|
|
 |
5 year detailed statistical review
The information contained in the table below reflects the reverse takeover
of Enerplus by EnerMark Income Fund on June 21, 2001 as required by Canadian
generally accepted accounting principles.
($ thousands, except per unit amount) |
2004 |
2003 |
2002 |
2001 |
2000 |
financial |
|
(restated) |
(restated) |
(restated) |
(restated) |
Oil and gas sales (1) |
$989,266 |
$890,011 |
$621,450 |
$639,379 |
$343,182 |
Cash available for distribution |
$426,721 |
$379,055 |
$246,787 |
$316,454 |
$168,181 |
Per unit |
$4.20 |
$4.32 |
$3.32 |
$5.67 |
$5.49 |
Net income |
$262,942 |
$248,046 |
$116,621 |
$181,454 |
$82,139 |
Per unit |
$2.65 |
$2.88 |
$1.62 |
$3.30 |
$3.06 |
Total net capital expenditures |
$813,636 |
$312,073 |
$361,702 |
$874,420 |
$700,714 |
Total assets |
$3,180,748 |
$2,661,765 |
$2,517,976 |
$2,330,639 |
$1,589,622 |
Long-term debt, net of cash |
$584,991 |
$257,701 |
$361,011 |
$411,610 |
$275,098 |
Net debt/funds flow ratio |
1.1x |
0.6x |
1.2x |
1.2x |
1.6x |
|
|
|
|
|
|
|
|
|
|
|
|
AVERAGE BENCHMARK PRICING |
|
|
|
|
|
AECO natural gas (per Mcf) |
$6.79 |
$6.70 |
$4.07 |
$6.30 |
$5.02 |
NYMEX natural gas (US$ per Mcf) |
6.09 |
5.54 |
3.25 |
4.38 |
3.91 |
WTI crude oil (US$ per bbl) |
41.40 |
31.04 |
26.08 |
25.97 |
30.19 |
CDN$/US$ exchange rate |
$0.7685 |
$0.7158 |
$0.6369 |
$0.6458 |
$0.6736 |
($ per BOE except percentage data) |
|
|
|
|
|
OIL AND GAS ECONOMICS |
|
|
|
|
|
Net royalty rate |
21% |
20% |
21% |
23% |
23% |
Weighted average price (2) |
$40.90 |
$36.94 |
$27.49 |
$29.89 |
$30.94 |
Hedging (3) |
(3.50) |
(1.81) |
(0.38) |
2.54 |
(0.80) |
Weighted average price (1) |
37.40 |
35.13 |
27.11 |
32.43 |
30.14 |
Net royalty expense |
8.40 |
7.51 |
5.75 |
6.73 |
7.10 |
Operating expense |
7.14 |
6.73 |
5.86 |
6.09 |
4.83 |
Operating netback |
21.86 |
20.89 |
15.50 |
19.61 |
18.21 |
General and administrative expense (3) |
1.06 |
0.95 |
0.70 |
0.66 |
0.63 |
Management fee |
- |
2.29 |
0.94 |
0.47 |
0.40 |
Interest expense, net of interest and
other income |
0.68 |
0.74 |
0.78 |
0.85 |
1.30 |
Foreign exchange (3) |
(0.01) |
0.08 |
- |
- |
- |
Capital taxes |
0.24 |
0.26 |
0.23 |
0.24 |
0.26 |
Restoration and abandonment
cash costs |
0.25 |
0.26 |
0.20 |
0.13 |
0.13 |
Gain on sale of investment |
- |
- |
- |
- |
- |
Funds flow from operations |
$19.64 |
$16.31 |
$12.65 |
$17.26 |
$15.49 |
(1) Net of hedging and transportation
(2) Net of transportation and before hedging
(3) Does not include non-cash portion of expense
combined operational statistics
The information contained in the table below reflects the combined results
of Enerplus and EnerMark Income Fund for the years indicated as if the combination
of the funds had been effective January 1, 2000. 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 Income Fund for 2000 and 2001.
