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CALGARY, Aug. 5, 2011 /CNW/ --
All financial figures are unaudited and in Canadian dollars (CDN$)
unless noted otherwise. All financial statements have been prepared in
accordance with International Financial Reporting Standards ("IFRS")
including comparative figures pertaining to Enerplus' 2010 results. A
reconciliation of comparative figures is provided in the notes to the
Unaudited Interim Consolidated Financial Statements for the period
ended June 30, 2011.
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, Resources and Operations", "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,
contingent resources and operational information in this news release.
A full copy of our 2011 Second Quarter 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, Aug. 5, 2011 /CNW/ - Enerplus Corporation ("Enerplus") (TSX:
ERF) (NYSE: ERF) is pleased to announce operating and financial results
for the three months ended June 30, 2011. Highlights for the quarter
include:
Acquisitions and Divestments
-- We sold approximately 45% of our Marcellus acreage position in
Pennsylvania, Maryland and West Virginia, including 24.5 Bcfe
of proved plus probable reserves for approximately $568
million, capturing a pre-tax gain of $272 million. Proceeds
from the sale were used to reduce our outstanding bank debt,
leaving our $1 billion credit facility virtually undrawn at the
end of the quarter.
-- Subsequent to the sale, we have retained a significant land
position in the Marcellus that is more balanced consisting of
110,000 net acres, 60% of which is operated. Our non-operated
Marcellus position includes approximately 45,000 net acres
concentrated in the prolific Northeast area of Pennsylvania
whereas our 65,000 net operated acres are located in West
Virginia and Maryland. The independent best estimate of
contingent resources associated with our remaining leases is
2.3 Tcfe and 92 Bcfe of proved plus probable natural gas
reserves as of December 31, 2010.
-- We continued to add to our undeveloped land inventory in
emerging resource plays in Canada this year. Year-to-date we
have acquired approximately 38,000 net acres in the
liquids-rich Duvernay shale play and 14,000 net acres in two
emerging Canadian oil prospects. We also added over 9,000 net
acres of Montney prospective lands in the Cameron area of
British Columbia, bringing our total Montney undeveloped land
position to approximately 28,000 net acres. In total, we've
invested approximately $75 million in unvdeveloped land to the
end of July 2011.
Production
-- Daily production averaged 75,383 BOE/day despite challenges
relating to wet weather in our key producing regions and was
virtually unchanged compared to the first quarter of 2011.
-- Field conditions have begun to improve in July and we are
ramping up activities with four operated rigs now running in
North Dakota at Fort Berthold and are building to four operated
rigs in Canada focused mainly on our waterflood properties. We
expect to bring on over 60 net wells during the second half of
the year as drilling activity increases. Production volumes are
expected to build throughout the remainder of the year, with
the most significant increases anticipated late in the third
quarter and into the fourth quarter.
Financial
-- We generated funds flow of $132.4 million ($0.74/share) during
the quarter. Our funds flow does not reflect the gain of $272
million from the Marcellus asset sale; however it does reflect
a $43 million U.S. tax expense resulting from the sale of those
assets. Funds flow was $0.98 per share if adjusted for the
impact of the tax expense. See "Non-GAAP Measures" below.
-- We invested approximately $145 million in our assets during the
quarter, drilling 14.1 net wells. Approximately 60% of our
capital was directed toward oil projects, primarily in the
Bakken and 33% invested in the Marcellus.
-- We maintained our monthly dividend at $0.18/share through the
quarter.
-- We exited the quarter in a very strong financial position with
a debt to funds flow ratio of only 0.7x.
-- Operating costs of $9.84/BOE and G&A costs of $3.64/BOE during
the quarter were marginally higher than anticipated mainly due
to lower production.
-- Our hedging program generated cash losses of approximately $21
million ($3.03/BOE) during the quarter as crude oil prices were
above our hedge positions. We currently have over 60% of our
anticipated crude oil production for the second half of 2011
hedged at $87.27 per barrel and have over 30% of our forecast
2012 crude oil production hedged at over $98.00 per barrel. We
do not have any natural gas price hedges in place.
Updated Guidance
-- We have adjusted our capital spending guidance for 2011 from
$650 million to $770 million due to an increase in drilling
activity in both our operated and non-operated acreage and as a
result of cost increases. We expect to drill more wells in the
Marcellus where activity is focused on the highly economic
northeast area of Pennsylvania, in the liquids rich Deep Basin
region and also in our oil properties in Canada. Approximately
85% of our total spending remains focused in our Bakken,
Marcellus and waterflood assets.
