All financial information contained within this news release
has been prepared in accordance with U.S. GAAP including
comparative figures pertaining to Enerplus' 2013 results. 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 "Non-GAAP Measures" at the end of this news release for
information regarding the presentation of the financial and
operational information in this news release. A full copy of our
First Quarter 2014 Financial Statements and MD&A are available
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, May 9, 2014 /CNW/ - Enerplus Corporation
("Enerplus") (TSX: ERF) (NYSE: ERF) is pleased to announce the
results from operations for the first quarter 2014.
HIGHLIGHTS:
- Enerplus demonstrated continued focus on operational execution
under a disciplined capital program in the first quarter,
delivering growth in both production and funds flow.
- Production volumes grew by 5% in the first quarter compared to
the fourth quarter of 2013, averaging 98,821 BOE per day. This
increase was attributable to record production from the Marcellus,
which averaged nearly 180 MMcf per day. While our crude oil volumes
were maintained quarter over quarter, adverse weather conditions
caused production interruptions in both our Canadian and U.S.
operations and slowed capital spending activities. We expect
that our crude oil production will continue to grow throughout 2014
achieving our guidance as we move through the year.
- We are maintaining our annual average production forecast of
96,000 BOE per day to 100,000 BOE per day, however we expect to
track towards the high end of the range due to the outperformance
in the Marcellus. As a result, our natural gas weighting is
expected to increase to 56% of total volumes.
- Higher production levels and stronger commodity prices
contributed to an increase in funds flow during the quarter. Funds
flow grew to $220 million
($1.09 per share), up 22% from the
previous quarter. Cold weather throughout many regions of
North America caused natural gas
prices to increase by over 50% and contributed to the growth in
funds flow. This increase and the proceeds from our non-core
divestment program also strengthened our balance sheet. Our
debt to trailing twelve month funds flow ratio improved to 1.3x
from 1.4x at year end.
- Capital spending was slightly less than planned in the quarter
due to weather interruptions delaying some of our completion
activities, particularly in our U.S. oil assets. We invested
$218 million and continue to expect
to be on track with our full year capital program. However, the
decline in the Canadian dollar exchange rate vis-à-vis the U.S.
dollar, while positive to revenues, will increase our reported
capital spending for the year. With approximately 60% of our
capital program invested in our U.S. assets, and modestly
higher capital spending associated with our non-operated projects,
our capital spending forecast for 2014 is expected to increase to
$800 million, up 5% from our original
estimate of $760 million.
- Both our operating and G&A costs were in line with our
estimates during the quarter and we are maintaining our guidance
targets. Given the increase in our share price, we anticipate that
cash share based compensation will increase by $0.20 per BOE to $0.45 per BOE.
- As a result of the improvement in our sustainability and
balance sheet over the past year, and to reduce dilution, we
elected to remove the 5% discount under our Stock Dividend Program
("SDP") effective with the April 2014
dividend payment. The SDP remains in place, affording shareholders
the opportunity to reinvest their dividends on a monthly basis.
