This news release includes forward-looking statements and
information within the meaning of applicable securities laws.
Readers are advised to review the "Forward-Looking Information and
Statements" at the conclusion of this news release. Readers are
also referred to "Information Regarding Financial and Operational
Information" and "Non-GAAP Measures" at the end of this news
release for information regarding the presentation of the financial
and operational information contained in this news release. A full
copy of our third quarter 2013 Financial Statements and MD&A,
as well as our 2012 Financial Statements and MD&A, have been
filed on our website at www.enerplus.com, under our profile on
SEDAR at www.sedar.com and on the EDGAR website at
www.sec.gov.
CALGARY, Nov. 8, 2013 /CNW/ - Enerplus Corporation
("Enerplus") (TSX: ERF) (NYSE: ERF) is pleased to announce results
for the third quarter of 2013 that were once again ahead of
expectations:
3rd QUARTER HIGHLIGHTS:
- As a result of strong operational performance from our core
areas in both Canada and the U.S.
daily production during the third quarter averaged just under
88,000 BOE/day, up 8% from the same period last year.
- Production from our North
Dakota assets continues to outperform our expectations,
increasing by almost 20% during the quarter to a new record level
of 18,000 BOE/day, achieving our 2013 exit forecast for these
properties one full quarter ahead of expectations.
- Year-to-date, production has averaged 88,318 BOE/day, up 9%
from the same period a year ago in spite of divestments earlier in
the year, and ahead of our revised guidance of 87,500 BOE/day.
- We generated funds flow of $196
million ($0.98 per share) in
the third quarter, up 45% from the third quarter of 2012.
- Our adjusted payout ratio during the quarter fell to 97% and
year-to-date is 103%, a significant improvement from the same
periods in 2012.
- The majority of our $146 million
capital program during the quarter was allocated to our U.S. oil
and Canadian waterflood oil assets, where 70% of our drilling
program took place. We are seeing improved cost performance
in a number of our key operating areas, most notably in Fort
Berthold and in the Marcellus.
- Our capital spending program remains on track with our original
guidance for 2013 with a focus on maximizing crude oil and liquids
production. In the first nine months of 2013, we have spent
only two thirds of our annual capital budget yet are exceeding our
forecasts for both annual average and exit production, despite the
sale of 1,300 BOE/day of non-core production.
- Operating and general and administrative costs per BOE are also
on track and we are maintaining our guidance on both metrics for
the full year.
- Our financial flexibility has also continued to improve in part
from the growth in funds flow and also by our non-core asset sales.
The trailing twelve month debt-to-funds flow ratio fell to 1.2
times at the end of September, compared to 1.9 times for the same
period last year.
- On October 22, 2013, we announced
an additional sale of non-core assets for approximately
$105 million before closing
adjustments which further focuses our operations, strengthens our
balance sheet and improves our financial position.
- With more than 80% of our corporate netback derived from crude
oil, we continue to hedge our exposure to crude oil prices to help
protect our funds flow and ensure our on-going financial
strength. About 74% of our forecast crude oil production, net
of royalties, is hedged at just over US$100/bbl for the remainder of 2013. For
the first half of 2014, we have price protection on 66% of our
forecast crude oil production, net of royalties, at an average
price of US$93.70/bbl, while 49% of
our forecast crude oil production net of royalties for the second
half of 2014 is hedged at US$92.73/bbl. We have 25% of our 2014
forecast natural gas production, net of royalties, hedged at a
price of $4.15/Mcf, before
considering the acquisition of additional interests in the
Marcellus.
- Subsequent to the quarter, we have entered into an agreement to
purchase additional interests in our core Marcellus properties for
approximately US$153 million before
closing adjustments. The acquisition includes 17,000 net acres of
land in the northeast region of Pennsylvania and approximately 42 MMcf/day of
natural gas production. This acquisition will increase our exit
production forecast from 88,000 BOE/day to 95,000 BOE/day.
