diversity with longevity
Enerplus has consistently replaced its reserves year over year.
The mixture of commodities within our reserve base shows the diversity of our asset base.
Oil and Gas Reserves
YEAR OVER YEAR, PROVED PLUS PROBABLE RESERVES WERE ESSENTIALLY UNCHANGED VERSUS ESTABLISHED RESERVES LAST YEAR
Year-end 2003 reserves were evaluated in accordance with the newly introduced National Instrument 51-101 guidelines that were imposed by Canadian regulators earlier in the year. These guidelines are deemed to be more stringent and are intended to improve the consistency of reserve reports within the oil and gas sector. Enerplus’ year end proved plus probable reserves were essentially unchanged from the established reserves reported in the prior year, going from 330.4 MMBOE in 2002 to 328.1 MMBOE in 2003, down 0.7%. Proved reserves, however, were more adversely affected by the more stringent regulations going from 288.3 MMBOE in 2002 to 249.2 MMBOE in 2003, down 13.6%. A portion of the negative proved revisions can be attributed to the new 50-year cutoff rule, which has virtually no impact on the Fund’s production or net asset values.
Positive proved plus probable reserve revisions of 4.0 million BOE or 1.3% occurred as the effects of positive technical revisions exceeded the negative effects of NI 51-101. Proved reserve revisions were negative 31.0 MMBOE or 10.7%. Positive revisions associated with our development program of
10.9 MMBOE were more than offset by negative revisions of 41.9 MMBOE associated with NI 51-101.
NEW NI 51-101 RESERVE REPORTING RULES
Effective with the 2003 annual reporting cycle, Enerplus, and the majority of publicly traded Canadian oil and gas companies, are now subject to the Canadian reserve reporting requirement known as National Instrument 51-101. This new reporting requirement includes a number of rules and standards that were designed to improve consistency and reliability of Canadian public oil and gas reserve disclosures. The most significant changes associated with NI 51-101 include:
-
the introduction of a 50-year cutoff which eliminates any reserves expected to be produced after 50 years;
-
a more rigorous risking of probable reserves;
-
a more stringent definition of proved reserves; and
-
inclusion of future development costs when calculating finding and development costs.
While many fields produce much longer than 50 years, the 50-year cutoff was introduced to provide a consistent cutoff point in standardizing reserve reporting. This change impacts the reserve volumes for longer life entities, such as Enerplus, but does not have a material impact on current net asset values as these reserves have limited present value.
Another key change associated with NI 51-101 was the introduction of proved plus probable reserves (risked) to replace the previously used “established reserves” (proved plus half probable). Essentially each of these two definitions are designed to provide the most likely reserve estimate and we have used the two terms for comparison purposes throughout this report.
The third key change associated with NI 51-101 was a more conservative standard around reporting proved reserves. Traditionally, proved reserves represented a conservative estimate of the aggregate expected reserves. NI 51-101 introduced increased conservatism in an effort to limit potential negative proved reserve revisions. This higher standard has generally resulted in lower reported proved reserves across the Canadian industry this year.
The final major change requires future development capital to be included when calculating finding and development costs. Accordingly, we have included future development capital in our calculation of FD&A costs. This puts developed and undeveloped reserves on a more consistent basis for more meaningful comparisons across the industry.
RESERVE REPORTING
Given the new rules in place this year, comparisons to prior years are more difficult. To assist investors, we have provided disclosure that highlights reserve changes and associated metrics to allow comparisons year-over-year under the prior methodology (without NI 51-101) and with the new reporting rules (with NI 51-101). We have also adopted the practice of reporting proved plus probable reserves in 2003 whereas we previously reported established reserves. This type of reporting provides a clearer picture of reserve performance and changes during this transition year as the industry applies the new standards.
NI 51-101 has additional reporting requirements that provide more fulsome disclosure to investors and standardized the methods of calculating certain metrics. Additional information with regard to net reserves and constant prices will be contained in our Annual Information Form. All references to barrels of oil equivalent utilize a conversion rate of six Mcf of natural gas to one barrel of oil.
