This news release includes forward-looking statements and
information within the meaning of applicable securities
laws. Readers are advised to review "Forward-Looking
Information and Statements" at the conclusion of this news release.
Readers are also referred to "Information Regarding Reserves and
Operational Information", "Notice to U.S. Readers" and "Non-GAAP
Measures" at the end of this news release for information regarding
the presentation of the financial, reserves and operational
information in this news release.
CALGARY, Feb. 3, 2014 /CNW/ - Enerplus Corporation
("Enerplus") (TSX: ERF) (NYSE: ERF) is pleased to announce
production and reserve results for the year ended
2013. Highlights include:
2013 PRODUCTION
- Annual average production grew by over 9% in 2013 to average
89,800 BOE per day, ahead of our expectations of 89,000
BOE/day.
- Production during the month of December averaged 99,600 BOE per
day, exceeding our expectations due to continued outperformance in
the Marcellus, which averaged 170 MMcf per day during the
month.
- Fourth quarter 2013 production averaged 94,200 BOE per day. As
a result of the Marcellus performance, the natural gas weighting
increased to 56% during the quarter.
2013 YEAR-END RESERVES
- Proved plus probable company interest ("2P") reserves grew by
over 17% to 406 MMBOE. On a per share basis, 2P reserves increased
by 15% year-over-year.
- Added 78 MMBOE of 2P reserves through our development programs,
including technical and economic revisions, replacing 238% of 2013
annual production. Approximately 30% of the reserve additions
were from crude oil.
- Added a total of 93 MMBOE of 2P reserves, including technical
and economic revisions and net acquisition and development
activity, replacing 284% of production in 2013. 83% of the
total reserve additions were from natural gas.
- Capital spending for the year was an estimated $681.4 million, slightly less than our forecast
of $685 million. Approximately two
thirds of our capital was invested in oil projects in 2013.
- 2P finding and development ("F&D") costs including future
development capital ("FDC") decreased by over 50% to $11.28 per BOE. This represents a recycle
ratio of 2.4 times based upon an estimated operating netback of
$27.40 per BOE in 2013.
- 2P finding, development and acquisition ("FD&A") costs per
BOE were $8.36 per BOE including FDC,
down over 60% year-over-year. Our three year FD&A costs
for 2P reserves, including FDC, are $14.66 per BOE.
- A total of 24.4 MMbbls of 2P crude oil reserves were added
through our acquisition and capital spending activities, including
technical and economic revisions, reflecting a 175% oil production
replacement and offsetting the disposition of 10 MMbbls of oil
reserves during the year.
- 2P natural gas reserves increased by 43% to 1.2 Tcf with the
addition of 463 Bcf associated with our development, acquisition
and divestment activities. The majority of the increase in 2P
natural gas reserves is attributable to the Marcellus where we
added 268 Bcf of 2P reserves through our capital development
activities, including technical and economic factors, and 143 Bcf
through acquisitions. Total Marcellus 2P reserves at year-end
increased to 601 Bcf and now represent 50% of our total 2P natural
gas reserves, up from 27% at year-end 2012.
- 12.1 MMBOE of 2P reserves were sold during 2013 at an average
cost of $33.72 per BOE.
- 26.9 MMBOE of 2P reserves were purchased during 2013, the
majority of which is attributable to the acquisition of additional
working interests in the Marcellus, at an average cost of
$11.25 per BOE.
- 2P reserve life index remains essentially unchanged at 10.8
years.
INDEPENDENT RESERVES EVALUATION
All reserves information, including our U.S. reserves, has been
prepared in accordance with Canadian National Instrument 51-101 -
Standards of Disclosure for Oil and Gas Activities ("NI 51-101")
standards. Independent reserve evaluations have been conducted
on approximately 89.5% of the total proved plus probable value
(before tax, discounted at 10%) of our reserves at December 31, 2013. McDaniel & Associates
Consultants Ltd. ("McDaniel") evaluated 74% of our Canadian
reserves and 100% of the reserves associated with our U.S. oil
assets. McDaniel also reviewed the internal evaluation completed by
Enerplus on the remaining 26% of our Canadian assets. Netherland,
Sewell & Associates, Inc. ("NSAI") evaluated all of our U.S.
natural gas assets.
