Enerplus 2013 Second Quarter Results Ahead of Expectations

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 
second 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, Aug. 9, 2013 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) 
(NYSE: ERF) is pleased to announce that results for the second quarter of 2013 
are ahead of expectations: 

    --  Funds flow increased by almost 20% during the quarter compared
        to the first quarter of 2013, and 40% compared to the second
        quarter last year, to approximately $205 million, driven by
        higher production and a significant improvement in our netback
        as a result of higher realized commodity prices.
    --  Our adjusted payout ratio decreased to 89% in the quarter. On a
        year-to-date basis, our adjusted payout ratio is approximately
        106% before considering the proceeds of our divestment
        activities and reflects the improved sustainability of our
    --  Operations in both Canada and the U.S. continued to perform
        ahead of our expectations.  Daily production was up 10% over
        the second quarter of 2012 and 3% higher than the first quarter
        of 2013, averaging 90,037 BOE/day.  For the first six months of
        2013, daily production has averaged 88,618 BOE/day,
        significantly ahead of our expectations.
    --  Natural gas production in both Canada and the U.S. showed the
        most notable increases as a result of successful drilling
        activity in the Wilrich and continued strong performance in the
    --  Drilling and development activities in Canada slowed during the
        quarter, resulting in a 20% decrease in capital spending
        compared to the first quarter of 2013. Approximately $140
        million was invested across our portfolio with over 80% of our
        spending dedicated to our oil properties in both Canada and the
        U.S. In the first half of 2013, we've invested approximately
        $313 million in development capital which is about 45% of our
        full year budget.  Our North Dakota operations continued to
        attract the majority of our capital investment given the strong
        economic returns from this region.
    --  Our hedging program generated approximately $21 million
        year-to-date in cash gains.
    --  Operating costs and general and administrative costs continue
        to track our expectations.
    --  We increased the concentration in our Canadian waterflood
        portfolio through the acquisition of an additional 50% working
        interest in the Pouce Coupe Boundary Lake light oil pool in
        Alberta and also added to our acreage positions in our core
        areas in North Dakota and Pennsylvania.
    --  As previously announced, we have also either sold or entered
        into agreements to sell approximately 1,300 BOE/day of non-core
        producing assets, net of acquisitions. In addition, we have
        also closed the sale of infrastructure assets in the Fort
        Berthold region for approximately $34 million.
    --  Year-to-date, including agreements signed, we have sold
        approximately $192 million in non-core assets and invested
        approximately $55 million in acquistions in our core areas.
    --  As a result of non-core asset sales and the increase in funds
        flow, our trailing 12 month debt-to-funds flow ratio also
        improved, falling to 1.6 times at the end of the quarter.

FINANCIAL        Three months ended June
RESULTS                    30,             Six months ended June 30,
                      2013          2012        2013            2012


Funds Flow        $204,706      $146,547    $377,302        $309,253

Cash and Stock
Dividends           54,009        88,599     107,794         194,594

Net Income          52,622       100,264      47,384          66,443

Debt Outstanding
- net of cash    1,133,048     1,152,746   1,133,048       1,152,746

Capital Spending   139,644       208,587     312,588         525,653

Property and
Acquisitions        51,692        23,649      55,659          56,669

Dispositions        71,293          (87)      72,624          52,524

Debt to Trailing
12 Month Funds
Flow                  1.6x          2.0x        1.6x            2.0x

Financial per
Weighted Average

Funds Flow( )        $1.02         $0.74       $1.89           $1.60

Net Income            0.26          0.51        0.24            0.34

Weighted Average
Number of Shares
(000's)            199,825       196,768     199,430         193,306

Results per BOE(

Oil & Gas Sales(
(2))                $48.65        $42.07      $47.68          $44.51

Royalties           (9.93)        (8.36)      (9.73)          (8.80)

Instruments           1.11          0.68        1.29          (0.38)

Operating Costs    (10.55)       (10.80)     (10.48)         (10.32)

General and
Administrative      (2.29)        (2.76)      (2.71)          (2.82)

Equity Based
Compensation        (0.45)          0.19      (0.57)          (0.01)

Interest and
Other Expenses      (1.38)        (0.90)      (1.78)          (0.81)

Taxes               (0.18)        (0.51)      (0.18)          (0.31)

Funds Flow          $24.98        $19.61      $23.52          $21.06

SELECTED OPERATING   Three months ended June   Six months ended June
RESULTS                                  30,                     30,
                        2013            2012      2013          2012

Average Daily                                                       
    Crude oil         38,066          36,527    38,193        35,300
    NGLs (bbls/day)    3,497           3,393     3,546         3,698
    Natural gas      290,841         253,126   281,275       249,905
    Total (BOE/day)   90,037          82,108    88,618        80,649
    % Crude Oil &        46%             49%       47%           48%
    Natural Gas