|
2004 (1) |
2003 (1) |
2002 |
2001 |
2000 |
|
|
|
|
|
|
Daily Production |
|
|
|
|
|
Crude oil per day (bbls/day) |
25,550 |
24,597 |
23,288 |
24,010 |
18,118 |
NGLs per day (bbls/day) |
4,398 |
4,666 |
4,410 |
4,650 |
3,395 |
Natural Gas per day (Mcf/day) |
271,091 |
240,907 |
210,517 |
203,727 |
149,616 |
BOE per day |
75,130 |
69,414 |
62,784 |
62,615 |
46,449 |
|
|
|
|
|
|
Proved Reserves |
|
|
|
|
|
Crude oil (Mbbls) |
104,408 |
91,063 |
105,247 |
94,847 |
101,439 |
NGLs (Mbbls) |
12,776 |
13,571 |
16,035 |
16,114 |
16,973 |
Natural Gas (MMcf) |
971,598 |
867,204 |
1,001,913 |
951,133 |
954,124 |
MBOE |
279,117 |
249,168 |
288,267 |
269,483 |
277,433 |
Probable Reserves (2) |
|
|
|
|
|
Crude oil (Mbbls) |
74,530 |
27,807 |
16,725 |
18,821 |
20,675 |
NGLs (Mbbls) |
3,292 |
3,742 |
2,319 |
2,337 |
1,722 |
Natural Gas (MMcf) |
295,698 |
284,096 |
138,789 |
130,345 |
131,818 |
MBOE |
127,105 |
78,898 |
42,175 |
42,882 |
44,367 |
Proved plus Probable Reserves |
|
|
|
|
|
Crude oil (Mbbls) |
178,938 |
118,870 |
121,972 |
113,668 |
122,114 |
NGLs (Mbbls) |
16,068 |
17,313 |
18,354 |
18,451 |
18,695 |
Natural Gas (MMcf) |
1,267,296 |
1,151,300 |
1,140,702 |
1,081,478 |
1,085,942 |
MBOE |
406,222 |
328,066 |
330,442 |
312,365 |
321,800 |
Reserve Life Index (3) |
|
|
|
|
|
Proved (years) |
10.1 |
10.6 |
12.0 |
12.1 |
11.9 |
Proved plus probable (years) |
14.0 |
13.3 |
13.8 |
14.0 |
13.7 |
(1) 2004 & 2003 reserve information reflects NI
51-101 reporting methodology. All prior years have not been restated for
NI 51-101.
(2) Probable reserves for years 2002 and prior have
been risked by 50%.
(3) The Reserve Life Indices (RLIs) are based upon year-end
proved plus probable reserves (established reserves for years 2002 and prior)
divided by following year's proved and proved plus probable production volumes
determined in the independent reserve engineering report for 2003 forward
and management's estimate for all prior years.
SUPPLEMENTARY RESERVE INFORMATION
The following information has been prepared in accordance with National
Instrument 51-101 and is derived from the independent engineering evaluations
prepared by Sproule Associates Limited and Gilbert Laustsen Jung Associates
Ltd. Using forecast prices. Our reserve statement, which includes
complete disclosure of our oil and gas reserves and other oil and gas information
in accordance with NI 51-101, as contained within our Annual Information
Form will be available on our website at www.enerplus.com and
on our SEDAR profile at www.sedar.com prior
to
March 31, 2005. Additionally, the Annual Information Form will be part
of our Form 40-F that will be filed with the SEC and available on www.edgar.com prior
to March 31, 2005.