SELECTED FINANCIAL RESULTS
|
|
|
Three months ended March 31, |
|
|
|
|
|
2014 |
|
|
|
|
2013 |
Financial (000's) |
|
|
|
|
|
|
|
|
|
|
Funds Flow |
|
|
|
$ |
220,512 |
|
|
|
$ |
172,599 |
Cash and Stock Dividends |
|
|
|
|
54,935 |
|
|
|
|
53,785 |
Net Income/(Loss) |
|
|
|
|
40,037 |
|
|
|
|
(16,397) |
Debt Outstanding - net of cash |
|
|
|
|
1,020,720 |
|
|
|
|
1,125,762 |
Capital Spending |
|
|
|
|
217,763 |
|
|
|
|
172,947 |
Property and Land Acquisitions |
|
|
|
|
9,969 |
|
|
|
|
3,967 |
Property Divestments |
|
|
|
|
117,225 |
|
|
|
|
1,331 |
Debt to Trailing 12-Month Funds
Flow |
|
|
|
|
1.3x |
|
|
|
|
1.7x |
|
|
|
|
|
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding |
|
|
|
|
|
|
|
|
|
|
Funds Flow |
|
|
|
$ |
1.09 |
|
|
|
$ |
0.87 |
Net Income (Basic) |
|
|
|
|
0.20 |
|
|
|
|
(0.08) |
Weighted Average Number of Shares
Outstanding (000's) |
|
|
|
|
203,178 |
|
|
|
|
199,031 |
|
|
|
|
|
|
|
|
|
|
|
Selected Financial Results per
BOE(1)(2) |
|
|
|
|
|
|
|
|
|
|
Oil & Natural Gas
Sales(3) |
|
|
|
$ |
54.19 |
|
|
|
$ |
46.67 |
Royalties and Production Taxes |
|
|
|
|
(12.05) |
|
|
|
|
(9.52) |
Commodity Derivative Instruments |
|
|
|
|
(1.72) |
|
|
|
|
1.47 |
Operating Costs |
|
|
|
|
(10.01) |
|
|
|
|
(10.42) |
General and Administrative |
|
|
|
|
(2.31) |
|
|
|
|
(3.15) |
Share-Based Compensation |
|
|
|
|
(0.77) |
|
|
|
|
(0.70) |
Interest, Foreign Exchange and Other
Expenses |
|
|
|
|
(1.67) |
|
|
|
|
(2.19) |
Taxes |
|
|
|
|
(0.87) |
|
|
|
|
(0.16) |
Funds Flow |
|
|
|
$ |
24.79 |
|
|
|
$ |
22.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SELECTED OPERATING RESULTS |
|
|
Three months ended March 31, |
|
|
|
|
|
2014 |
|
|
|
|
2013 |
Average Daily
Production(2) |
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/day) |
|
|
|
|
37,760 |
|
|
|
|
38,321 |
|
NGLs (bbls/day) |
|
|
|
|
3,262 |
|
|
|
|
3,595 |
|
Natural gas (Mcf/day) |
|
|
|
|
346,794 |
|
|
|
|
271,602 |
|
Total (BOE/day) |
|
|
|
|
98,821 |
|
|
|
|
87,183 |
|
|
|
|
|
|
|
|
|
|
|
|
% Natural Gas |
|
|
|
|
58% |
|
|
|
|
52% |
|
|
|
|
|
|
|
|
|
|
|
Average Selling
Price(2)(3) |
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per bbl) |
|
|
|
$ |
91.48 |
|
|
|
$ |
78.52 |
|
NGLs (per bbl) |
|
|
|
|
66.30 |
|
|
|
|
58.58 |
|
Natural gas (per Mcf) |
|
|
|
|
4.93 |
|
|
|
|
3.10 |
|
|
|
|
|
|
|
|
|
|
|
Net Wells drilled |
|
|
|
|
30 |
|
|
|
|
25 |
(1) |
Non-cash amounts have been excluded. |
(2) |
Based on Company interest production volumes. See "Basis
of Presentation" section in the MD&A. |
(3) |
Net of oil and gas transportation costs, but before royalties
and the effects of commodity derivative instruments. |
|
|
|
Three months ended
March 31, |
Average Benchmark Pricing |
|
|
|
|
2014 |
|
|
|
|
2013 |
WTI crude oil (US$/bbl) |
|
|
|
$ |
98.68 |
|
|
|
$ |
94.37 |
AECO - monthly index (CDN$/Mcf) |
|
|
|
|
4.76 |
|
|
|
|
3.08 |
AECO - daily index (CDN$/Mcf) |
|
|
|
|
5.71 |
|
|
|
|
3.20 |
NYMEX natural gas - last day (US$/Mcf) |
|
|
|
|
4.94 |
|
|
|
|
3.34 |
USD/CDN exchange rate |
|
|
|
|
1.10 |
|
|
|
|
1.01 |
|
|
|
|
|
|
|
|
|
|
Share Trading Summary |
|
|
|
CDN* - ERF |
|
|
|
|
U.S.** - ERF |
For the three months ended March 31, 2014 |
|
|
|
(CDN$) |
|
|
|
|
US$) |
High |
|
|
$ |
22.37 |
|
|
|
$ |
20.18 |
Low |
|
|
$ |
18.45 |
|
|
|
$ |
17.15 |
Close |
|
|
$ |
22.10 |
|
|
|
$ |
20.03 |
*TSX and other Canadian trading data combined. |
**NYSE and other U.S. trading data combined. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 Dividends per
Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CDN$ |
|
|
|
|
US$(1) |
January |
|
|
|
$ |
|
|
|
|
0.09 |
|
|
|
$ |
|
|
|
|
0.08 |
February |
|
|
|
$ |
|
|
|
|
0.09 |
|
|
|
$ |
|
|
|
|
0.08 |
March |
|
|
|
$ |
|
|
|
|
0.09 |
|
|
|
$ |
|
|
|
|
0.08 |
First Quarter Total |
|
|
|
$ |
|
|
|
|
0.27 |
|
|
|
$ |
|
|
|
|
0.24 |
(1) |
US$ dividends represent CDN$ dividends converted at the
relevant foreign exchange rate on the payment date.