2003 RESERVE SUMMARY 2003 Reserve Summary - Gross Company Interest Volumes
| |
Light & Medium Oil
Mbbls |
Heavy Oil
Mbbls |
Total Oil
Mbbls |
Natural Gas Liquids
Mbbls |
Natural Gas
Bcf |
2003
Total
MBOE |
Proved developed producing |
74,558 |
11,301 |
85,859 |
11,846 |
737 |
220,605 |
Proved developed non-producing |
97 |
63 |
160 |
517 |
26 |
5,061 |
Proved Uudeveloped |
1,388 |
3,656 |
5,044 |
1,208 |
104 |
23,502 |
Total Proved Reserves |
76,043 |
15,020 |
91,063 |
13,571 |
867 |
249,168 |
Probable Reserves |
23,206 |
4,601 |
27,807 |
3,742 |
284 |
78,898 |
Total Proved Plus Probable Reserves |
99,249 |
19,621 |
118,870 |
17,313 |
1,151 |
328,066 |
RESERVE RECONCILIATION
Proved Reserves - Gross Company Interest
(forecast prices) |
Light & Medium
Oil
Mbbls |
Heavy
Oil
Mbbls |
Total
Oil
Mbbls |
Natural Gas
Liquids
Mbbls |
Natural
Gas
Bcf |
Total
MBOE |
Proved Reserves at Dec. 31, 2002 |
87,330 |
17,917 |
105,247 |
16,036 |
1,002 |
288,267 |
Acquisitions |
8,841 |
24 |
8,865 |
805 |
88 |
24,337 |
Divestments |
-5,226 |
-16 |
-5,242 |
-259 |
-10 |
-7,168 |
Extensions |
372 |
0 |
372 |
94 |
9 |
2,025 |
Technical Revisions excl. NI 51-101 |
6,738 |
607 |
7,345 |
12 |
2 |
7,647 |
Discoveries |
0 |
0 |
0 |
0 |
0 |
0 |
Economic Factors |
-517 |
408 |
-109 |
13 |
8 |
1,273 |
Improved Recovery |
0 |
0 |
0 |
0 |
0 |
0 |
Production |
-7,466 |
-1,512 |
-8,978 |
-1,703 |
-88 |
-25,336 |
Reserves at Dec. 31, 2003 excl. NI 51-101 |
90,072 |
17,428 |
107,500 |
14,998 |
1,011 |
291,045 |
NI 51-101 50 Year Cut-off |
-6,211 |
0 |
-6,211 |
-567 |
-18 |
-9,778 |
Other NI 51-101 Revisions |
-7,818 |
-2,408 |
-10,226 |
-860 |
-126 |
-32,099 |
Reserves at Dec. 31, 2003 incl. NI 51-101 |
76,043 |
15,020 |
91,063 |
13,571 |
867 |
249,168 |
Probable Reserves - Gross Company Interest (forecast prices)
| |
Light & Medium Oil
Mbbls |
Heavy
Oil
Mbbls |
Total
Oil
Mbbls |
Natural Gas
Liquids
Mbbls |
Natural
Gas
Bcf |
Total
MBOE |
Half Probable Reserves at Dec. 31, 2002 |
13,169 |
3,556 |
16,725 |
2,318 |
139 |
42,175 |
Acquisitions |
1,454 |
43 |
1,497 |
122 |
13 |
3,769 |
Divestments |
-1,485 |
-292 |
-1,777 |
-35 |
-1 |
-2,034 |
Extensions |
49 |
0 |
49 |
0 |
3 |
541 |
Technical Revisions - excl. NI 51-101 |
2,548 |
-99 |
2,449 |
4 |
0 |
2,549 |
Discoveries |
0 |
0 |
0 |
0 |
0 |
0 |
Economic Factors |
-824 |
233 |
-591 |
264 |
-3 |
-920 |
Improved Recovery |
1,092 |
0 |
1,092 |
0 |
0 |
1,092 |
Production |
0 |
0 |
0 |
0 |
0 |
0 |
Reserves at Dec. 31, 2003 excl. NI 51-101 |
16,003 |
3,441 |
19,444 |
2,673 |
151 |
47,172 |
NI 51-101 50 Year Cut-off |
-2,976 |
0 |
-2,976 |
-312 |
-22 |
-6,994 |
Other NI 51-101 Revisions |
10,179 |
1,160 |
11,339 |
1,381 |
155 |
38,720 |
Reserves at Dec. 31, 2003 incl. NI 51-101 |
23,206 |
4,601 |
27,807 |
3,742 |
284 |
78,898 |
Proved plus Probable Reserves - Gross Company (forecast prices)
| |
Light &
Medium Oil
Mbbls |
Heavy
Oil
Mbbls |