- In addition, subsequent to the quarter, we have entered into an
agreement to sell our Montney
interests at Julienne Creek for $130
million. The sale includes 33,300 net acres of land with no
associated production or reserves.
SELECTED FINANCIAL RESULTS |
|
|
Three months
ended September 30, |
Nine months ended
September 30, |
|
2013 |
2012 |
2013 |
2012 |
Financial (000's) |
|
|
|
|
Funds Flow |
$196,187 |
$134,980 |
$573,489 |
$444,233 |
Cash and Stock Dividends |
54,405 |
53,394 |
162,199 |
247,988 |
Net Income |
34,020 |
(63,466) |
81,404 |
2,977 |
Debt Outstanding - net of cash |
964,577 |
1,118,569 |
964,577 |
1,118,569 |
Capital Spending |
145,811 |
166,988 |
458,399 |
692,641 |
Property and Land Acquisitions |
15,792 |
7,277 |
71,451 |
63,946 |
Property Dispositions |
124,462 |
3,112 |
197,086 |
55,636 |
|
|
|
|
|
Debt to Trailing 12 Month Funds Flow |
1.2x |
1.9x |
1.2x |
1.9x |
|
|
|
|
|
Financial per Weighted Average Shares
Outstanding |
|
|
|
|
Funds Flow |
$0.98 |
$0.68 |
$2.87 |
$2.28 |
Net Income |
0.17 |
(0.32) |
0.41 |
0.02 |
Weighted Average Number of Shares Outstanding
(000's) |
201,117 |
197,618 |
200,002 |
194,753 |
|
|
|
|
|
Selected Financial Results per
BOE(1) |
|
|
|
|
Oil & Gas Sales(2) |
$53.61 |
$43.30 |
$49.67 |
$44.10 |
Royalties |
(11.91) |
(8.61) |
(10.46) |
(8.74) |
Commodity Derivative Instruments |
(1.30) |
1.06 |
0.42 |
0.11 |
Operating Costs |
(10.58) |
(12.32) |
(10.52) |
(11.00) |
General and Administrative |
(2.48) |
(2.48) |
(2.63) |
(2.70) |
Equity Based Compensation |
(0.60) |
(0.69) |
(0.58) |
(0.24) |
Interest and Other Expenses |
(1.78) |
(2.56) |
(1.78) |
(1.40) |
Taxes |
(0.65) |
0.29 |
(0.33) |
(0.10) |
Funds Flow |
$24.31 |
$17.99 |
$23.79 |
$20.03 |
SELECTED OPERATING RESULTS |
|
|
Three months
ended September 30, |
Nine months ended
September 30, |
|
2013 |
2012 |
2013 |
2012 |
Average Daily Production |
|
|
|
|
|
Crude oil (bbls/day) |
38,883 |
36,810 |
38,426 |
35,807 |
|
NGLs (bbls/day) |
2,985 |
3,538 |
3,357 |
3,644 |
|
Natural gas (Mcf/day) |
275,164 |
247,347 |
279,212 |
249,046 |
|
Total (BOE/day) |
87,729 |
81,573 |
88,318 |
80,959 |
|
|
|
|
|
|
% Crude Oil & Natural Gas Liquids |
48% |
49% |
47% |
49% |
|
|
|
|
|
Average Selling
Price(2) |
|
|
|
|
|
Crude oil (per bbl) |
$ 96.30 |
$ 76.41 |
$ 86.05 |
$ 78.72 |
|
NGLs (per bbl) |
49.88 |
47.81 |
51.48 |
54.88 |
|
Natural gas (per Mcf) |
2.96 |
2.20 |
3.26 |
2.18 |
|
|
|
|
|
Net Wells drilled |
15 |
17 |
50 |
70 |
(1) Non-cash amounts have been
excluded.