Average Selling                                                     
    Crude oil (per   $ 82.95         $ 74.36   $ 80.74       $ 79.93
    NGLs (per bbl)     45.64           60.11     52.16         58.30
    Natural gas (per    3.70            2.06      3.41          2.17
    Net Wells             10              19        35            53

((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 June   Six months ended June 30,
                      2013             2012     2013               2012

Average Benchmark                                                      

WTI crude oil       $94.22           $93.49   $94.30             $98.21

AECO- monthly index   3.59             1.83     3.34               2.18

AECO- daily index     3.53             1.90     3.37               2.02

NYMEX- monthly NX3    4.09             2.26     3.72               2.52
index (US$/Mcf)

USD/CDN exchange      1.02             1.01     1.02               1.01

Share Trading Summary                    CDN* - ERF       U.S.** - ERF

For the three months ended June 30, 2013     (CDN$)              (US$)

High                                         $16.95             $16.47

Low                                          $12.93             $12.60

Close                                        $15.54             $14.79

* TSX and other Canadian trading data combined.
**NYSE and other U.S. trading data combined.

2013 Dividends per Share                                                

Payment                                                                 US$(
Month                                                       CDN$        (1))

First                                                                  $0.27
Total                                                      $0.27

April                                                      $0.09       $0.09

May                                                        $0.09       $0.09

June                                                       $0.09       $0.08

Second                                                                 $0.26
Total                                                      $0.27

Total                                                                  $0.53
Year-to-Date                                               $0.54

((1)) (US$ dividends represent CDN$ dividends converted at the relevant
      foreign exchange rate on the payment date.)

                  Three months ended           Six months ended
Production and
Capital Spending        June  30, 2013               June 30, 2013 
                Average        Capital      Average        Capital 
             Production       Spending   Production       Spending
Crude Oil & NGLs
(BOE/day)           Volumes   ($ millions)      Volumes   ($ millions) 
Canada               21,339            $35       21,809            $82 
United States        20,224             78       19,930             155 
Total Crude Oil                       $113       41,739           $237
& NGLs (BOE/day)     41,563 
Natural Gas                                                           
Canada              186,569            $10      182,214             $46 
United States       104,272             17       99,061             30 
Total Natural                          $27      281,275            $76
Gas (Mcf/day)       290,841 
Company Total                         $140       88,618           $313
(BOE/day)            90,037 


Net Drilling Activity - for the three months ended June 30, 2013  
                                            Pending                     Dry &