-- Approximately $60 million of the increase in capital spending
for 2011 is attributed to transitory cost increases due to the
wet weather, some cost overruns on a few of our delineation
projects, as well as inflationary cost increases for some
services in Canada.
-- Delays in production and capital spending due to the weather
during the quarter reduced our expectations for annual average
production by 800 BOE/day. We also sold 900 BOE/day of annual
average production and 3,800 BOE/day of exit 2011 production
due to the Marcellus sale. As a result, we are adjusting our
2011 annual average production guidance down by 2,000 BOE/day
to 76,000 to 78,000 BOE/day.
-- Due to the additional capital spending plans in the second half
of the year, we are adjusting our exit production guidance up
slightly to 81,000 - 84,000 BOE/day.
-- With regard to 2012, we are evaluating opportunities within our
portfolio and the potential to increase spending and production
volumes beyond our original guidance issued earlier this year.
We expect to provide greater clarity on our 2012 plans in the
fourth quarter.
SELECTED FINANCIAL RESULTS
Three months ended June Six months ended June 30,
30,
2011 2010((1)) 2011 2010((1))
Financial (000's)
Funds Flow( (2)) $132,441 $174,753 $293,665 $373,035
Dividends to 97,077 95,909 193,763 191,621
Shareholders
Net Income/(Loss) 267,982 76,502 297,531 (107,520)
Debt Outstanding 460,087 697,817 460,087 697,817
- net of cash
Capital Spending 145,165 88,395 319,609 182,556
Property and Land 94,415 310,114 142,633 349,747
Acquisitions
Divestments 571,096 181,238 630,788 182,776
Financial per
Weighted Average
Shares
Outstanding
Funds Flow( (2)) $0.74 $0.99 $1.64 $2.13
Dividends 0.54 0.55 1.08 1.09
Net Income/(Loss) 1.50 0.44 1.66 (0.61)
Weighted Average
Number of Shares
Outstanding 179,583 175,705 179,209 175,099
Debt to Trailing
12 Month Funds
Flow 0.7x 0.9x((5)) 0.7x 0.9x((5))
Selected Financial
Results per BOE(
(3))
Oil & Gas Sales((4)
()) $51.62 $41.18 $49.28 $44.39
Royalties (9.07) (7.35) (8.85) (7.96)
Commodity (3.03) 2.23 (1.30) 1.38
Derivative
Instruments
Operating Costs (9.86) (10.09) (9.37) (10.03)
General and (3.16) (2.18) (3.21) (2.46)
Administrative
Interest and (0.89) (1.12) (1.82) (0.99)
Other Expenses
Taxes (6.30) (0.05) (3.22) (0.03)
Funds Flow((2)) $19.31 $22.62 $21.51 $24.30
SELECTED OPERATING RESULTS
Three months ended June Six months ended June 30,
30,
2011 2010 2011 2010
Average Daily
Production
Natural gas 255,665 296,566 253,584 297,737
(Mcf/day)
Crude oil 29,330 31,559 29,831 31,268
(bbls/day)
NGLs (bbls/day) 3,442 3,922 3,337 3,924
Total (BOE/day) 75,383 84,909 75,433 84,815
% Natural gas 57% 58% 56% 59%
Average Selling
Price((4))
Natural gas (per $3.86 $3.78 $3.88 $4.44
Mcf)
Crude oil (per 90.92 68.72 84.23 71.25
bbl)
NGLs (per bbl) 66.20 47.55 63.35 52.49
US$/CDN$ exchange 1.03 0.97 1.02 0.97
rate
Net Wells drilled 14.1 19 40.2 158
((1) ) (2010 comparative amounts have been restated and are
presented in accordance with International Financial
Reporting Standards ("IFRS"). In addition, 2010 comparatives
represent the results of Enerplus Resources Fund which
converted into Enerplus Corporation on January 1, 2011.)
((2))( ) (See "Non-GAAP Measures" in the Management's Discussion and
Analysis of Enerplus Corporation dated August 4, 2011.)
((3)) (Non-cash amounts have been excluded.)
((4) ) (Net of oil and gas transportation costs, but before the
effects of commodity derivative instruments.)
((5))( ) (The 12 months trailing funds flow for June 30, 2010,
includes funds flow for July through December 2009 which was
prepared following previous Canadian GAAP.)