Total
Oil
Mbbls |
Natural Gas
Liquids
Mbbls |
Natural
Gas
Bcf |
Total
MBOE |
Estab. Reserves at Dec. 31, 2002 |
100,499 |
21,473 |
121,972 |
18,354 |
1,141 |
330,442 |
Acquisitions |
10,295 |
67 |
10,362 |
927 |
101 |
28,106 |
Divestments |
-6,711 |
-308 |
-7,019 |
-294 |
-11 |
-9,202 |
Extensions |
421 |
0 |
421 |
94 |
12 |
2,566 |
Technical Revisions excl. NI 51-101 |
9,286 |
508 |
9,794 |
16 |
2 |
10,196 |
Discoveries |
0 |
0 |
0 |
0 |
0 |
0 |
Economic Factors |
-1,341 |
641 |
-700 |
277 |
5 |
353 |
Improved Recovery |
1,092 |
0 |
1,092 |
0 |
0 |
1,092 |
Production |
-7,466 |
-1,512 |
-8,978 |
-1,703 |
-88 |
-25,336 |
Reserves at Dec. 31, 2003 excl. NI 51-101 |
106,075 |
20,869 |
126,944 |
17,671 |
1,162 |
338,217 |
NI 51-101 50 Year Cut-off |
-9,187 |
0 |
-9,187 |
-879 |
-40 |
-16,772 |
Other NI 51-101 Revisions |
2,361 |
-1,248 |
1,113 |
521 |
29 |
6,621 |
Reserves at Dec. 31, 2003 incl. NI 51-101 |
99,249 |
19,621 |
118,870 |
17,313 |
1,151 |
328,066 |
Net Present Value of Future Production Revenue
These schedules have been prepared on the basis that no cash income tax will be paid by the Fund or its operating subsidiaries in the future and therefore after-tax future net revenues from oil and gas reserves is equal to before tax future net revenues from oil and gas reserves.
Under Enerplus’ current structure and existing tax legislation, annual taxable income is transferred from its operating entities to the Fund through interest and royalty payments. The Fund, in turn, makes distributions to its unitholders and therefore does not incur any cash income tax in the operating companies or the Fund.
The following table shows the net present value of future production using the forecast prices.
Net Present Value of Future Production Revenue - Forecast Prices and Costs - ($ millions including ARTC) |
0% |
5% |
10% |
15% |
|
|
|
|
|
|
|
Proved developed producing |
$3,540 |
$2,264 |
$1,719 |
$1,414 |
|
Proved developed non-producing |
82 |
56 |
43 |
35 |
|
Proved undeveloped |
286 |
172 |
111 |
75 |
|
Total Proved Reserves |
$3,908 |
$2,492 |
$1,873 |
$1,524 |
|
Probable Reserves |
1,303 |
601 |
360 |
249 |
|
Proved plus Probable Reserves at December 31, 2003 |
$5,211 |
$3,093 |
$2,233 |
$1,773 |
Net Asset Value
Enerplus’ net asset value is measured with reference to the present value of future net cash flows from our reserves as estimated by independent reserve engineers, Sproule Associates Limited (“Sproule”), plus land values, adjusted for working capital and long-term debt at year-end. This calculation can vary significantly depending on the oil and natural gas price assumptions used by Sproule. In addition, this calculation ignores “going concern” value and assumes only the reserves identified in the Sproule report with no further acquisitions, despite our 18 year history of replacing production through acquisitions and development.