The following reserves information sets out our company interest
reserves volumes at December 31, 2013
by production type and reserve category under McDaniel's forecast
price scenarios. Under different price scenarios, these reserves
could vary as a change in price can affect the economic limit
associated with a property. Company interest reserves consist of
gross reserves, which are before the deduction of any royalties,
plus Enerplus' royalty interests in reserves. It should be
noted that tables may not add due to rounding.
See "Information Regarding Reserves and Operational
Information" at the end of this news release for information
regarding the presentation of company interest reserves.
RESERVES SUMMARY
Enerplus' 2P reserves increased by 60.2 million BOE to 406.0
million BOE at year-end 2013, up from 345.8 million at year-end
2012. The majority of reserve additions were associated with
our U.S. properties as a result of our drilling and acquisition
activities. These assets now represent 58% of total 2P
reserves. Proved reserves as a percentage of total 2P reserves
remained at 65% year-over-year.
Reserves Summary |
Light &
Medium
Oil
(Mbbls) |
Heavy Oil
(Mbbls) |
Total Oil
(Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Natural
Gas
(MMcf) |
Shale
Gas
(MMcf) |
Total
(MBOE) |
Company Interest |
|
|
|
|
|
|
|
Proved producing |
64,108 |
26,700 |
90,808 |
7,348 |
354,385 |
212,770 |
192,681 |
Proved developed non-producing |
805 |
136 |
941 |
145 |
8,486 |
72,320 |
14,553 |
Proved undeveloped |
22,883 |
3,980 |
26,863 |
1,475 |
46,959 |
126,342 |
57,221 |
Total proved |
87,795 |
30,816 |
118,611 |
8,967 |
409,830 |
411,431 |
264,455 |
Total probable |
62,371 |
11,264 |
73,635 |
5,757 |
183,744 |
189,430 |
141,587 |
Proved plus Probable |
150,166 |
42,080 |
192,246 |
14,723 |
593,574 |
600,861 |
406,042 |
Gross |
|
|
|
|
|
|
|
Proved producing |
64,006 |
26,689 |
90,695 |
7,166 |
338,646 |
212,770 |
189,764 |
Proved developed non-producing |
805 |
136 |
941 |
144 |
8,417 |
72,320 |
14,541 |
Proved undeveloped |
22,879 |
3,980 |
26,859 |
1,422 |
43,215 |
126,342 |
56,540 |
Total proved |
87,689 |
30,806 |
118,495 |
8,732 |
390,280 |
411,431 |
260,844 |
Total probable |
62,340 |
11,260 |
73,600 |
5,629 |
174,445 |
189,430 |
139,875 |
Proved plus Probable |
150,029 |
42,066 |
192,095 |
14,361 |
564,725 |
600,861 |
400,720 |
Net |
|
|
|
|
|
|
|
Proved producing |
53,604 |
21,407 |
75,011 |
5,398 |
305,107 |
170,423 |
159,663 |
Proved developed non-producing |
700 |
106 |
806 |
104 |
6,335 |
57,893 |
11,614 |
Proved undeveloped |
18,654 |
3,053 |
21,707 |
1,172 |
42,789 |
101,084 |
46,858 |
Total proved |
72,957 |
24,566 |
97,523 |
6,674 |
354,231 |
329,400 |
218,136 |
Total probable |
50,388 |
8,588 |
58,976 |
4,459 |
158,767 |
151,530 |
115,152 |
Proved plus Probable |
123,345 |
33,154 |
156,499 |
11,134 |
512,998 |
480,930 |
333,288 |
|
|
|
|
|
|
|
|
RESERVES RECONCILIATION
The following tables outline the changes in Enerplus' proved,
probable and proved plus probable reserves, on a company interest
basis, from December 31, 2012 to
December 31, 2013:
