-
On June 21, Enerplus Resources Fund merged
with EnerMark Income Fund to create North
America’s largest conventional oil and gas
income fund
-
Enerplus realized the highest return in the
Canadian conventional oil and gas income
fund sector, a 34% total return for its
Unitholders
-
EnerMark Unitholders realized a 22% total
return for the year
-
Enerplus completed the most active
development drilling program in its history,
drilling approximately 350 net wells with a
99% success rate
-
The Fund’s commodity price risk
management program generated over
$50 million in net proceeds to the Fund
2001 Cash Distribution per Unit
 |
Production
Month |
Payment
Month |
Pre-Merger
Enermark (CDN$) |
Pre-Merger
Enerplus (CDN$) |
Post-Merger
Enerplus (CDN$) |
Enerplus (US$) |
|
| January |
March |
$ 0.09 |
$ 0.45 |
$ - |
$ 0.29 |
| February |
April |
0.09 |
0.45 |
- |
0.29 |
| March |
May |
0.17 |
0.90 |
- |
0.58 |
| April |
June |
0.09 |
0.52 |
- |
0.34 |
| May |
July |
- |
- |
0.48 |
0.31 |
| June |
August |
- |
- |
0.50 |
0.32 |
| July |
September |
- |
- |
0.45 |
0.29 |
| August |
October |
- |
- |
0.40 |
0.25 |
| September |
November |
- |
- |
0.40 |
0.25 |
| October |
December |
- |
- |
0.35 |
0.22 |
| November |
January, 2002 |
- |
- |
0.30 |
0.19 |
| December |
February, 2002 |
- |
- |
0.25 |
0.16 |
|
2001 Selected Combined Results
The information contained in the table below reflects the combined results of Enerplus Resources Fund and
EnerMark Income Fund for the years indicated as if the combination of the Funds had been effective at
January 1, 1997. This information may not be representative of the actual results had the combination occurred on
that date. No pro forma adjustments have been made to give effect to the combination of Enerplus and EnerMark
for these periods. The information in this table is different from the financial statements and MD&A which account
for the combination as a reverse takeover of Enerplus by EnerMark on June 21, 2001 as required by Canadian
generally accepted accounting principles.
|
| For the year ended December 31, |
2001 |
2000 |
|
| Operating |
|
|
| Average Daily Volumes |
|
|
| Crude oil (bbls/day) |
24,010 |
18,118 |
| NGLs (bbls/day) |
4,650 |
3,395 |
| Natural gas (Mcf/day) |
203,727 |
149,616 |
| Total (BOE/day) (6:1) |
62,615 |
46,449 |
| % natural gas |
54% |
54% |
| Reserve Life Index (years) |
14.0 |
13.7 |
|
| |
CDN$ |
US$ |
|
| |
2001 |
2000 |
2001 |
2000 |
|
| Average Selling Price Pre-Hedging |
|
|
|
|
| Crude oil (per bbl) |
$ 31.09 |
$ 37.08 |
$ 20.08 |
$ 24.98 |
| NGLs (per bbl) |
32.09 |
33.13 |
20.72 |
22.31 |
| Natural gas (per Mcf) |
5.22 |
4.60 |
3.37 |
3.10 |
| Currency exchange rate (CDN$ to US$) |
$ 0.6458 |
$ 0.6736 |
$ 0.6458 |
$ 0.6736 |
| Financial (combined basis, unaudited) ($000) |
|
|
|
|
| Oil and gas sales before hedging |
$ 713,933 |
$ 540,344 |
$ 461,058 |
$ 363,974 |
| Proceeds (cost) of hedging |
47,789 |
(15,894) |
30,862 |
(10,706) |
| Royalties, net of ARTC |
158,760 |
116,505 |
102,527 |
78,478 |
| Operating Costs |
138,218 |
86,295 |
89,261 |
58,128 |
| Netback |
464,744 |
321,650 |
300,132 |
216,662 |
| General and administrative |
14,940 |
10,787 |
9,649 |
7,266 |
| Management fees |
12,066 |
8,576 |
7,792 |
5,777 |
| Interest expense net |
19,287 |
20,324 |
12,456 |
13,690 |
| Capital taxes |
5,248 |
3,836 |
3,389 |
2,583 |
| Restoration and abandonment cash costs |
3,261 |
2,782 |
2,106 |
1,874 |
| Funds flow from operations |
409,942 |
275,345 |
264,740 |
185,472 |
| Cash withheld for debt reduction |
$ 56,100 |
$ 18,046 |
$ 36,229 |
$ 12,156 |
| Debt/funds flow ratio |
1.0x |
1.5x |
1.0x |
1.5x |
|
Number of Units outstanding at December 31, 2001 is 69.5 million and at December 31, 2000 is
40.9 million. 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. |
|