    Horizontal   Vertical   Total   Completion/         Wells   Abandoned
Oil          Wells      Wells   Wells      Tie-in *   On-stream**       Wells 
Canada         3.6          -     3.6           3.6           8.6           - 
United         4.7          -     4.7           1.5           6.1           -
Total          8.3          -     8.3           5.1          14.7           -
Canada           -          -       -             -           1.1           - 
United         2.1          -     2.1           2.1           1.8           -
Total          2.1          -     2.1           2.1           2.9           -
Company       10.4          -    10.4           7.2          17.6           -
*Wells drilled during the quarter that are pending potential completion/tie-in 
or abandonment as at June 30, 2013.
** Total wells brought on-stream during the quarter regardless of when they 
were drilled. 
U.S. Crude Oil 
Production from our U.S. crude oil assets increased slightly during the second 
quarter primarily due to drilling activity at Fort Berthold, North Dakota. We 
invested approximately $78 million drilling 4.7 net long horizontal wells and 
bringing 6.1 net horizontal wells on-stream with the majority of the wells 
brought on late in the quarter. Service and supply costs continue to be lower 
than our original expectations with a 10% savings realized on well costs 
year-to-date. Production from Fort Berthold continues to be on track with our 
expectations and averaged just over 15,000 BOE/day during the quarter. 
Canadian Crude Oil 
Production from our Canadian crude oil properties was down slightly from the 
first quarter, averaging approximately 21,300 BOE/day due to a slow-down in 
development activity and the sale of non-core production. The majority of our 
activities were focused on drilling additional wells in our waterflood 
properties at Medicine Hat and Giltedge. We also acquired an incremental 50% 
working interest in the Pouce Coupe South Boundary Lake waterflood property 
during the quarter, taking our working interest to approximately 100%. This 
property has a very low historical decline rate of roughly 5% with an average 
netback of approximately $50/BOE and we believe there is future upside 
potential through incremental drilling and waterflood optimization. 
U.S. Natural Gas 
U.S. natural gas production grew by more than 10% during the quarter, 
averaging approximately 104 MMcf/day. The majority of our U.S. gas 
production is from the Marcellus region in northeast Pennsylvania which 
produced on average 88 MMcf/day of natural gas during the quarter, up 11% from 
the first quarter. We continue to see strong well performance, particularly in 
the Bradford and Susquehanna areas where approximately 90% of our Marcellus 
capital is being allocated. As a result of the growth in production volumes 
and increasing natural gas prices, we have seen a significant increase in 
funds flow from our Marcellus operations in 2013 generating approximately $34 
million in funds flow year-to-date which has fully funded our 2013 capital 
spending in this region. 
Canadian Natural Gas 
Based upon the success of our drilling activity to date in the Wilrich, we 
plan to drill two additional horizontal development wells in the Ansell area 
in the latter half of the year with an expected on-stream early in 2014. We 
also plan to begin drilling two Montney horizontal wells at our 
Cameron/Julienne property in northeast British Columbia in the fourth 
quarter. The first of two vertical wells testing the Duvernay is currently 
underway. We expect to finish drilling both of these wells in the fourth 
quarter of 2013. 
Hedging Update 
As the majority of our funds flow comes from crude oil revenues, we continue 
to enter into additional WTI hedge positions in order to provide greater 
certainty of our future funds flow. We now have 75% of our remaining 2013 
crude oil production, after royalties, hedged at a price of US$100.35 per 
barrel and we have 56% of our expected 2014 crude oil production volumes, net 
of royalties, hedged at an average price of US$93.06 per barrel. We also 
have 32% of our remaining 2013 natural gas volumes, after royalties, hedged at 
an average price of $3.51 per Mcf. For 2014, we have 24% of our expected net 
natural gas production hedged against the NYMEX benchmark at a price of 
US$4.17 per Mcf with an additional 2% hedged against the AECO benchmark at a 
price of $3.85 per Mcf. 
Guidance Update 
As a result of lower drilling activity during the second quarter and planned 
turn-around activity, along with the impact of non-core property divestments, 
we expect to see a decline in production volumes during the third quarter. 
Although production has exceeded expectations year-to-date, we are not 
increasing our annual average production guidance beyond 85,000 BOE/day given 
our plans to continue to rationalize additional assets over the course of the 
year. If we are unable to complete additional divestments, we would expect 
our annual average and exit production to potentially exceed our current 
guidance. As the majority of the sales completed to date have been crude oil 
properties and with the growth in our natural gas production from our core 
assets, we now expect our crude oil and liquids production will represent 
approximately 48% of our total volumes in 2013. 
We remain on track to meet our other guidance targets for 2013, with the 
exception of cash equity-based compensation expenses which we are increasing 
to $0.60 per BOE from $0.45 per BOE given the increase in our share price to 
date in 2013. 
U.S. Filing Status 
As a result of the increase in value of our U.S. assets combined with the 
majority of our shareholders residing in the U.S., effective January 1, 2014, 
we anticipate that Enerplus will no longer qualify as a "foreign private 
issuer" under U.S. securities regulations. Enerplus would then be considered 
a U.S. domestic issuer and would become subject to U.S. domestic reporting 
requirements from that date forward. 
The change in filing status would not impact our operations, but would change 
the way in which we report and file our operating and financial results. For 
example, our financial statements would be prepared under U.S. Generally 
Accepted Accounting Principles. The U.S. GAAP financial statements will 
satisfy our Canadian filing obligations and IFRS statements will no longer be 
prepared. We expect the most significant differences between U.S. GAAP and 
IFRS for Enerplus will relate to the accounting for our oil and gas assets, 
specifically, impairment calculations and the accounting treatment for 
dispositions. Other differences may include the accounting for decommissioning 
liabilities and differences in balance sheet presentation. We expect these 
changes may impact earnings, however, we do not expect a material change in 
most of our key performance indicators such as funds flow, debt levels, 
capital spending, operating costs, general and administrative expenses, 
netbacks or adjusted payout ratio. Sales revenues and production volumes 
would be reported on a net (after royalty) basis however we will also provide 
supplementary disclosures for gross sales revenue and volumes to facilitate 
comparison with Canadian peers. In addition to filing our reserves under 
Canadian National Instrument 51-101 standards, our reserves information would 
also be prepared and filed under the U.S. SEC standards. 
Enerplus has undergone significant change in our portfolio and strategy over 
the past few years. The impact of these changes is being reflected in our 
improved operational performance. Based upon our results for the first half 
of 2013 and including the non-core asset sales we've made year-to-date, we 
expect to meet or beat our guidance this year. We've achieved significant 
growth in production and funds flow and our balance sheet remains strong. As 
a result of this performance, we are delivering profitable growth and income 
to our investors. 
Q2 Results Live Conference Call 
A conference call hosted by Mr. Ian C. Dundas will be held at 9:00 am MT 
(11:00 am ET) to discuss these results. Details of the conference call are as 
Date:       Friday, August 9, 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/1199387/1315153

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:  20555284


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 

See "Non-GAAP Measures" below.


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 gas production volumes for 2013; 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 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 expected 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; 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.


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 
For further information, please contact our Investor Relations  Department at 
1-800-319-6462 or emailinvestorrelations@enerplus.com. 
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