|
OIL AND GAS RESERVES |
|
Light And Medium Oil |
Heavy Oil |
Bitumen |
| RESERVES CATEGORY |
Company Interest (Mbbls) |
Gross (Mbbls) |
Net (Mbbls) |
Company Interest (Mbbls) |
Gross (Mbbls) |
Net (Mbbls) |
Company Interest (Mbbls) |
Gross (Mbbls) |
Net
(Mbbls) |
|
|
|
|
|
|
|
|
|
|
Proved Reserves |
|
|
|
|
|
|
|
|
|
Proved Developed
Producing |
70,078 |
69,410 |
63,755 |
28,274 |
28,232 |
24,358 |
- |
- |
- |
Proved Developed
Non-Producing |
104 |
104 |
96 |
66 |
65 |
53 |
- |
- |
- |
Proved Undeveloped |
2,857 |
2,818 |
2,421 |
3,029 |
3,029 |
2,560 |
- |
- |
- |
Total Proved Reserves |
73,039 |
72,332 |
66,272 |
31,369 |
31,326 |
26,971 |
- |
- |
- |
Probable Reserves |
17,180 |
16,936 |
14,892 |
9,603 |
9,596 |
8,264 |
47,747 |
47,747 |
43,640 |
Total Proved plus Probable Reserves |
90,219 |
89,268 |
81,164 |
40,972 |
40,922 |
35,235 |
47,747 |
47,747 |
43,640 |
Net Reserve Reconciliation
The following tables reconcile the reported volumes of net reserves from
December 31, 2003 to December 31, 2004 and highlight which production type
and reserves categories contributed to the change.
Proved Reserves
- Net Volumes (forecast prices) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
light &
medium oil
(Mbbls) |
heavy oil
(Mbbls) |
bitumen (Mbbls) |
total oil
(Mbbls) |
natural gas
liquids
(Mbbls) |
natural
gas
(Bcf) |
total
(MBOE) |
Proved Reserves at Dec. 31, 2003 |
59,748 |
21,857 |
- |
81,605 |
9,464 |
684.1 |
205,086 |
Acquisitions |
8,662 |
1,754 |
- |
10,416 |
364 |
79.2 |
23,980 |
Divestments |
(20) |
(130) |
- |
(150) |
(9) |
(2.0) |
(492) |
Discoveries |
292 |
- |
- |
292 |
31 |
0.7 |
440 |
Extensions |
150 |
(518) |
- |
(368) |
126 |
12.5 |
1,841 |
Technical Revisions |
1,157 |
6,027 |
- |
7,184 |
(11) |
13.0 |
9,335 |
Economic Factors |
452 |
143 |
- |
595 |
36 |
2.8 |
1,098 |
Improved Recovery |
1,126 |
241 |
- |
1,367 |
144 |
65.7 |
12,461 |
Production |
(5,295) |
(2,403) |
- |
(7,698) |
(1,203) |
(77.4) |
(21,796) |
Proved Reserves at Dec. 31,
2004 |
66,272 |
26,971 |
- |
93,243 |
8,942 |
778.6 |
231,953 |
Probable
Reserves - Net Volumes (forecast prices) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
light &
medium oil
(Mbbls) |
heavy oil
(Mbbls) |
bitumen (Mbbls) |
total oil
(Mbbls) |
natural gas
liquids
(Mbbls) |
natural
gas
(Bcf) |
total
(MBOE) |
Probable Reserves at Dec. 31, 2003 |
17,696 |
6,474 |
- |
24,170 |
2,624 |
229.5 |
65,044 |
Acquisitions |
6,995 |
941 |
- |
7,936 |
199 |
68.9 |
19,618 |
Divestments |
(19) |
(235) |
- |
(254) |
(11) |
(2.0) |
(596) |
Discoveries |
62 |
- |
- |
62 |
11 |
0.3 |
123 |
Extensions |
689 |
(164) |
43,640 |
44,165 |
44 |
0.8 |
44,342 |
Technical Revisions |
(10,795) |
1,183 |
- |
(9,612) |
(559) |
(66.1) |
(21,187) |
Economic Factors |
104 |
26 |
- |
130 |
(24) |
0.6 |
206 |
Improved Recovery |
160 |
39 |
- |
199 |
34 |
11.2 |
2,099 |
Production |
- |
- |
- |
- |
- |
- |
- |
Probable Reserves at Dec. 31,
2004 |
14,892 |
8,264 |
43,640 |
66,796 |
2,318 |
243.2 |
109,649 |
Proved Plus Probable
Reserves - Net Volumes (forecast prices) |
|
|
|
|
|
|
|
|
|
|
|
light & medium oil (Mbbls) |
heavy oil (Mbbls) |
bitumen (Mbbls) |
total oil (Mbbls) |
natural gas liquids (Mbbls) |
natural gas (Bcf) |
Total (MBOE) |
Proved Plus Probable Reserves at Dec.