|
Production and Capital Spending |
|
|
|
|
|
|
|
|
|
|
Three
months ended
March 31, 2014 |
Crude Oil & NGLs
(bbls/day) |
|
|
|
|
Average Production
Volumes |
|
|
|
|
Capital Spending
($ millions) |
Canada |
|
|
|
|
19,117 |
|
|
|
|
$62 |
United States |
|
|
|
|
21,905 |
|
|
|
|
59 |
Total Crude Oil & NGLs (bbls/day) |
|
|
|
|
41,022 |
|
|
|
|
$121 |
Natural Gas (Mcf/day) |
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
|
151,627 |
|
|
|
|
$66 |
United States |
|
|
|
|
195,167 |
|
|
|
|
31 |
Total Natural Gas (Mcf/day) |
|
|
|
|
346,794 |
|
|
|
|
$97 |
Company Total (BOE/day) |
|
|
|
|
98,821 |
|
|
|
|
$218 |
Net Drilling Activity - for the three
months ended March 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
Horizontal Wells
Drilled |
|
|
Wells Pending
Completion/
Tie-in* |
|
|
Wells
On-stream** |
|
|
Dry & Abandoned
Wells |
Canada |
|
|
13.2 |
|
|
10.3 |
|
|
4.0 |
|
|
- |
United States |
|
|
5.3 |
|
|
5.3 |
|
|
1.8 |
|
|
- |
Total Crude Oil |
|
|
18.5 |
|
|
15.6 |
|
|
5.8 |
|
|
- |
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
7.3 |
|
|
3.7 |
|
|
3.4 |
|
|
0.3 |
United States |
|
|
4.1 |
|
|
4.1 |
|
|
2.3 |
|
|
- |
Total Natural Gas |
|
|
11.4 |
|
|
7.8 |
|
|
5.7 |
|
|
- |
Company Total |
|
|
29.9 |
|
|
23.4 |
|
|
11.5 |
|
|
0.3 |
*Wells drilled during the quarter that are pending potential
completion/tie-in or abandonment as at March 31, 2014. |
**Total wells brought on-stream during the quarter regardless
of when they were drilled. |
Asset Activity
We continued with an active capital program
during the first quarter of 2014, spending $218 million across our four core areas. A
total of 30 net horizontal wells were drilled, however, due to
extreme weather, only 11.5 net wells were placed on stream, down
significantly from the fourth quarter of 2013 when 19 net wells
were brought on-stream. Our U.S. activities were focused in
Fort Berthold, North Dakota and in
the Marcellus in northeast Pennsylvania where we continue to see strong
well performance.
Production from Fort Berthold was maintained
quarter over quarter despite the weather impact on production and
the timing of our completion activities. Only 1.8 net wells
were brought on-stream during the quarter. We are encouraged by the
sustained performance of wells drilled in the fourth quarter with
the new completion design. With 90 days of runtime, production
volumes continue to be ahead of our expectations. Subsequent to the
quarter, we brought on two wells from our second high density pad,
one well producing from the Bakken and one well producing from the
second bench of the Three Forks formation. In the first 26
days on production, the Bakken well has produced over 64,000
barrels of oil (on average almost 2,500 barrels per day) and the
second bench Three Forks well has produced over 60,000 barrels of
oil (on average 2,300 barrels per day). These are the best wells
we've drilled to date.