Proved Reserves - Company Interest
Volumes (Forecast Prices) |
|
CANADA |
Light &
Medium
Oil
(Mbbls) |
Heavy
Oil
(Mbbls) |
Total Oil
(Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Natural
Gas
(MMcf) |
Shale
Gas
(MMcf) |
Total
(MBOE) |
Proved Reserves at
Dec. 31, 2012 |
36,246 |
31,521 |
67,767 |
6,887 |
361,158 |
- |
134,847 |
Acquisitions |
1,580 |
- |
1,580 |
19 |
1,676 |
- |
1,879 |
Dispositions |
(7,105) |
- |
(7,105) |
(599) |
(5,999) |
- |
(8,703) |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
1,511 |
1,528 |
3,039 |
196 |
24,172 |
- |
7,264 |
Economic factors |
491 |
55 |
546 |
(29) |
(3,058) |
- |
8 |
Technical revisions |
(105) |
828 |
722 |
878 |
32,791 |
- |
7,065 |
Production |
(3,404) |
(3,115) |
(6,520) |
(1,023) |
(64,195) |
- |
(18,241) |
Proved Reserves at
Dec. 31, 2013 |
29,214 |
30,816 |
60,030 |
6,330 |
346,545 |
- |
124,118 |
UNITED STATES |
Light &
Medium
Oil
(Mbbls) |
Heavy
Oil
(Mbbls) |
Total Oil
(Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Natural
Gas
(MMcf) |
Shale
Gas
(MMcf) |
Total
(MBOE) |
Proved Reserves at
Dec. 31, 2012 |
56,993 |
- |
56,993 |
2,349 |
52,748 |
146,127 |
92,488 |
Acquisitions |
30 |
- |
30 |
2 |
12 |
117,668 |
19,645 |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
5,188 |
- |
5,188 |
255 |
5,177 |
168,634 |
34,412 |
Economic factors |
(556) |
- |
(556) |
2 |
(1,126) |
(17,140) |
(3,598) |
Technical revisions |
4,368 |
- |
4,368 |
273 |
12,778 |
30,917 |
11,924 |
Production |
(7,442) |
- |
(7,442) |
(245) |
(6,305) |
(34,775) |
(14,533) |
Proved Reserves at
Dec. 31, 2013 |
58,581 |
- |
58,581 |
2,637 |
63,285 |
411,431 |
140,337 |
|
|
|
|
|
|
|
|
|
|
TOTAL ENERPLUS |
Light &
Medium
Oil
(Mbbls) |
Heavy
Oil
(Mbbls) |
Total Oil
(Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Natural
Gas
(MMcf) |
Shale
Gas
(MMcf) |
Total
(MBOE) |
Proved Reserves at
Dec. 31, 2012 |
93,239 |
31,521 |
124,760 |
9,236 |
413,906 |
146,127 |
227,335 |
Acquisitions |
1,610 |
- |
1,610 |
21 |
1,688 |
117,668 |
21,524 |
Dispositions |
(7,105) |
- |
(7,105) |
(599) |
(5,999) |
- |
(8,703) |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
6,699 |
1,528 |
8,227 |
451 |
29,349 |
168,634 |
41,675 |
Economic factors |
(65) |
55 |
(10) |
(26) |
(4,183) |
(17,140) |
(3,590) |
Technical revisions |
4,262 |
828 |
5,090 |
1,151 |
45,569 |
30,917 |
18,989 |
Production |
(10,846) |
(3,115) |
(13,961) |
(1,267) |
(70,499) |
(34,775) |
(32,774) |
Proved Reserves at
Dec. 31, 2013 |
87,795 |
30,816 |
118,611 |
8,967 |
409,830 |
411,431 |
264,455 |
Probable Reserves - Company
Interest Volumes (Forecast Prices) |
|
CANADA |
Light &
Medium
Oil
(Mbbls) |
Heavy
Oil
(Mbbls) |
Total Oil
(Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Natural
Gas
(MMcf) |
Shale
Gas
(MMcf) |
Total
(MBOE) |
Probable Reserves at
Dec. 31, 2012 |
12,810 |
10,991 |
23,801 |
3,144 |
171,526 |
- |
55,533 |
Acquisitions |
290 |
- |
290 |
3 |
283 |
- |
340 |
Dispositions |
(2,775) |
- |
(2,775) |
(214) |
(2,164) |
- |
(3,350) |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
687 |
1,751 |
2,438 |
70 |
8,489 |
- |
3,923 |
Economic factors |
(13) |
57 |
45 |
(18) |
(937) |