(2) Net of oil and gas transportation costs, but
before the effects of commodity derivative instruments.
|
Three months
ended September 30, |
Nine months ended
September 30, |
|
2013 |
2012 |
2013 |
2012 |
Average Benchmark Pricing |
|
|
|
|
WTI crude oil (US$/bbl) |
$105.82 |
$92.22 |
$98.14 |
$96.21 |
AECO- monthly index (CDN$/Mcf) |
2.82 |
2.19 |
3.16 |
2.18 |
AECO- daily index (CDN$/Mcf) |
2.43 |
2.29 |
3.05 |
2.11 |
NYMEX- monthly NX3 index (US$/Mcf) |
3.60 |
2.81 |
3.68 |
2.62 |
USD/CDN exchange rate |
1.04 |
1.00 |
1.02 |
1.00 |
SHARE TRADING SUMMARY |
CDN* - ERF |
U.S.** - ERF |
For the three months ended
September 30, 2013 |
(CDN$) |
(US$) |
High |
$18.35 |
$17.69 |
Low |
$15.29 |
$14.43 |
Close |
$17.05 |
$16.59 |
* TSX and other Canadian trading data combined.
**NYSE and other U.S. trading data combined.
2013 DIVIDENDS PER
SHARE |
|
|
|
|
|
CDN$ |
US$(1) |
First Quarter Total |
|
|
$0.27 |
$0.27 |
Second Quarter Total |
|
|
$0.27 |
$0.26 |
July |
|
|
$0.09 |
$0.09 |
August |
|
|
$0.09 |
$0.08 |
September |
|
|
$0.09 |
$0.09 |
Third Quarter Total |
|
|
$0.27 |
$0.26 |
Total Year-to-Date |
|
|
$0.81 |
$0.79 |
(1) US$ dividends represent CDN$ dividends converted
at the relevant foreign exchange rate on the payment date.
PRODUCTION AND CAPITAL SPENDING |
|
Three months ended
September 30, 2013 |
|
Nine months ended
September 30, 2013 |
Crude Oil & NGLs
(BOE/day) |
Average
Production
Volumes |
Capital
Spending
($ millions) |
|
Average
Production
Volumes |
Capital
Spending
($ millions) |
Canada |
19,511 |
$35 |
|
21,035 |
$117 |
United States |
22,357 |
66 |
|
20,748 |
221 |
Total Crude Oil & NGLs (BOE/day) |
41,868 |
$101 |
|
41,783 |
$338 |
Natural Gas (Mcf/day) |
|
|
|
|
|
Canada |
174,169 |
$22 |
|
179,503 |
$67 |
United States |
100,995 |
23 |
|
99,709 |
53 |
Total Natural Gas (Mcf/day) |
275,164 |
$45 |
|
279,212 |
$120 |
Company Total (BOE/day) |
87,729 |
$146 |
|
88,318 |
$458 |
NET DRILLING ACTIVITY - for the three months
ended September 30, 2013 |
|
|
|
|
|
|
|
Crude Oil |
Horizontal
Wells |
Vertical Wells |
Total
Wells |
Wells
Pending
Completion/
Tie-in * |
Wells
On-stream** |
Dry &
Abandoned
Wells |
Canada |
4.7 |
- |
4.7 |
2.7 |
5.7 |
- |
United States |
6.6 |
- |
6.6 |
5.3 |
3.2 |
- |
Total Crude Oil |
11.3 |
- |
11.3 |
8.0 |
8.9 |
- |
Natural Gas |
|
|
|
|
|
|
Canada |
1.1 |
- |
1.1 |
1.1 |
- |
- |
United States |
2.8 |
- |
2.8 |
2.6 |
2.2 |
- |
Total Natural Gas |
3.9 |
- |
3.9 |
3.7 |
2.2 |
- |
Company Total |
15.2 |
- |
15.2 |
11.7 |
11.1 |
- |
*Wells drilled during the quarter that are pending potential
completion/tie-in or abandonment as at September 30, 2013.