31, 2003 |
77,444 |
28,331 |
- |
105,775 |
12,088 |
913.6 |
270,130 |
Acquisitions |
15,657 |
2,695 |
- |
18,352 |
563 |
148.1 |
43,598 |
Divestments |
(39) |
(365) |
- |
(404) |
(20) |
(4.0) |
(1,088) |
Discoveries |
354 |
- |
- |
354 |
42 |
1.0 |
563 |
Extensions |
839 |
(682) |
43,640 |
43,797 |
170 |
13.3 |
46,183 |
Technical Revisions |
(9,638) |
7,210 |
- |
(2,428) |
(570) |
(53.1) |
(11,852) |
Economic Factors |
556 |
169 |
- |
725 |
12 |
3.4 |
1,304 |
Improved Recovery |
1,286 |
280 |
- |
1,566 |
178 |
76.9 |
14,560 |
Production |
(5,295) |
(2,403) |
- |
(7,698) |
(1,203) |
(77.4) |
(21,796) |
Proved Plus Probable Reserves
at Dec. 31, 2004 |
81,164 |
35,235 |
43,640 |
160,039 |
11,260 |
1,021.8 |
341,602 |
2004 INCOME TAX INFORMATION
Information for Canadian residents (CDN$ per Unit)
The following table outlines the breakdown of cash distributions per unit
and per subscription receipt paid by Enerplus Resources Fund for the period
February 20, 2004 to January 20, 2005 for Canadian Income Tax purposes.
Record Date |
Payment Date |
Total Distribution Paid |
Taxable Other
Income |
Taxable Dividend |
Return of Capital
Amount |
|
|
|
|
|
|
Feb 10, 2004 |
Feb 20, 2004 |
$0.350000 |
$0.306098 |
$0.008433 |
$0.035469 |
Mar 10, 2004 |
Mar 20, 2004 |
$0.350000 |
$0.306103 |
$0.008429 |
$0.035468 |
Apr 10, 2004 |
Apr 20, 2004 |
$0.350000 |
$0.306118 |
$0.008414 |
$0.035468 |
May 10, 2004 |
May 20, 2004 |
$0.350000 |
$0.306120 |
$0.008412 |
$0.035468 |
Jun 10, 2004 |
Jun 20, 2004 |
$0.350000 |
$0.306125 |
$0.008407 |
$0.035468 |
Jul 10, 2004 |
Jul 20, 2004 |
$0.350000 |
$0.306849 |
$0.007683 |
$0.035468 |
Aug 10, 2004 |
Aug 20, 2004 |
$0.350000 |
$0.306851 |
$0.007681 |
$0.035468 |
Sep 10, 2004 |
Sep 20, 2004 |
$0.350000 |
$0.306855 |
$0.007677 |
$0.035468 |
Oct 10, 2004 |
Oct 20, 2004 |
$0.350000 |
$0.306861 |
$0.007671 |
$0.035468 |
Nov 10, 2004 |
Nov 20, 2004 |
$0.350000 |
$0.306866 |
$0.007666 |
$0.035468 |
Dec 10, 2004 |
Dec 20, 2004 |
$0.350000 |
$0.306870 |
$0.007662 |
$0.035468 |
Dec 31, 2004 |
Jan 20, 2005 |
$0.350000 |
$0.306877 |
$0.007654 |
$0.035469 |
|
|
|
|
|
|
TOTAL PER UNIT |
$4.200000 |
$3.678593 |
$0.095789 |
$0.425618 |
|
|
|
|
|
|
PER SUBSCRIPTION
RECEIPT |
$0.350000 |
$0.350000 |
- |
- |
Income Tax - United States Residents (US$ per Unit)
The following table outlines the breakdown of cash distributions per unit,
prior to any amounts deducted for Canadian withholding tax, paid by Enerplus
Resources Fund for the period January 20, 2004 to December 20, 2004 for units
held through a broker or other intermediary. The amounts shown on
the schedule are in U.S. dollars as converted on the applicable payment dates.