- |
(129) |
Technical revisions |
(1,320) |
(1,536) |
(2,856) |
(421) |
(32,227) |
- |
(8,649) |
Production |
- |
- |
- |
- |
- |
- |
- |
Probable Reserves at
Dec. 31, 2013 |
9,679 |
11,264 |
20,943 |
2,564 |
144,970 |
- |
47,668 |
|
|
UNITED STATES |
Light &
Medium
Oil
(Mbbls) |
Heavy
Oil
(Mbbls) |
Total Oil
(Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Natural
Gas
(MMcf) |
Shale
Gas
(MMcf) |
Total
(MBOE) |
Probable Reserves at
Dec. 31, 2012 |
43,111 |
- |
43,111 |
2,243 |
27,202 |
78,373 |
62,950 |
Acquisitions |
681 |
- |
681 |
40 |
266 |
25,686 |
5,046 |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
14,477 |
- |
14,477 |
986 |
12,973 |
89,619 |
32,562 |
Economic factors |
8 |
- |
8 |
2 |
(19) |
(8,877) |
(1,473) |
Technical revisions |
(5,585) |
- |
(5,585) |
(78) |
(1,647) |
4,629 |
(5,166) |
Production |
- |
- |
- |
- |
- |
- |
- |
Probable Reserves at
Dec. 31, 2013 |
52,692 |
- |
52,692 |
3,193 |
38,774 |
189,430 |
93,919 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ENERPLUS |
Light &
Medium
Oil
(Mbbls) |
Heavy
Oil
(Mbbls) |
Total Oil
(Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Natural
Gas
(MMcf) |
Shale
Gas
(MMcf) |
Total
(MBOE) |
Probable Reserves at
Dec. 31, 2012 |
55,921 |
10,991 |
66,912 |
5,387 |
198,728 |
78,373 |
118,482 |
Acquisitions |
971 |
- |
971 |
43 |
548 |
25,686 |
5,386 |
Dispositions |
(2,775) |
- |
(2,775) |
(214) |
(2,164) |
- |
(3,350) |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
15,164 |
1,751 |
16,916 |
1,056 |
21,462 |
89,619 |
36,485 |
Economic factors |
(5) |
57 |
53 |
(16) |
(956) |
(8,877) |
(1,602) |
Technical revisions |
(6,905) |
(1,536) |
(8,441) |
(499) |
(33,874) |
4,629 |
(13,815) |
Production |
- |
- |
- |
- |
- |
- |
- |
Probable Reserves at Dec. 31, 2013 |
62,371 |
11,264 |
73,635 |
5,757 |
183,744 |
189,430 |
141,587 |
Proved Plus Probable Reserves -
Company Interest Volumes (Forecast Prices) |
|
CANADA |
Light &
Medium
Oil
(Mbbls) |
Heavy
Oil
(Mbbls) |
Total Oil
(Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Natural
Gas
(MMcf) |
Shale
Gas
(MMcf) |
Total
(MBOE) |
Proved Plus Probable
Reserves at Dec. 31, 2012 |
49,056 |
42,512 |
91,568 |
10,031 |
532,684 |
- |
190,380 |
Acquisitions |
1,870 |
- |
1,870 |
23 |
1,959 |
- |
2,219 |
Dispositions |
(9,880) |
- |
(9,880) |
(813) |
(8,163) |
- |
(12,053) |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
2,198 |
3,279 |
5,477 |
266 |
32,661 |
- |
11,186 |
Economic factors |
478 |
113 |
591 |
(46) |
(3,995) |
- |
(121) |
Technical revisions |
(1,426) |
(708) |
(2,134) |
457 |
564 |
- |
(1,583) |
Production |
(3,404) |
(3,115) |
(6,520) |
(1,023) |
(64,195) |
- |
(18,241) |
Proved Plus Probable
Reserves at Dec. 31, 2013 |
38,893 |
42,080 |
80,973 |
8,894 |
491,515 |
- |
171,787 |
|
|
UNITED STATES |
Light &
Medium
Oil
(Mbbls) |
Heavy
Oil
(Mbbls) |
Total Oil (Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Natural
Gas
(MMcf) |
Shale
Gas
(MMcf) |
Total
(MBOE) |
Proved Plus Probable
Reserves at Dec. 31, 2012 |
100,104 |
- |
100,104 |
4,592 |
79,950 |
224,500 |
155,438 |
Acquisitions |
711 |
- |
711 |
42 |
277 |
143,354 |