**Total wells brought on-stream during the quarter regardless of
when they were drilled.
U.S. Crude Oil
We continued to allocate the majority of our capital spending to
the Williston Basin, targeting
light crude oil from the Bakken and Three
Forks oil plays. During the quarter we invested $66 million at Fort Berthold, North Dakota, drilling 6.6 net
horizontal wells and bringing 3.2 net horizontal wells on stream.
During this period our North
Dakota production grew by almost 2,900 BOE/day to a record
18,000 BOE/day, a 19% increase from the last quarter.
Combined with our Bakken production from Montana, our U.S. assets now account for more
than half of Enerplus' total crude oil and liquids volumes.
We are also seeing a significant improvement in well performance
as we continue to optimize our completion design. Since the start
of 2013, we have evolved our completions, moving from ceramic
proppant to white sand proppant while increasing the number of frac
stages by 40% and the amount of proppant per stage by over 200%.
Despite the increase in frac size, our average cost per frac stage
has decreased by approximately 15%. More significantly, the average
30 day cumulative initial production in our most recent Bakken and
Three Forks wells is 80% or higher
than the rates we were achieving at the start of 2013.
We've drilled 10.6 net wells in the Bakken and 4.9 net wells in
the first bench of the Three Forks
to date in 2013 and continue to explore downspacing and testing of
the lower benches of the Three
Forks in order to expand our drilling inventory.
Canadian Crude Oil
Production from our Canadian oil assets averaged approximately
19,500 BOE/day, down from second quarter results of 21,300 BOE/day
largely due to downtime at our Medicine Hat "Glauc C" property and
the sale of non-core production earlier in the year.
In Saskatchewan, results on the
Ratcliffe trend continued to exceed our expectations. These
assets attracted the highest share of investment amongst our
waterflood properties during the quarter as we drilled 3.7 net
horizontal wells in the area, brought 2 net wells on stream, and
continued to invest in infrastructure to support our growing
production in the region. Initial production volumes over the
first 30 days from these wells are exceeding our type curve
expectations by almost 60%, with rates of about 220 bbls/day.
We plan on drilling 2 additional gross (1.3 net) wells offsetting
these producers during the fourth quarter of 2013.
U.S. Natural Gas
Production from the Marcellus averaged 83 MMcf/day of natural
gas during the quarter, ahead of our planned 2013 exit rate of 75
MMcf/day. We continue to be encouraged by strong well performance
and as new wells come on stream, we expect to reach record
production levels in the fourth quarter. We invested $23 million in the Marcellus during the quarter,
which included the drilling of 2.8 net wells and bringing 2.2 net
wells on stream. As a result of the production growth
achieved year-to-date and an improvement in NYMEX natural gas
prices year-over-year, funds flow has increased significantly from
the Marcellus with approximately $48
million realized year-to-date. Additionally, well
costs have also improved, declining approximately 20% from our
original budget expectations. Given the on-going production growth
from the Marcellus and lagging infrastructure expansion,
differentials in the region continued to widen. Our long-term sales
contracts on over 75% of our current production provided us with a
degree of protection, resulting in our average realized Marcellus
gas price being about US$0.52/Mcf
below the NYMEX price during the quarter. Until infrastructure
catches up to the burgeoning natural gas supply and new markets
open up, we expect that wide differentials will persist in the
region.
Canadian Natural Gas
Our Canadian natural gas activities continued to be focused in
the Deep Basin region of Alberta
where we are advancing our development plans in the Wilrich and
continuing to delineate the Duvernay.
Based upon the success of our drilling activity in the Wilrich,
we acquired an additional 5,000 net acres in the Minehead area
during the third quarter and have moved one dedicated rig to the
region to execute our development plans. We plan to drill and
complete one well in the fourth quarter and expect to spud a second
well which will be completed in early 2014.
