Enerplus Announces Strong 2013 First Quarter Results

This news release includes forward-looking statements and information within 
the meaning of applicable securities laws. Readers are advised to review the 
"Cautionary Note Regarding Forward-Looking Information and Statements" at the 
conclusion of this news release. Readers are also referred to "Information 
Regarding 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 
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, May 10, 2013 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) 
(NYSE: ERF) is pleased to announce that strong results for the first quarter 
have positioned us to achieve all of our operational targets for the coming 
year. Our portfolio of core assets in Canada and the U.S. continued to deliver 
profitable, organic growth. 

    --  We achieved average production of 87,183 BOE per day during the
        quarter.  This growth was in part driven by record production
        levels from the Marcellus and our Fort Berthold assets in North
    --  Most notably, our Marcellus production increased by
        approximately 40%, averaging 79 MMcf per day, up from 57 MMcf
        per day during the fourth quarter of 2012 as a result of a
        combination of strong well performance and increased tie-in
        activity at the end of the year.
    --  We closely managed our capital spending program during the
        first quarter as part of our strategy to improve the
        sustainability and profitability of our business. We invested
        $173 million during the quarter, approximately 25% of our
        capital spending budget for the year. The majority of our
        spending was once again directed to our crude oil projects in
        Canada and the U.S.  Approximately 45% of our program was
        directed to our Bakken development at Fort Berthold, North
        Dakota where we realized a reduction in well costs during the
        first quarter.  A total of 25 net wells were drilled with 17
        net wells brought on-stream.
    --  With the steady recovery of natural gas prices and support from
        our hedging program, we generated $173 million ($0.87 per
        share) in funds flow during the quarter.  Approximately 40% of
        our total production is now attributable to our U.S. assets,
        helping to mitigate the impact of wider Canadian heavy crude
        oil differentials.
    --  Our operating costs of $10.37/BOE were in line with our
        guidance, and while our general and administrative costs were
        higher than expected due to one-time charges associated with
        the departure of personnel, we continue to maintain our annual
        guidance for both these items.
    --  Our adjusted payout ratio was approximately 126%, a significant
        improvement from 254% a year ago due to the increase in funds
        flow, and reductions in our capital spending and monthly
    --  We have continued to keep our balance sheet strong with a debt
        to trailing 12 month funds flow ratio of 1.7 times at the end
        of the quarter. Approximately 70% of our $1 billion credit
        facility remains unutilized.
    --  We are also well positioned with hedges on approximately 65% of
        our net crude oil production and 35% of our net natural gas
        production for 2013 that we expect will provide us with
        significant funds flow protection in 2013.  This will help
        ensure we have the financial capacity to support our capital
        spending plans and our dividend.   We've also started to layer
        in additional hedges for 2014.
    --  We reported a net loss of $5.2 million for the quarter.
        Non-cash mark-to-market losses on our commodity derivatives as
        a result of higher forecast commodity prices at quarter end
        negatively impacted earnings.  This non-cash loss had no impact
        on funds flow.
    --  Subsequent to the quarter, we sold approximately 600 BOE per
        day of low working interest crude oil production in southeast
        Saskatchewan and Alberta for $58 million. These assets were not
        considered part of our core portfolio and their sale not only
        increases our financial flexibility but also improves the
        concentration of our asset base.
    --  We are also currently marketing a package of small non-core
        properties representing approximately 1,300 BOE per day of
        primarily oil production in order to further focus our
        portfolio and provide additional funding for our capital
    --  We are maintaining our annual average production guidance of
        82,000 to 85,000 BOE per day with an exit rate of 84,000 to
        88,000 BOE per day, despite the sale of 600 BOE/day.  Our
        guidance does not reflect the potential divestment activities
        mentioned above as we cannot predict the outcome of these

SELECTED OPERATING RESULTS            Three months ended March 31,
                                         2013                      2012