Record Date |
Payment Date |
Distribution Paid
CDN$ |
Exchange
Rate |
Distribution Paid
US$ |
Taxable
Qualified Dividend US$ |
Non-Taxable Return
of Capital US$ |
|
|
|
|
|
|
|
|
|
Dec 31, 2003 |
Jan 20, 2004 |
$0.35 |
0.769823 |
$0.269438 |
$0.253542 |
$0.015896 |
|
Feb 10, 2004 |
Feb 20, 2004 |
$0.35 |
0.740192 |
$0.259067 |
$0.243783 |
$0.015284 |
|
Mar 10, 2004 |
Mar 20, 2004 |
$0.35 |
0.751597 |
$0.263059 |
$0.247540 |
$0.015519 |
|
Apr 10, 2004 |
Apr 20, 2004 |
$0.35 |
0.736377 |
$0.257732 |
$0.242527 |
$0.015205 |
|
May 10, 2004 |
May 20, 2004 |
$0.35 |
0.725005 |
$0.253752 |
$0.238782 |
$0.014970 |
|
Jun 10, 2004 |
Jun 20, 2004 |
$0.35 |
0.731368 |
$0.255979 |
$0.240877 |
$0.015102 |
|
Jul 10, 2004 |
Jul 20, 2004 |
$0.35 |
0.759417 |
$0.265796 |
$0.250115 |
$0.015681 |
|
Aug 10, 2004 |
Aug 20, 2004 |
$0.35 |
0.768935 |
$0.269127 |
$0.253250 |
$0.015877 |
|
Sep 10, 2004 |
Sep 20, 2004 |
$0.35 |
0.768108 |
$0.268838 |
$0.252978 |
$0.015860 |
|
Oct 10, 2004 |
Oct 20, 2004 |
$0.35 |
0.800448 |
$0.280157 |
$0.263629 |
$0.016528 |
|
Nov 10, 2004 |
Nov 20, 2004 |
$0.35 |
0.838926 |
$0.293624 |
$0.276301 |
$0.017323 |
|
Dec 10, 2004 |
Dec 20, 2004 |
$0.35 |
0.811886 |
$0.284160 |
$0.267396 |
$0.016764 |
|
|
|
|
|
|
|
|
|
TOTAL PER UNIT |
$4.20 |
|
$3.220729 |
$3.030720 |
$0.190009 |
|
|
ABBREVIATIONS
| AECO | Alberta Energy Company interconnect with the Nova Gas System, the Canadian benchmark for natural gas pricing purposes
| | API | American
Petroleum Institute
|
| ARTC | Alberta
Royalty Tax Credit
|
| bbl(s)/day | barrel(s)
per day, with each barrel representing 34.972 Imperial gallons or 42 U.S.