As a result of recent drilling activity, Enerplus now has core
data from three Duvernay vertical
delineation test wells on varying sections of our leases in the
Willesden Green area. The core analysis from these wells is
positive and in our view supports a range of expected free
condensate of 75 - 150 bbls per million cubic feet of natural gas
over a significant portion of our acreage block. This data
supports our current plan to drill a horizontal re-entry which is
underway in one of the vertical tests. We expect to follow with
another horizontal well with completion of both wells scheduled in
2014.
Marcellus Acquisition and Montney Disposition Subsequent to
the Quarter
Consistent with our strategy to concentrate our portfolio in top
tier assets in core areas, we have entered into agreements to add
to our U.S. gas position in the Marcellus and to also sell our
Montney interests in northeastern
British Columbia.
We have entered into an agreement to acquire additional working
interests in 17,000 net non-operated acres within our core
properties in the Marcellus with current production of
approximately 42 MMcf/day of natural gas for approximately
US$153 million before closing
adjustments.
The acquisition increases our working interest in existing
non-operated leases within the northeast region of Pennsylvania. Since entering the play in
2009, well performance from this region has surpassed our
expectations and increased our confidence in the productivity and
economic viability of the Marcellus. Based upon the drilling
results achieved to date, we expect ultimate recoveries ("EUR") of
natural gas in the best areas to range from 10 Bcf to 13.5 Bcf or
higher per well. Close to half of the acquired leases are located
in 10 Bcf or greater areas and virtually all of the value of the
transaction has been attributed to these Tier 1 areas with
approximately 44 net future drilling locations.
Approximately 60% of the total leases being acquired are
currently held by production. With the majority of our existing
core leasehold acreage now held by production, we have seen an
improvement in drilling efficiencies to date in 2013 that has
resulted in lower well costs. Based upon our expected
ultimate recoveries and current well costs of under $7 million, we expect top tier full cycle
finding, development and acquisition costs of less than
$1.00 per Mcf with attractive recycle
ratios.
Upon closing of the acquisition, Enerplus' core Marcellus
acreage will total approximately 60,000 net acres. We plan to
more fully outline our capital spending plans when we release our
2014 production and capital forecast in December of this year.
The acquisition is expected to close at the end of November 2013 and as a result will increase our
2013 exit rate guidance from 88,000 BOE/day to 95,000 BOE/day. This
increase in natural gas production in 2014 is expected to provide
us with the opportunity to continue selling non-core assets and
high-grading our portfolio. Our 2013 annual average production and
capital spending forecast is not expected to change materially as a
result of the acquisition.
We have also entered into an agreement to sell our Montney interests at Julienne Creek for
$130 million. While we believe
the Julienne Creek asset offers significant scope and scale, the
natural gas produced in this area is predominantly dry with very
little associated natural gas liquids production. Our core assets
in the Williston Basin, our
waterfloods, the Marcellus and the Deep Basin (Wilrich and
Duvernay) provide us with a deep
inventory of future drilling prospects that offer more favourable
economics and will enable us to grow production, reserves and cash
flow in existing areas in both the near and long-term. Enerplus has
invested approximately $50 million
building our position in the Montney. The sale includes 33,300 net
contiguous acres (100% working interest) with no current production
or reserves, representing sale metrics of approximately
$3,900 per acre.
Summary
Our quarterly results once again reflect the benefits of our
multi-year strategy to position Enerplus in top tier resource plays
and develop them within a disciplined capital allocation and cost
management framework. Our non-core property dispositions
continue to help us improve our financial flexibility and enable us
to focus our expertise and capital spending within our four core
areas. These strategies are driving improved capital efficiencies
and achieving sustainable, profitable growth and income for our
investors. We plan to continue on this path of value creation
for our shareholders.