Net Asset Value - Forecast Prices ($ millions, except per Trust Unit amount)
|
|
|
|
|
|
0% |
5% |
10% |
15% |
Present value of proved plus probable reserves at December 31, 2003 |
$5,211 |
$3,093 |
$2,233 |
$1,773 |
Undeveloped acreage and seismic (acreage valued at $50/acre) |
17 |
17 |
17 |
17 |
Long-term debt |
-338 |
-338 |
-338 |
-338 |
Net Working capital excluding distributions to unitholders |
65 |
65 |
65 |
65 |
Net asset value |
$4,955 |
$2,837 |
$1,977 |
$1,517 |
Net asset value per Trust Unit(1) |
$52.52 |
$30.07 |
$20.95 |
$16.08 |
(1) Based on 94.3 million Trust Units outstanding as at December 31, 2003.
Reserve Determination Methodologies
Sproule has evaluated 86% of the total proved plus probable value (discounted at 10%) of the Fund’s year-end reserves and has reviewed all the reserves internally evaluated by Enerplus in keeping with NI 51-101. All evaluations of future net production revenues set forth in the tables are stated without provision for income taxes, abandonment costs on existing wells and facilities or associated general and administrative costs.
Prior to this year, Enerplus followed the Canadian practice of using “Established Reserves”, which included proved reserves and the probable reserves portion with a predetermined risk factor of 50%. This year, Enerplus followed the practice of reporting proved plus probable reserves with probable reserves risked by the third party engineering firm or our own internal evaluators in keeping with NI 51-101. In the U.S., reserve estimates are calculated using prices and costs held constant at amounts in effect at the date of the reserve report. Also in the U.S., proved reserves are reported excluding probable reserves and proved reserve standards in the U.S. may not be comparable to the Canadian standards used in NI 51-101. Generally, Canadian proved reserves are more conservative from U.S. proved reserves. In the U.S., only net production is typically reported. As a consequence, care should be used when comparing U.S. and Canadian style reserves and production between companies.
The present value of future cash flows at December 31, 2003 was based upon crude oil and natural gas pricing assumptions prepared by Sproule. The base reference prices and exchange rates used by Sproule are as follows:
Sproule January 1 forecast prices
|
WTI Crude Oil $US/bbl |
Light Crude (1) Edmonton
$CDN/bbl |
Natural gas
30 day spot
Plant Gate Price
$CDN/MMBtu |
Exchange Rate
$US/$Cdn
|
2004 |
$29.63 |
$37.99 |
$5.81 |
$0.75 |
| 2005 |
26.80 |
34.24 |
5.15 |
0.75 |
2006 |
25.76 |
32.87 |
4.59 |
0.75 |
2007 |
26.14 |
33.37 |
4.71 |
0.75 |
2008 |
26.53 |
33.87 |
4.80 |
0.75 |
Thereafter |
+ 1.5% |
+ 1.5% |
+ 1.5% |
0.75 |
(1) Edmonton refinery postings for 40 degree API, 0.4% sulphur content crude
Finding, Development and Acquisition Costs
OUR THREE-YEAR FD&A COSTS, USING PROVED PLUS PROBABLE RESERVES, IS AMONG THE BEST IN OUR SECTOR AT $8.54 PER BOE USING THE NEW NI 51-101 METHODOLOGY AND $7.86 PER BOE USING THE HISTORICAL METHODOLOGY.
Enerplus has maintained an attractive finding, development and acquisition ("FD&A") cost on a proved plus probable reserves basis over time. Our three-year FD&A cost is among the best in our sector at $8.54 per BOE using the new NI 51-101 methodology and $7.86 per BOE using the historical methodology. We also enjoy an attractive three-year average recycle ratio of 1.9 on a proved plus probable reserves basis under NI 51-101. The recycle ratio is indicative of the value created by our investment activities. The higher the recycle ratio, the better the profitability of our investments. A recycle ratio of less than one represents negative value creation.