gallons |
| Bcf | billion
cubic feet
|
| 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
| COGPE Canadian
oil and gas property expense
| | CAPP | Canadian
Association of Petroleum Producers
| | EDGAR | Electronic
Data Gathering, Analysis and Retrieval system
| | Established Reserves | proved
plus half probable reserves applicable to years 2002 and prior
| | FD&A Costs | finding,
development and acquisition costs
| | GLJ | Gilbert
Laustsen Jung Associates Ltd., an external, independent third party engineering
firm
| | IP Rate | initial
production rate
| | 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
| | NGC | natural
gas from coal, otherwise known as coalbed methane - CBM
| | NGLs | natural
gas liquids
| | NI 51-101 | National
Instrument 51-101 (pertaining to reserve reporting in Canada)
| | NYSE | New
York Stock Exchange
| | OECD | Organization
for Economic Cooperation and Development
| | P+P Reserves | proved
plus probable reserves
| | PDP Reserves | proved
developed producing reserves
| | RLI | reserve
life index
| | SAGD | steam
assisted gravity drainage
| | TSX | Toronto
Stock Exchange
| | W.I. | percentage
working interest ownership
| | WTI | West
Texas Intermediate oil at Cushing, Oklahoma, the benchmark for North American
crude oil pricing purposes
| | SEDAR | System
for Electronic Document Analysis and Retrieval
| | Sproule | Sproule
Associates Limited, an external, independent third party engineering firm
DEFINITIONS
| | Bitumen | A
highly viscous oil which is too thick to flow in its native state and which
cannot be produced without altering its viscosity. The density of bitumen
is generally less than 10 degrees API.
| | BOE | Barrels
of oil equivalent converting 6 Mcf of natural gas to one barrel of oil equivalent
and one barrel of natural gas liquids to one barrel of oil equivalent. The
factor used to convert natural gas and natural gas liquids to oil equivalent
is not based on either energy content or prices but is a commonly used industry
benchmark. BOEs may be misleading, particularly if used in isolation. A BOE
conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
| | CO 2 | Carbon
dioxide, a colorless, non-toxic odourless gas composed of one carbon atom
and two oxygen atoms.
| | FD&A Costs | Finding,
development and acquisition costs. Calculated as total capital expenditures
and net acquisitions, including changes in future development capital, divided
by reserve additions (proved and/or proved plus probable). It is a measure
of a company's ability to add reserves in a cost effective manner.
| | Light & Medium Oil | Oil
that has a density of 22.3 degrees API or higher.
| | Heavy Oil | Oil
with a density between 10 to 22.3 degrees API, or where a royalty regime
exists specific to heavy oil, it is defined based upon that royalty regime.
| | Operating Income | Calculated
as revenues from oil and gas sales less cash hedging costs, transportation
costs, royalties and operating costs.
| | NGLs | Natural
gas liquids - hydrocarbon components that can be recovered from natural gas
as liquids, including, but not limited to, ethane, propane, butanes, pentanes
plus, condensate and small quantities of non-hydrocarbons.
| | Production per Debt-Adjusted Unit | Production
per unit is measured in respect of the average production for the year, and
the weighted average number of trust units outstanding during the year. The
measurements are then debt-adjusted by assuming additional trust units are
issued at quarter-end unit prices to replace long-term debt outstanding at
each quarter-end. The average number of trust units created over the four
quarters is then added to the weighted average number of trust units to obtain
the debt-adjusted number of trust units for the year.
| | Proved plus Probable
Reserve Life Index | Calculated
as proved plus probable reserves at year-end (established reserves for years
2002 and prior) divided by the following year's proved plus probable production
volumes as determined by the independent reserve engineering report for 2003
and forward, and management's estimate for all prior years.
| | Proved
Reserve Life Index | Calculated
as proved reserves at year-end divided by the following year's proved production
volumes as determined by the independent reserve engineering report for 2003
and forward, and management's estimate for all prior years.
| | Recycle Ratio | Calculated
as operating income per BOE divided by FD&A costs per BOE. It is an indication
of the value creation of each dollar invested.
| Reserves per
Debt-Adjusted Unit | Reserves
per trust unit are measured in respect of year-end proved plus probable reserves
and the number of trust units outstanding at year-end. To eliminate the temporary
timing effects of financing decisions, we have debt-adjusted these measurements
by assuming we issue additional trust units at year-end prices to replace
year-end long-term debt.