24,691 |
Dispositions |
- |
- |
- |
- |
- |
- |
- |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
19,665 |
- |
19,665 |
1,241 |
18,150 |
258,253 |
66,974 |
Economic factors |
(548) |
- |
(548) |
4 |
(1,145) |
(26,017) |
(5,071) |
Technical revisions |
(1,217) |
- |
(1,217) |
196 |
11,131 |
35,545 |
6,758 |
Production |
(7,442) |
- |
(7,442) |
(245) |
(6,305) |
(34,775) |
(14,533) |
Proved Plus Probable
Reserves at Dec. 31, 2013 |
111,273 |
- |
111,273 |
5,829 |
102,059 |
600,861 |
234,256 |
|
|
|
|
|
|
|
|
TOTAL ENERPLUS |
Light &
Medium
Oil
(Mbbls) |
Heavy
Oil
(Mbbls) |
Total Oil
(Mbbls) |
Natural
Gas
Liquids
(Mbbls) |
Natural
Gas
(MMcf) |
Shale
Gas
(MMcf) |
Total
(MBOE) |
Proved Plus Probable
Reserves at Dec. 31, 2012 |
149,160 |
42,512 |
191,672 |
14,623 |
612,634 |
224,500 |
345,817 |
Acquisitions |
2,581 |
- |
2,581 |
64 |
2,236 |
143,354 |
26,910 |
Dispositions |
(9,880) |
- |
(9,880) |
(813) |
(8,163) |
- |
(12,053) |
Discoveries |
- |
- |
- |
- |
- |
- |
- |
Extensions & improved
recovery |
21,864 |
3,279 |
25,143 |
1,507 |
50,811 |
258,253 |
78,160 |
Economic factors |
(70) |
113 |
43 |
(42) |
(5,139) |
(26,017) |
(5,192) |
Technical revisions |
(2,643) |
(708) |
(3,351) |
652 |
11,695 |
35,545 |
5,174 |
Production |
(10,846) |
(3,115) |
(13,961) |
(1,267) |
(70,499) |
(34,775) |
(32,774) |
Proved Plus Probable
Reserves at Dec. 31, 2013 |
150,166 |
42,080 |
192,246 |
14,723 |
593,574 |
600,861 |
406,042 |
|
|
|
|
|
|
|
|
FUTURE DEVELOPMENT CAPITAL
Changes in forecast FDC occur annually as a result of
development activities, acquisition and disposition activities and
capital cost estimates that reflect the evaluators' best estimate
of the capital required to bring the proved and proved plus
probable reserves on production. The aggregate of the exploration
and development costs incurred in the most recent year and the
change during the year in estimated future development costs
generally reflect the total finding and development costs related
to reserve additions for that year.
The increase in FDC year-over-year is a result of the increase
in the number of undeveloped drilling locations at Fort Berthold,
the Marcellus, in the Wilrich and in our Canadian waterflood
properties.
The following is a summary of the independent reserve
evaluators' estimated FDC required to bring the total proved and
proved plus probable probable reserves on production:
Future Development
Capital |
Proved
Reserves |
Proved Plus
Probable Reserves |
($ millions) |
|
2014 |
479 |
558 |
2015 |
390 |
518 |
2016 |
31 |
439 |
2017 |
31 |
376 |
2018 |
19 |
40 |
Remainder |
51 |
65 |
Total FDC Undiscounted |
1,001 |
1,996 |
Total FDC Discounted at 10% |
889 |
1,667 |
F&D AND FD&A COSTS -
including future development capital |
|
($ millions except for per BOE amounts) |
2013 |
2012 |
2011 |
3 Year |
Proved Plus Probable Reserves |
|
|
|
|
|
|
|
|
|
Finding & Development Costs |
|
|
|
|
Capital Expenditures |
$ 681.4 |
$ 852.8 |
$ 829.8 |
$ 2,364.0 |
Net change in Future Development
Capital |
$ 200.0 |
$ 534.6 |
$ 435.9 |
$ 1,170.5 |
Company Interest Reserve
additions (MMBOE) |
78.1 |
57.3 |
48.2 |