Production from the Marcellus continues to
surpass our expectations. Our drilling activities remain
concentrated in the Bradford and
Susquehanna areas where we are
seeing strong well performance. Similar to North Dakota, well completions in the
Marcellus continue to evolve with an increase in the number of
stages and the amount of sand per stage in the fracs. During
the quarter, 30 day initial production rates on wells drilled in
the Bradford and Susquehanna areas averaged 15 MMcf per day,
with two wells producing over 20 MMcf per day in their first 30
days.
We continued to invest in our waterflood
portfolio in Canada where we
advanced projects targeting the Ratcliffe, lower Mannville, Midale, Glauconitic, Cardium and Boundary Lake
plays. Our Canadian gas activities were directed to the
Wilrich and the Duvernay. We
drilled two wells in the Ansell area targeting the Wilrich, and in
the Willesden Green area we've drilled and completed two horizontal
wells targeting the Duvernay. We
expect to be in a position to discuss results from this activity
later in the year.
Crude Oil & Natural Gas Pricing
While the West Texas Intermediate benchmark
price for crude oil was only marginally higher quarter over
quarter, the more significant impact to Enerplus was a narrowing of
crude oil differentials in both Canada and the U.S and the strengthening of
the U.S. dollar. Our average realized sales price for our crude
increased by approximately 18% to $91.48 during the quarter with crude oil sales
generating approximately 70% of our corporate netback.
We also saw a significant improvement in the
price of natural gas in both Canada and the
United States during the quarter as winter weather caused
the largest storage withdrawals in 20 years across North America. Our realized sales price
for natural gas increased by over 50% quarter over quarter to
average $4.93 per Mcf.
The growth in our Marcellus production volumes
combined with higher natural gas prices has resulted in a
significant increase in Marcellus net operating income to
approximately $46 million during the
quarter. With capital spending of approximately $31 million, the Marcellus generated $15 million of free cash flow in the first
quarter. Based upon our outlook for production for the year, we
expect the Marcellus to generate cash flow in excess of our capital
spending in this area in 2014. Industry production from the
region continues to outpace takeaway capacity putting pressure on
the regional basis differentials. We believe this issue may persist
for another year or two. We have long-term contracts and/or
transportation to market points on approximately 75 - 85 MMcf per
day which is helping to mitigate our exposure to these widening
differentials however, roughly 55% of our volumes are not
contracted. Our Marcellus production realized an average discount
of US$0.88 per Mcf relative to the
NYMEX benchmark during the quarter. Higher production volumes and
stronger NYMEX prices are resulting in an increase in funds flow in
2014.
We continued to enter into hedge contracts on
our future crude oil and natural gas production in order to protect
a minimum level of cash flow. We have significant hedge
protection in place for the rest of 2014, with over 60% of our
crude oil production net of royalties hedged and just over 45% of
our natural gas production, net of royalties, hedged. However,
beyond 2014, the forward commodity price markets are in
backwardation on both crude oil and natural gas. We have
roughly 10% of our forecast oil and 20% of our forecast natural gas
hedged for 2015. We expect to layer in additional hedges over
time.
Board & Executive Appointments
Mr. Doug Martin,
Chairman of the Board of Enerplus, will be retiring at the end of
2014. Doug will step down from his position as Chairman
effective June 1, 2014 but will
remain a Board member until the end of the year to facilitate the
transition for the new Chairman. Doug joined the Board of
Directors of Enerplus in 2000, and since that time has helped steer
the Company through many commodity price cycles, changes within the
landscape of the oil and gas industry, and our evolution from a
trust to a corporation. I would like to thank Doug for his guidance
and support over the past 14 years.
Mr. Elliott Pew,
who is currently a Board member, will assume the position of
Chairman of the Board for Enerplus. Elliott is a geologist
and joined our Board in 2010, bringing a deep technical and
commercial background within the oil and gas industry. He currently
sits as the Chair of the Reserves Committee and a member of the
Audit Committee.