Average Daily Production                                          
    Crude oil (bbls/day)                38,321               34,074
    NGLs (bbls/day)                      3,595                4,002
    Natural gas (Mcf/day)              271,602              246,686
    Total (BOE/day)                     87,183               79,190
    % Crude Oil & NGLs                     48%                  48%

Average Selling Price((2))                                        
    Crude oil (per bbl)                $ 78.52              $ 85.91
    NGLs (per bbl)                       58.58                56.77
    Natural gas (per Mcf)                 3.10                 2.27

Net Wells Drilled                          25                   34
                                      Three months ended March 31,
                                         2013                 2012

Average Benchmark Pricing                                         

WTI crude oil (US$/bbl)                $94.37              $102.93

AECO natural gas - monthly index         3.08                 2.52

AECO natural gas - daily index           3.20                 2.15

NYMEX natural gas - monthly NX3 index    3.35                 2.77

USD/CDN exchange rate                    1.01                 1.00

SELECTED FINANCIAL RESULTS              Three months ended March 31,
                                             2013               2012

Financial (000's)                                                   

Funds Flow                               $172,596           $162,706

Cash and Stock Dividends                   53,785            105,995

Net Income/(Loss)                         (5,238)           (33,821)

Debt Outstanding - net of cash          1,125,762            902,937

Capital Spending                          172,944            317,066

Property and Land Acquisitions              3,967             33,020

Property Dispositions                       1,331             52,611

Asset Disposition gain/(loss)                 217             24,100

Debt to Trailing 12 Month Funds Flow         1.7x               1.6X

Financial per Weighted Average Shares                               

Funds Flow( )                               $0.87              $0.86

Net Income/(Loss)                          (0.03)             (0.18)

Weighted Average Number of Shares         199,031            189,844
Outstanding (000's)

Selected Financial Results per BOE((1))                             

Oil & Gas Sales((2))                       $46.67             $47.04

Royalties                                  (9.52)             (9.26)

Commodity Derivative Instruments             1.47             (1.48)

Operating Costs                           (10.42)             (9.81)

General and Administrative Expenses        (3.15)             (2.87)

Equity Based Compensation                  (0.70)             (0.22)

Interest and Other Expenses                (2.19)             (0.72)

Taxes                                      (0.16)             (0.10)

Funds Flow                                 $22.00             $22.58

((1) )Non-cash amounts have been excluded.
((2) )Net of oil and gas transportation costs, but before the effects
of commodity derivative instruments.

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

For the three months ended March              (CDN$)              (US$)
31, 2013

High                                          $15.50             $15.17

Low                                           $12.26             $12.03

Close                                         $14.84             $14.61

* TSX and other Canadian trading data combined.
**NYSE and other U.S. trading data combined.
    2013 Dividends per Share    

Payment Month                                   CDN$           US$((1))

January                                        $0.09              $0.09

February                                       $0.09              $0.09

March                                          $0.09              $0.09

First Quarter                                  $0.27              $0.27

((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, 2013

Crude Oil & NGLs                     Average          Capital Spending
(BOE/day)                  Production Volumes              ($ millions)

Canada                                 22,284                       $47

United States                          19,632                        77

Total Crude Oil &                      41,916                      $124
NGLs (BOE/day)

Natural Gas                                                            

Canada                                177,809                       $36

United States                          93,793                        13

Total Natural Gas                     271,602                       $49

Company Total                          87,183                      $173

Net Drilling Activity - for the three months ended March 31, 2013
                                         Wells                 Dry &