$ 183.6 |
F&D costs ($/BOE) |
$ 11.28 |
$ 24.21 |
$ 26.26 |
$ 19.25 |
|
|
|
|
|
Finding, Development & Acquisition
Costs |
|
|
|
|
Capital expenditures and net
acquisitions |
$ 561.1 |
$ 726.4 |
$ 370.2 |
$ 1,657.7 |
Net change in Future Development
Capital |
$ 216.6 |
$ 509.1 |
$ 402.7 |
$ 1,128.4 |
Company Interest Reserve
additions (MMBOE) |
93.0 |
53.9 |
43.2 |
$ 190.1 |
FD&A costs ($/BOE) |
$ 8.36 |
$ 22.92 |
$ 17.89 |
$ 14.66 |
|
|
|
|
|
Proved Reserves |
|
|
|
|
|
|
|
|
|
Finding & Development Costs |
|
|
|
|
Capital Expenditures |
$ 681.4 |
852.8 |
829.8 |
$ 2,364.0 |
Net change in Future Development
Capital |
$ (106.4) |
248.3 |
230.7 |
$ 372.6 |
Company Interest Reserve
additions (MMBOE) |
57.1 |
38.4 |
31.5 |
$ 127.0 |
F&D costs ($/BOE) |
$ 10.08 |
$ 28.67 |
$ 33.67 |
$ 21.55 |
|
|
|
|
|
Finding, Development & Acquisition
Costs |
|
|
|
|
Capital expenditures and net
acquisitions |
$ 561.1 |
726.4 |
370.2 |
$ 1,657.7 |
Net change in Future Development
Capital |
$ (112.8) |
241.3 |
213.0 |
$ 341.5 |
Company Interest Reserve
additions (MMBOE) |
69.9 |
36.6 |
28.9 |
$ 135.4 |
FD&A costs ($/BOE) |
$ 6.41 |
$ 26.44 |
$ 20.18 |
$ 14.77 |
|
FORECAST PRICE ASSUMPTIONS
The estimated reserves volumes and the net present values of
future net revenues ("NPV") at December 31,
2013 were based upon forecast crude oil and natural gas
pricing assumptions prepared by McDaniel as of January 1, 2014. These prices were applied to the
reserves evaluated by McDaniel and NSAI, along with those evaluated
internally by Enerplus and reviewed by McDaniel. The base reference
prices and exchange rates used by McDaniel are detailed below.
While the near-term oil and natural gas price assumptions used
by our independent reserve evaluators at January 1, 2014 increased, the long-term price
outlooks decreased when compared to the price assumptions used at
December 31, 2012. As a result,
despite a 17% increase in our 2P reserves at December 31, 2013, the estimated before tax NPV
using a 10% discount increased by only 7%.
McDaniel January 2014
Forecast Price Assumptions |
|
WTI
Crude Oil
US$/bbl |
Light
Crude Oil(1)
Edmonton
CDN$/bbl |
Hardisty
Heavy Oil
12o API
CDN$/bbl |
Henry Hub
Gas Price
US$/MMBtu |
Natural Gas
30 day spot
@ AECO
CDN$/MMBtu |
Exchange
Rate
CDN$/US$ |
|
|
|
|
|
|
|
2014 |
95.00 |
95.00 |
67.50 |
4.25 |
4.00 |
0.950 |
2015 |
95.00 |
96.50 |
70.40 |
4.50 |
4.25 |
0.950 |
2016 |
95.00 |
97.50 |
71.20 |
4.75 |
4.55 |
0.950 |
2017 |
95.00 |
98.00 |
71.50 |
5.00 |
4.75 |
0.950 |
2018 |
95.30 |
98.30 |
71.80 |
5.25 |
5.00 |
0.950 |
Thereafter |
** |
** |
** |
** |
** |
0.950 |
(1) Edmonton Light
Sweet 40 degree API, 0.3% sulphur content crude.
** Escalation varies after 2018. |
|
NET PRESENT VALUE OF FUTURE PRODUCTION REVENUE
The following table provides an estimate of the net present
value of Enerplus' future production revenue after deduction of
royalties, estimated future capital and operating expenditures,
before income taxes. It should not be assumed that the present
value of estimated future cash flows shown below is representative
of the fair market value of the reserves.