Share Trading Summary CDN* - ERF U.S.** - ERF
For the three months ended June 30, (CDN$) (US$)
2011
High $31.54 $32.86
Low $28.82 $29.61
Close $30.45 $31.60
* TSX and other Canadian trading data
combined.
**NYSE and other U.S. trading data
combined.
2011 Cash Dividends Per Share
Payment Month CDN$ US$*
First Quarter Total $0.54 $0.55
April $0.18 $0.19
May 0.18 0.18
June 0.18 0.18
Second Quarter Total $0.54 $0.55
Total Year-to-Date $1.08 $1.10
(*US$ dividends represent CDN$ dividends converted at the relevant
foreign exchange rate on the payment date.)
PRODUCTION AND CAPITAL SPENDING
Three months ended Six months ended
June 30, 2011 June 30, 2011
Average Capital Average Capital
Production Spending Production Spending
Play Type Volumes ($ millions) Volumes ($ millions)
Bakken/Tight Oil 12,724 67 13,197 135
(BOE/day)
Crude Oil 13,314 19 13,379 48
Waterfloods
(BOE/day)
Conventional Oil 6,075 1 6,269 4
(BOE/day)
Total Oil (BOE/day) 32,114 87 32,845 187
Marcellus Shale Gas 21,867 47 21,571 89
(Mcfe/day)
Other Natural Gas 237,746 11 233,959 44
(Mcfe/day)
Total Gas 259,613 58 255,530 133
(Mcfe/day)
Company Total 75,383 145 75,433 320
NET DRILLING ACTIVITY for the three months ended June 30, 2011
Wells
Pending Wells Dry &
Horizontal Vertical Total Completion/ On- Abandoned
Play Type Wells Wells Wells Tie-in* stream Wells
Bakken/Tight 7.6 - 7.6 4.6 3.0 -
Oil
Crude Oil - - - - - -
Waterfloods
Conventional 1.5 0.1 1.6 1.6 - -
Oil
Total Oil 9.1 0.1 9.2 6.2 3.0 -
Marcellus 4.7 - 4.7 4.7 - -
Shale Gas
Other 0.2 - 0.2 0.2 - -
Natural Gas
Total Gas 4.9 - 4.9 4.9 - -
Company 14.0 0.1 14.1 11.1 3.0 -
Total
(*Pending potential completion/tie-in or abandonment and on-stream
wells measured as at June 30, 2011)
Bakken/Tight Oil
As a result of the unusually wet weather conditions in the Williston
Basin, we experienced a second consecutive quarter of lower than
anticipated activity in our Bakken/tight oil resource play. We managed
to keep two rigs working in Fort Berthold, North Dakota and two rigs
working in Sleeping Giant, Montana throughout the quarter where we
drilled 6 net operated horizontal wells and brought 2.8 net wells
on-stream during the quarter. We also participated in the drilling of
1.6 net wells at Taylorton, Saskatchewan. Production volumes for the
quarter averaged approximately 12,700 BOE/day, down 900 BOE/day from
the first quarter due to weather and timing delays.
At Fort Berthold, we drilled one long and three short Bakken horizontal
wells during the quarter and completed and brought on a short Three
Forks well. We began drilling a long Three Forks lateral well during
the quarter and anticipate testing the well during the third quarter.
We currently have four rigs working at Fort Berthold and expect to
maintain this rig count through the remainder of 2011. Infrastructure
and gathering system build continues to proceed and we expect to have a
majority of our wells tied in by the end of the third quarter, reducing
our reliance on trucking. Production volumes are also expected to
increase by approximately 10% due to the associated natural gas volumes
which will be captured once the wells are tied into the gathering
system. We expect to drill 26 horizontal wells at Fort Berthold during
the remainder of the year, targeting both the Bakken and the Three
Forks formations and plan to complete and tie-in 22 wells. We have
permits in place for all of our 2011 wells and are currently working to
secure 2012 and 2013 drilling permits. Our 2011 plans include testing
downspacing to determine optimal well density and as a result, we
expect approximately 75% of the wells drilled this year will be short
lateral horizontals. Under the full development scenario, approximately
75% of the wells are expected to be long horizontals. With four rigs
working and our frac services agreement in place, drilling and
completions activity should accelerate and we expect to remain on
schedule for the balance of the year, drilling and completing three to
four wells per month. We continue to expect to spend approximately $250
million in North Dakota and Montana in 2011.
Waterfloods
Activity during the second quarter was mainly focused on our two
enhanced oil recovery projects at Giltedge and Medicine Hat. Our
polymer pilot at Giltedge is now fully operational and we are seeing
indications that the polymer is moving through the project area.