I would also like to thank Mr. David O'Brien who is retiring and will not be
standing for re-election as a Board member this year. David joined
our Board in 2008 and his guidance and direction have helped to
transform our business over the past five years. In planning
for these changes, we added two new Board members during the
quarter, Ms. Hilary
Foulkes and Mr. Michael
Culbert. Both individuals bring more than 30 years of
experience in the oil and gas industry and their knowledge and
expertise will enhance the strength of our Board.
I am also pleased to announce that Lisa Ower will be joining the executive team of
Enerplus in the position of Vice-President of Human Resources
effective May 20, 2014. Lisa
brings a wealth of experience to the role having held similar
positions within oil and gas production, mid-stream, manufacturing
and business service industries. I welcome our new Board
members and Lisa and look forward to their contributions in helping
shape our future.
Conference Call Details
A conference call hosted by Ian C.
Dundas, President and CEO will be held at 8:30AM MT (10:30AM
ET) today to discuss these results. Details of the
conference call are as follows:
Live Conference Call
Date: |
Friday, May 9, 2014 |
Time: |
8:30AM MT / 10:30AM ET |
Dial-In: |
647-427-7450
|
|
888-231-8191 (toll free) |
|
Passcode: 27538438 |
Audiocast: |
http://www.newswire.ca/en/webcast/detail/1335843/1476541 |
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 podcast of the conference call will be
available on our website for downloading. A telephone replay
will be available for 30 days following the conference call. The
telephone replay can be accessed at the following numbers:
Dial-In: |
416-849-0833
|
|
1-855-859-2056 (toll free) |
|
|
Passcode: |
27538438 |
Electronic copies of our First Quarter 2014 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.
Currency and Accounting Principles
All amounts in this news release are stated in Canadian
dollars unless otherwise specified. All financial information in
this news release has been prepared and presented in accordance
with U.S. GAAP, except as noted below under "Non-GAAP
Measures".
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 Information
Under U.S. GAAP oil and gas sales are generally presented net
of royalties and U.S. industry protocol is to present production
volumes net of royalties. Under Canadian industry protocol
oil and gas sales and production volumes are presented on a gross
basis before deduction of royalties. In order to
continue to be comparable with our Canadian peer companies, the
summary results contained within this news release presents our
production and BOE measures on a before royalty company interest
basis. 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.
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: Enerplus' asset portfolio; 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, expected
ultimate recoveries 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; future funds flow
and debt-to-funds flow levels; potential asset acquisitions and
dispositions; rates of return on Enerplus' capital program;
Enerplus' tax position; sources of funding of Enerplus' capital
program; 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 and resource 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 realized prices for Enerplus'
products; 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; 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 our AIF and Form 40-F described above).
The purpose of certain financial outlook information included
in this news release, including with respect to our 2014 guidance
for funds flow, is to communicate our current expectations as to
our performance in 2014. Readers are cautioned that it may
not be appropriate for other purposes. 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 "funds
flow", "adjusted payout ratio" and "netback" as measures to analyze
operating performance, leverage and liquidity. "Funds flow" is
calculated as net cash generated from operating activities but
before changes in non-cash operating working capital and asset
retirement obligation expenditures. "Adjusted payout ratio" is
calculated as cash dividends to shareholders, net of our stock
dividends and DRIP proceeds, plus capital spending (including
office capital) divided by funds flow. "Netback" is calculated as
oil and gas revenues after deducting royalties, operating costs and
transportation expenses.
Enerplus believes that, in addition to net earnings and other
measures prescribed by U.S. GAAP, the terms "funds flow", "adjusted
payout ratio", and "netback" 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 U.S. 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.
SOURCE Enerplus Corporation
Video with caption: "Video: Enerplus Announces Strong First
Quarter 2014 Results". Video available at:
http://stream1.newswire.ca/cgi-bin/playback.cgi?file=20140509_C7320_VIDEO_EN_40144.mp4&posterurl=http://photos.newswire.ca/images/20140509_C7320_PHOTO_EN_40144.jpg&clientName=Enerplus%20Corporation&caption=Video%3A%20Enerplus%20Announces%20Strong%20First%20Quarter%202014%20Results&title=ENERPLUS%20CORPORATION%20%2D%20Enerplus%20Announces%20Strong%20First%20Quarter%202014%20Results&headline=Enerplus%20Announces%20Strong%20First%20Quarter%202014%20Results