Net Present Value of Future
Production Revenue - Forecast Prices and Costs (before
tax) |
Reserves at December 31, 2013, ($ Millions,
discounted at) |
0% |
5% |
10% |
15% |
Proved developed producing |
$5,238 |
$3,820 |
$3,051 |
$2,575 |
Proved developed non-producing |
299 |
217 |
174 |
147 |
Proved undeveloped |
1,305 |
612 |
312 |
152 |
Total Proved |
$6,842 |
$4,649 |
$3,537 |
$2,874 |
Probable |
4,933 |
2,382 |
1,437 |
974 |
Total Proved Plus Probable Reserves (before
tax) |
$11,775 |
$7,031 |
$4,974 |
$3,848 |
INFORMATION REGARDING RESERVES AND OPERATIONAL
INFORMATION
Currency
All amounts in this news release are stated in Canadian
dollars unless otherwise specified.
Barrels of Oil Equivalent
This news release also contains references to "BOE" (barrels of
oil equivalent). Enerplus has adopted the standard of six thousand
cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when
converting natural gas to BOEs. BOEs may be misleading,
particularly if used in isolation. The foregoing conversion
ratios are based on an energy equivalency conversion method
primarily applicable at the burner tip and do not represent a value
equivalency at the wellhead. Given that the value ratio based on
the current price of oil as compared to natural gas is
significantly different from the energy equivalent of 6:1,
utilizing a conversion on a 6:1 basis may be misleading. "MBOE" and
"MMBOE" mean "thousand barrels of oil equivalent" and "million
barrels of oil equivalent", respectively.
Presentation of Production and Reserves Information
All production volumes and revenues presented herein are
reported on a "company interest" basis, before deduction of Crown
and other royalties, plus Enerplus' royalty interest. Unless
otherwise specified, all reserves volumes in this news release (and
all information derived therefrom) are based on "company interest
reserves" using forecast prices and costs. "Company interest
reserves" consist of "gross reserves" (as defined in NI 51-101),
being Enerplus' working interest before deduction of any
royalties), plus Enerplus' royalty interests in reserves. "Company
interest reserves" are not a measure defined in NI 51-101 and do
not have a standardized meaning under NI 51-101. Accordingly, our
company interest reserves may not be comparable to reserves
presented or disclosed by other issuers. Our oil and gas reserves
statement for the year ended December 31,
2013, which will include complete disclosure of our oil and
gas reserves and other oil and gas information in accordance with
NI 51-101, will be contained within our Annual Information Form for
the year ended December 31, 2013
("our AIF") which will be available in late February 2014 on our website at
www.enerplus.com and under our SEDAR profile at www.sedar.com.
Additionally, our AIF will form part of our Form 40-F that will be
filed with the U.S. Securities and Exchange Commission and will be
available on EDGAR at www.sec.gov. Readers are also urged to review
the Management's Discussion & Analysis and financial statements
to be filed on SEDAR and EDGAR concurrently with our AIF for more
complete disclosure on our operations.
F&D and FD&A Costs
F&D costs presented in this news release are calculated
(i) in the case of F&D costs for proved reserves, by dividing
the sum of exploration and development costs incurred in the year
plus the change in estimated future development costs in the year,
by the additions to proved reserves in the year, and (ii) in the
case of F&D costs for proved plus probable reserves, by
dividing the sum of exploration and development costs incurred in
the year plus the change in estimated future development costs in
the year, by the additions to proved plus probable reserves in the
year. The aggregate of the exploration and development costs
incurred in the most recent financial year and the change during
that year in estimated future development costs generally reflect
total finding and development costs related to its reserves
additions for that year.
FD&A costs presented in this news release are calculated
(i) in the case of FD&A costs for proved reserves, by dividing
the sum of exploration and development costs and the cost of net
acquisitions incurred in the year plus the change in estimated
future development costs in the year, by the additions to proved
reserves including net acquisitions in the year, and (ii) in the
case of FD&A costs for proved plus probable reserves, by
dividing the sum of exploration and development costs and the cost
of net acquisitions incurred in the year plus the change in
estimated future development costs in the year, by the additions to
proved plus probable reserves including net acquisitions in the
year. The aggregate of the exploration and development costs
incurred in the most recent financial year and the change during
that year in estimated future development costs generally reflect
total finding, development and acquisition costs related to its
reserves additions for that year.
See "Non-GAAP Measures" below.
Other Metrics
Reserve life index is calculated by dividing the total
applicable reserves quantity by the 2014 annual production as
forecast in the reserves evaluations.