Assessment of oil production performance is expected by year end. At
Medicine Hat, we continued to work on facility build-out to support our
polymer project and plan to be injecting polymer early in 2012. Despite
nominal tie-ins during the quarter, production volumes were unchanged
from the first quarter at 13,300 BOE/day, emphasizing the benefits of
these low decline properties.
Marcellus
High activity levels in the Marcellus continued through the second
quarter of 2011 as our partners drilled wells to retain and develop
leases. On our non-operated land, we participated in drilling 59 gross
wells (approximately 5.3 net) with the majority of this activity in
northeastern Pennsylvania where production rates and expected ultimate
recoveries have been generally above our type curve. Although none of
the wells drilled during the quarter were completed or tied-in due to
wet weather, 1.2 net wells previously drilled were brought on stream
during the quarter. There are currently 169 gross wells (12.5 net
wells) drilled by our partners that are waiting on completion and/or
tie-in. Production volumes during the quarter averaged 21.9 MMcfe/day,
slightly above our first quarter average of 21.3 MMcfe/day. Current
production is approximately 12 MMcf/day.
UPDATING 2011 GUIDANCE
_____________________________________________________________________
|2011 Estimates | |
|_____________________________________________________|_______________|
|Capital Expenditures ($millions) | |
|_____________________________________________________|_______________|
| Original Capital Expenditure Estimate | $650|
|_____________________________________________________|_______________|
| Capital Reduction Due to Marcellus Disposition | ($50)|
|_____________________________________________________|_______________|
| Increased Spending | $170|
|_____________________________________________________|_______________|
| Revised Capital Expenditure Estimate | $770|
|_____________________________________________________|_______________|
| | |
|_____________________________________________________|_______________|
|Revised Capital Expenditures By Resource Play | |
|_____________________________________________________|_______________|
| Bakken/Tight Oil | $325|
|_____________________________________________________|_______________|
| Waterfloods | $145|
|_____________________________________________________|_______________|
| Marcellus | $195|
|_____________________________________________________|_______________|
| Deep Basin | $55|
|_____________________________________________________|_______________|
|% of Total | 94%|
|_____________________________________________________|_______________|
| | |
|_____________________________________________________|_______________|
|Original Annual Average Production Estimate (BOE/day)|78,000 - 80,000|
|_____________________________________________________|_______________|
|Oil & Liquids Weighting | 47%|
|_____________________________________________________|_______________|
| | |
|_____________________________________________________|_______________|
|Less Marcellus Production Sold & Weather Impacts | (1,700)|
|(BOE/day) | |
|_____________________________________________________|_______________|
|Revised Annual Average Production (BOE/day) |76,000 - 78,000|
|_____________________________________________________|_______________|
|Oil & Liquids Weighting | 45%|
|_____________________________________________________|_______________|
| | |
|_____________________________________________________|_______________|
|Original Exit Production Estimate (BOE/day) |80,000 - 84,000|
|_____________________________________________________|_______________|
|Less Marcellus Production Sold (BOE/day) | (3,800)|
|_____________________________________________________|_______________|
|Revised Exit Production Estimate (BOE/day) |81,000 - 84,000|
|_____________________________________________________|_______________|
|Oil & Liquids Weighting | 47%|
|_____________________________________________________|_______________|
ADDITIONS TO THE BOARD OF DIRECTORS
We are pleased to announce that Ms. Sue MacKenzie and Mr. David Barr
joined the board of directors of Enerplus effective July 1, 2011. Ms.
MacKenzie has over 25 years of energy sector experience, having served
as Chief Operating Officer with Oilsands Quest Inc. and Vice-President
of Human Resources and Vice President of In Situ Development and
Operations for Petro-Canada. Mr. Barr has 36 years of experience in
the oil and gas industry, and is President and Chief Executive Officer
of Logan International Inc. He was formerly Chairman of the Board of
Logan International. He also spent close to 20 years with Baker Hughes
in various executive roles, including Group President of numerous
divisions and President of Baker Atlas.
OUTLOOK
The unusual weather experienced during the first half of 2011 has
presented a number of operational challenges for Enerplus. However,
through the hard work and dedication of our employees, particularly in
the field, we were successful in mitigating any significant impacts to
our business and maintaining our production volumes at similar levels
to the first quarter. We have once again delivered a significant gain
to shareholders with the Marcellus sale and increased our financial
strength and ability to deliver on our growth plans. The second half
of 2011 is expected to be very active due to the increase in capital
spending and the number of wells we plan to drill and tie-in. We will
be focused on executing our capital program and achieving our
production targets through the remainder of the year.
For further information, please contact our Investor Relations
Department at 1-800-319-6462 or email investorrelations@enerplus.com.
- 30 -
Gordon J. Kerr
President & Chief Executive Officer
Enerplus Corporation
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 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. Additionally, the SEC prohibits
disclosure of oil and gas resources, whereas Canadian issuers may
disclose oil and gas resources. Resources are different than, and
should not be construed as reserves. For a description of the
definition of, and the risks and uncertainties surrounding the
disclosure of, contingent resources, see "Information Regarding
Reserves, Resources and Operations" below.
INFORMATION REGARDING RESERVES, RESOURCES AND OPERATIONS
Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent
This news release also contains references to "BOE" (barrels of oil
equivalent) and "cfe" (cubic feet of gas 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, and one barrel
of oil to six thousand cubic feet of gas (1 bbl: 6 Mcf) when converting
oil to cfes. BOEs and cfes 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.
Contingent Resource Estimates
This news release contains estimates of "contingent resources".
"Contingent resources" are not, and should not be confused with, oil
and gas reserves. "Contingent resources" are defined in the Canadian
Oil and Gas Evaluation Handbook (the "COGE Handbook") as "those quantities of petroleum estimated, as of a given date, to
be potentially recoverable from known accumulations using established
technology or technology under development, but which are not currently
considered to be commercially recoverable due to one or more
contingencies. Contingencies may include factors such as economic,
legal, environmental, political and regulatory matters or a lack of
markets. It is also appropriate to classify as "contingent resources"
the estimated discovered recoverable quantities associated with a
project in the early evaluation stage." There is no certainty that we
will produce any portion of the volumes currently classified as
"contingent resources". The "contingent resource" estimates contained
herein are presented as the "best estimate" of the quantity that will
actually be recovered, effective as of December 31, 2010. A "best
estimate" of contingent resources means that it is equally likely that
the actual remaining quantities recovered will be greater or less than
the best estimate, and if probabilistic methods are used, there should
be at least a 50% probability that the quantities actually recovered
will equal or exceed the best estimate.
For information regarding the primary contingencies which currently
prevent the classification of our disclosed "contingent resources"
associated with our Marcellus shale gas assets as reserves and the
positive and negative factors relevant to the "contingent resource"
estimate, see our Annual Information Form for the year ended December
31, 2010 (and corresponding Form 40-F), a copy of which is available on
our SEDAR profile at www.sedar.com and a copy of the Form 40-F which is available on our EDGAR profile at www.sec.gov.
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'
strategy to deliver both income and growth to investors and Enerplus'
related asset portfolio; future capital and development expenditures
and the timing and allocation thereof among our resource plays and
assets; future development and drilling locations and plans; the
performance of and future results from Enerplus' assets and operations,
including anticipated production levels and decline rates; future
growth prospects, acquisitions and dispositions; the volumes and
estimated value of Enerplus' oil and gas reserves and contingent
resource volumes 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 production; securing necessary
infrastructure and third party services; future cash flows and
debt-to-cash flow levels; returns on Enerplus' capital program; and
future costs and expenses.
The forward-looking information contained in this news release reflect
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 and
resource volumes; commodity price and cost assumptions; the continued
availability of adequate debt and/or equity financing and cash flow 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
reserve and resource 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 speak
only as of the date of this news release, and none of Enerplus or its
subsidiaries assumes 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 "funds flow" to analyze operating
performance, leverage and liquidity. We calculate funds flow based on
cash flow from operating activities before changes in non-cash
operating working capital and decommissioning liabilities settled, all
of which are measures prescribed by International Financial Reporting
Standards ("IFRS") and which appear in our Consolidated Statements of
Cash Flows.
Enerplus believes that, in addition to net earnings and other measures
prescribed by IFRS, the term "funds flow", is a useful supplemental
measure as it provides an indication of the results generated by
Enerplus' principal business activities. However, this measure is not
recognized by IFRS and does not have a standardized meaning prescribed
by IFRS. Therefore, this measure, as defined by Enerplus, may not be
comparable to similar measures presented by other issuers.
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p Investor Relations Department at 1-800-319-6462 or email a href="mailto:investorrelations@enerplus.com"investorrelations@enerplus.com/a. /p