| | Total Return | Calculated
using the change in the trust unit price at the start of the period (including
any capital appreciation or depreciation) and the total cash distributions
paid during the period divided by the starting unit price.
| | Gross Reserves | Our
working interest (operated and non-operated) share of reserves before the
deduction of any royalty interest reserves, but exclusive of royalty interest
reserves owned
by Enerplus.
| | Net Reserves | Our
working interest (operated and non-operated) share of reserves after the
deduction of royalty interest reserves, but inclusive of any royalty interest
reserves owned by Enerplus.
| | Company Interest
Reserves | Our
working interest (operated and non-operated) share of reserves before the
deduction of any royalty interest reserves, but inclusive of any royalty
interest reserves owned
by Enerplus.
| | Proved Reserves | Reserves
that can be estimated with a high degree of certainty to be recoverable in
accordance with NI 51-101. It is likely that the actual remaining quantities
recovered will exceed the estimated proved reserves.
| | Probable Reserves | Additional
reserves, calculated in accordance with NI 51-101, that are less certain
to be recovered than proved reserves. It is equally likely that the actual
remaining quantities recovered will be greater or less than the sum of the
estimated probable reserves.
| | Proved Developed
Producing Reserves | Reserves
that are expected to be recovered from completion intervals open at the time
of the estimate. These reserves may be currently producing or, if shut-in,
they must have previously been on production, and the date of resumption
of production must be known with reasonable certainty.
| | Proved Developed
Non-Producing
Reserves | Reserves
that either have not been on production or have previously been on production,
but are shut-in, and the date of resumption of production is unknown.
| Proved Undeveloped
Reserves | Reserves
expected to be recovered from known accumulations where a significant expenditure
(for example, when compared to the cost of drilling a well) is required to
render them capable of production. |
BOARD OF DIRECTORS
Douglas R. Martin (1)(2)(10)
President
Charles Avenue Capital Corp.
Calgary, Alberta
Edwin Dodge (3)(9)
Corporate Director
Calgary, Alberta
Derek Fortune (3)(9)(11)
Chairman, DF Consulting and Financial Services Inc.
Ottawa, Ontario
Gordon J. Kerr
President & Chief Executive Officer
EnerMark Inc.
Calgary, Alberta
Robert L. Normand (6)(9)
Corporate Director
Rosemere, Québec
Glen D. Roane (5)(7)
Corporate Director
Canmore, Alberta
Eric P. Tremblay
Senior Vice President, Capital Markets
EnerMark Inc.
Calgary, Alberta
Donald T. West (7)
Corporate Director
Calgary, Alberta
Harry B. Wheeler (5)(8)
President
Colchester Investments Ltd.
Calgary, Alberta
Robert L. Zorich (4)
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, Nominating and Environment, Health & Safety
Committee
(4) Chairman of the Corporate Governance, Nominating and Environment,
Health & Safety
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) Mr.
Fortune has retired from the Board effective February 1, 2005
OFFICERS
Gordon J. Kerr
President & Chief Executive Officer
Heather J. Culbert
Senior Vice President, Corporate Services
Ian C. Dundas
Senior Vice President, Business Development
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
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
HEAD OFFICE
The Dome Tower
3000, 333 - 7 th 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
Enerplus Internet Site
Enerplus Resources Fund has a comprehensive website that provides investors
with an immediate source of all public information. The following documents
are available at www.enerplus.com:
· Unit Trading Information
· Annual and Quarterly Reports
· Tax Information
· News Releases
· Recent Presentations
· 15 Minute Delayed Stock Quote
· Historical Distribution Tables
· Distribution Reinvestment
and Unit Purchase Plan Information
· Adjusted Cost Base Calculator
· Important Dates and Events
Annual General Meeting
Unitholders are encouraged to attend
the Annual General and Special Meeting being held on:
Tuesday, April 12, 2005
10:00 a.m., local time at
The Metropolitan Centre
333 - 4 th Avenue SW
Calgary, Alberta
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