The following tables summarize Enerplus' FD&A costs on both a proved and proved plus probable basis under both the new NI 51-101 guidelines and the historic method for calculating FD&A. We have also included the recycle ratio on a proved plus probable basis. We believe FD&A and recycle metrics under the new NI 51-101 rules are comparable year-over-year when using established reserves for prior years and the new proved plus probable reserves for 2003. However, a comparison using proved reserves is problematic because of the more stringent rules applied this year. To assist investors in determining our FD&A performance this year in a historical context, we have included FD&A costs as determined under both the new and old methods.
FD&A for proved plus probable reserves did not materially change under the two methods ($8.54 per BOE under the new rules and $7.86 per BOE under the historic methodology) given the comparability of established and proved plus probable reserves used in the calculation. FD&A for proved reserves only changed materially given the significant difference in what constitutes proved reserves year-over-year. Under NI 51-101, we expect 2003 will form a new baseline for proved reserves that can be used to determine FD&A on a proved basis going forward. Historical comparisons, including three-year average FD&A, will continue to be problematic until three years of reserve numbers determined under the same rules are available.
The following schedule compares Enerplus’ FD&A costs for the last three years on a proved plus probable basis under the new rules for NI 51-101 and the old method as historically reported.
FD&A Costs- UNDER NI 51-101 ($ millions, except per BOE amounts)
|
2003 |
2002 |
2001 |
Proved Reserves |
|
|
|
Capital expenditures and net acquisitions |
309.8 |
357.3 |
872.6 |
Net change in Future Development Costs |
(26.1) |
58.6 |
16.4 |
Gross company reserve additions (MBOE)
|
(13.8) |
41.7 |
111.3 |
FD&A costs ($/BOE) |
N/A(1) |
9.97 |
7.99 |
Three year average FD&A costs ($/BOE)(2) |
11.41 |
8.48 |
8.25 |
Proved plus Probable Reserves (Prior to 2003 - Established)
|
|
|
|
Capital expenditures and net acquisitions |
309.8 |
357.3 |
872.6 |
Net change in Future Development Costs |
(43.0) |
48.0 |
42.7 |
Gross company reserve additions (MBOE)
|
23.0 |
41.0 |
121.9 |
FD&A costs ($/BOE) |
11.60 |
9.89 |
7.51 |
Three year average FD&A costs ($/BOE) (2) |
8.54 |
7.88 |
7.48 |
(1) As the negative proved revisions during 2003 were greater than the reserve additions, the FD&A cost for 2003 is not determinable.
(2) Calculated as FD&A over a three-year period.
FD&A Costs - UNDER HISTORIC METHODOLOGY ($ millions, except per BOE amounts)
|
2003 |
2002 |
2001 |
Proved Reserves |
|
|
|
Capital expenditures and net acquisitions(1) |
309.8 |
357.3 |
872.6 |
Gross company reserve additions excluding NI 51-101 effects (MBOE)
|
28.1 |
41.7 |
111.3 |
FD&A costs ($/BOE) |
11.02 |
8.57 |
7.84 |
Three year average FD&A costs ($/BOE) (2) |
8.50 |
8.08 |
8.02 |
Proved plus Probable Reserves (Prior to 2003 - Established)
Reserves |
|
|
|
Capital expenditures and net acquisitions(1) |
309.8 |
357.3 |
872.6 |
Gross company reserve additions excluding NI 51-101 effects (MBOE)
|
33.1 |
41.0 |
121.9 |
FD&A costs ($/BOE) |
9.36 |
8.72 |
7.16 |
Three year average FD&A costs ($/BOE) (2) |
7.86 |
7.46 |
7.19 |
(1) Future Development Costs are excluded from all years.
(2) Calculated as FD&A over a three-year period.
Recycle Ratio
|
2003 |
2002 |
2001 |
Operating netback ($/BOE) |
20.89 |
15.50 |
19.61 |
Finding, development and acquisition costs ($/BOE)
|
11.60 |
9.89 |
7.51 |
Recycle ratio |
1.8x
|
1.6x |
2.6x |
Three year average recycle ratio |
1.9x
|
2.1x |
2.3x |
|
