule Associates Limited
Calgary, Alberta

Gilbert Laustsen Jung Associates Ltd.
Calgary, Alberta

STOCK EXCHANGE LISTINGS AND TRADING SYMBOLS

New York Stock Exchange: ERF
Toronto Stock Exchange: ERF.un


DISTRIBUTION REINVESTMENT AND UNIT PURCHASE PLAN

Enerplus Resources Fund offers a convenient method for Canadian residents to reinvest cash distributions or invest additional funds into new trust units with the Distribution Reinvestment and Unit Purchase Plan (“the Plan”).
 
Benefits of the Plan include:
·
Existing unitholders can purchase new units of the Fund each month by automatically reinvesting cash distributions.
·
Participants receive a 5% discount off the purchase price when reinvesting cash distributions.
·
Current unitholders can also make optional cash payments each month to purchase additional units. The optional cash payments can be a minimum of $250 up to a maximum of $5,000, or the amount of cash distributions received each month.
·
No commissions, service charges or brokerage fees are payable in conjunction with the Plan.

If your units are held through a broker, investment dealer or other financial intermediary, you must direct that company to enroll your units into the Plan.

To obtain more information, please contact our Investor Relations Department at 1-800-319-6462, in Calgary at (403) 298-2200; by fax at (403) 298-2211; or by email at investorrelations@enerplus.com. Information on the Plan is also available on our website at www.enerplus.com.


ABBREVIATIONS
 
AECO
Alberta Energy Company interconnect with the Nova Gas System, the Canadian benchmark for natural gas pricing purposes
bbl(s)/day
barrel(s) per day, with each barrel representing 34.972 Imperial gallons or 42 U.S. gallons
BOE(s)/day
barrel of oil equivalent per day (6 Mcf of gas:1 BOE)
CBM
coalbed methane, otherwise known as natural gas from coal - NGC
GAAP
Generally accepted accounting principles
Mbbls
thousand barrels
MBOE
thousand barrels of oil equivalent
Mcf/day
thousand cubic feet per day
MMbbl(s)
million barrels
MMBOE
million barrels of oil equivalent
MMBtu
million British Thermal Units
MMcf/day
million cubic feet per day
MWh
Megawatt hour(s) of electricity
NGLs
natural gas liquids
NYSE
New York Stock Exchange
SAGD
steam assisted gravity drainage
SEDAR
System for Electronic Document Analysis and Retrieval
TSX
Toronto Stock Exchange
WI
percentage working interest ownership
WTI
West Texas Intermediate oil at Cushing, Oklahoma, the benchmark for North American crude oil pricing purposes
 
Page 28

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

Page 29