Q3 Results Live Conference Call
A conference call will be held at 9:00 AM
MT (11:00 AM ET) to discuss
these results. Details of the conference call are as follows:
Date: |
Friday, November 8, 2013 |
Time: |
9:00 AM MT (11:00 AM ET) |
Dial-In: |
647-427-7450 |
|
1-888-231-8191 (toll free) |
Audiocast: |
http://www.newswire.ca/en/webcast/detail/1238557/1364449 |
To ensure timely participation in the conference call, callers
are encouraged to dial in 15 minutes prior to the start time to
register for the event. A telephone replay will be available for 30
days following the conference call and can be accessed at the
following numbers:
Dial-In: |
416-849-0833 |
|
1-855-859-2056 (toll free) |
Passcode: |
79678943 |
Electronic copies of our Q3 MD&A and financial statements,
along with other public information including investor
presentations are available on our website at
www.enerplus.com. For further information, please contact
Investor Relations at 1-800-319-6462 or email
investorrelations@enerplus.com.
Follow @EnerplusCorp on Twitter at
https://twitter.com/EnerplusCorp.
INFORMATION REGARDING FINANCIAL AND OPERATIONAL
INFORMATION
Currency and Production Amounts
All amounts in this news release are stated in Canadian
dollars unless otherwise specified. All production volumes are
presented on a company interest basis, being the Company's working
interest share before deduction of any royalties paid to others
plus the Company's royalty interests. Company interest is not a
term defined in Canadian National Instrument 51-101- Standards of
Disclosure for Oil and Gas Activities) and may not be comparable to
information produced by other entities.
Barrels of Oil Equivalent and Cubic Feet of Gas
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.
See "Non-GAAP Measures" below.
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: achievement of
operational targets for 2013; Enerplus' expected operating and
general and administrative costs and oil and natural gas production
volumes for 2013; our average realized crude oil and natural gas
prices and future differentials; the proportion of our anticipated
oil and natural gas production that is hedged; Enerplus' financial
capacity to support capital spending plans and its dividend;
potential asset divestments and acquisitions and the impact of such
on our 2013 production; future efficiencies and reserves and
production growth from capital spending; future capital and
development expenditures and the allocation thereof among our
assets; future development and drilling locations, plans and costs;
the performance of and future results from Enerplus' assets and
operations, including anticipated production levels, decline rates
and future growth prospects; the potential change of our status
from "foreign private issuer" to U.S. domestic issuer as of
January 1, 2014 and expected changes
in our reporting related thereto; and our ability to improve our
trading multiple and create significant value for our
shareholders.
The forward-looking information contained in this news
release reflects several material factors and expectations and
assumptions of Enerplus including, without limitation: that
Enerplus' operations and development plans will achieve the
expected results; the general continuance of current or, where
applicable, assumed industry conditions, including third party
costs; the continuation of assumed tax, royalty and regulatory
regimes; 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; the continued availability and sufficiency
of our funds flow and availability under our bank credit facility
to fund our working capital deficiency; the extent of its
liabilities; and that Enerplus will be able to complete planned
asset sales. 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 and resources volumes; limited, unfavourable or a lack
of access to capital markets; an inability to complete planned
asset sales and acquisitions; 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 for the year ended December 31, 2012, filed on SEDAR and EDGAR,
respectively, on February 22,
2013).
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
"adjusted payout ratio" to analyze operating performance, leverage
and liquidity, and "netback" as measures of operating
performance. We calculate "adjusted payout ratio" as cash
dividends to shareholders, net of our stock dividends (and for 2012
comparative purposes, our DRIP proceeds), plus capital spending
(including office capital) divided by funds flow. "Netback" is
calculated as oil and gas sales revenues after deducting royalties,
operating costs and transportation.
Enerplus believes that, in addition to net earnings and other
measures prescribed by IFRS, the term "adjusted payout ratio" and
"netback" are useful supplemental measures as they provides an
indication of the results generated by Enerplus' principal business
activities. However, these measures are not recognized by GAAP and
do not have a standardized meaning prescribed by IFRS. 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