NOTICE TO U.S. READERS
The oil and natural gas reserves information contained in
this news release has generally been prepared in accordance with
Canadian disclosure standards, which are not comparable in all
respects to United States or other
foreign disclosure standards. Reserves categories such as "proved
reserves" and "probable reserves" may be defined differently under
Canadian requirements than the definitions contained in
the United States Securities and
Exchange Commission (the "SEC") rules. In addition, under
Canadian disclosure requirements and industry practice, reserves
and production are reported using gross (or, as noted above,
"company interest") volumes, which are volumes prior to deduction
of royalty and similar payments. The practice in the United States is to report reserves and
production using net volumes, after deduction of applicable
royalties and similar payments. Canadian disclosure requirements
require that forecasted commodity prices be used for reserves
evaluations, while the SEC mandates the use of an average of first
day of the month price for the 12 months prior to the end of the
reporting period.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking
information and statements ("forward-looking information")
within the meaning of applicable securities laws. The use of any of
the words "expect", "anticipate", "continue", "estimate",
"guidance", "objective", "ongoing", "may", "will", "project",
"should", "believe", "plans", "intends", "budget", "strategy" and
similar expressions are intended to identify forward-looking
information. In particular, but without limiting the foregoing,
this news release contains forward-looking information pertaining
to the following: Enerplus' asset portfolio; future capital and
development expenditures to bring reserves on production; the
volumes and estimated net present value of Enerplus' oil and gas
reserves and future commodity price and foreign exchange rate
assumptions related thereto; the life of Enerplus' reserves; the
volume and product mix of Enerplus' oil and gas reserves and
production; and future costs, expenses and royalty rates.
The forward-looking information contained in this news
release reflects several material factors and expectations and
assumptions of Enerplus including, without limitation: that
Enerplus will conduct its operations and achieve results of
operations as anticipated; that Enerplus' development plans will
achieve the expected results; the general continuance of current
or, where applicable, assumed industry conditions; the continuation
of assumed tax, royalty and regulatory regimes; the accuracy of the
estimates of Enerplus' reserve volumes; commodity price and cost
assumptions; the continued availability of adequate debt and/or
equity financing, cash flow and other sources to fund Enerplus'
capital and operating requirements as needed; and the extent of its
liabilities. Enerplus believes the material factors, expectations
and assumptions reflected in the forward-looking information are
reasonable but no assurance can be given that these factors,
expectations and assumptions will prove to be correct.
The forward-looking information included in this news release
is not a guarantee of future performance and should not be unduly
relied upon. Such information involves known and unknown risks,
uncertainties and other factors that may cause actual results or
events to differ materially from those anticipated in such
forward-looking information including, without limitation: changes
in commodity prices; changes in the demand for or supply of
Enerplus' products; unanticipated operating results, results from
development plans or production declines; changes in tax or
environmental laws, royalty rates or other regulatory matters;
changes in development plans by Enerplus or by third party
operators of Enerplus' properties; increased debt levels or debt
service requirements; inaccurate estimation of Enerplus' oil and
gas reserves volumes; limited, unfavourable or a lack of access to
capital markets; increased costs; a lack of adequate insurance
coverage; the impact of competitors; reliance on industry partners;
and certain other risks detailed from time to time in Enerplus'
public disclosure documents (including, without limitation, those
risks identified in Enerplus' Annual Information Form and Form 40-F
described above).
The forward-looking information contained in this news
release speaks only as of the date of this news release, and none
of Enerplus or its subsidiaries assume any obligation to publicly
update or revise them to reflect new events or circumstances,
except as may be required pursuant to applicable laws.
NON-GAAP MEASURES
In this news release, we use the terms
""F&D costs", "FD&A costs", "recycle ratio" and "operating
netback" as measures of operating performance. "Operating
netback" is calculated as oil and gas sales revenues after
deducting royalties, operating costs and transportation. A "recycle
ratio" is calculated as F&D costs divided by operating
netback.
Enerplus believes that, in addition to net earnings and other
measures prescribed by U.S. GAAP, the terms "recycle ratio",
"F&D costs" and "FD&A costs" are useful supplemental
measures as they provide an indication of the results generated by
Enerplus' principal business activities. However, these measures
are not measures recognized by GAAP and do not have a standardized
meaning prescribed by U.S. GAAP. Therefore, these measures, as
defined by Enerplus, may not be comparable to similar measures
presented by other issuers.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation