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. To view this news release
in HTML formatting, please use the following URL:
http://www.newswire.ca/en/releases/archive/August2011/05/c9300.html
p Investor Relations Department at 1-800-319-6462 or email a
href="mailto:investorrelations@enerplus.com"investorrelations@enerplus.com/a.
/p
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