    Horizontal                     Pending              Abandoned
Crude              Vertical  Total  Completion/      Wells
Oil          Wells     Wells  Wells    Tie-in * On-stream**     Wells 
Canada        14.4       0.4   14.8        10.9         4.2         - 
United         3.7         -    3.7         2.8         7.7         -
Total         18.1       0.4   18.5        13.7        11.9         -
Canada         5.4         -    5.4         2.4         3.2         - 
United         0.8         -    0.8         0.8         1.7         -
Total          6.2         -    6.2         3.2         4.9         -
Company       24.3       0.4   24.7        16.9        16.8         -
*Wells drilled during the quarter that are pending potential
completion/tie-in or abandonment as at March 31, 2013.
** Total wells brought on-stream during the quarter regardless of
when they were drilled. 
U.S. Crude Oil 
Our U.S. crude oil production increased by approximately 7% during the first 
quarter of 2013 compared to the fourth quarter of 2012 due to the additional 
working interests purchased in the Sleeping Giant field in Montana in December 
2012 and continued drilling at Fort Berthold in North Dakota. We invested 
$77 million during the quarter in North Dakota targeting both the Bakken and 
Three Forks formations. We drilled three net operated long horizontal wells 
and participated in one non-operated well. In addition, five operated long 
horizontal wells, two short horizontal wells and one non-operated well were 
brought on-stream. 
The Fort Berthold region continues to be our most active development area 
within our portfolio. Our focus in 2013 is on improving our capital 
efficiencies and to continue to deliver growth in production and reserves. 
We initially budgeted $12.9 million for the drilling, completion and tie-in of 
a long horizontal well in 2013. During the quarter we realized savings in the 
order of 10% due primarily to lower costs for completion services and 
supplies. We are encouraged by these cost reductions and will work to extend 
them throughout the remainder of the year. In total, we plan to drill, 
complete and tie-in approximately 20 to 25 wells in 2013. 
U.S. Natural Gas 
Our U.S. natural gas production continued to grow during the first 
quarter.Marcellus production increased from approximately 57 MMcf per day 
during the fourth quarter of 2012 to average 79 MMcf per day during the 
quarter, well ahead of our expectations. While drilling activity slowed down 
as expected, we continue to benefit from better than expected well performance 
and increased tie-in activity late in 2012. Our Marcellus capital program 
this year is almost exclusively focused on the northeast region of 
Pennsylvania. With the recent strengthening in NYMEX natural gas prices, the 
economics of our capital program have improved significantly. Our Marcellus 
production is currently delivering a netback of approximately $2.50 per Mcf. 
Canada Crude Oil 
Capital spending activities to date in our Canadian crude oil portfolio were 
focused primarily at our Medicine Hat Glauconitic "C" property in Alberta and 
in Saskatchewan where we continued to drill into the Ratcliffe trend. 
At Medicine Hat, we continued with our waterflood optimization program 
drilling five injection and two producing wells into the field during the 
quarter. We also began work on a significant battery upgrade to support the 
growing production from this field. In addition to our waterflood program, 
we are encouraged by the response to our polymer injection project which began 
in mid-2012. We expect to make a decision on a second polymer project in 
this field by year end. 
In Saskatchewan, we drilled three horizontal wells targeting the Ratcliffe at 
our Freda Lake and Neptune properties during the quarter. We expect to 
complete and tie-in these wells during the second quarter. We have been very 
pleased with our drilling results in this area as we've grown production from 
approximately 700 BOE per day in 2010 to over 3,500 BOE/day during the 
quarter. After spring break-up, we expect to run one rig over the balance of 
the year and plan to continue to convert older vertical producing wells into 
water injection wells to optimize the waterfloods in this trend. 
Canada Natural Gas 
As planned, we have not invested significant capital in our Canadian natural 
gas assets in 2013 and as a result, daily production has continued to decline. 
We did however drill two horizontal wells targeting the Wilrich zone based 
upon the success of our 2012 drilling program in the Ansell area of Alberta. 
The first well is meeting our type curve assumptions with a 30-day initial 
production rate of approximately 6 MMcf per day of natural gas. The second 
well had an initial peak test rate of approximately 35 MMcf per day during the 
first 17 hours at 15.3 MPa in mid-March. The well has been on production since 
mid-April and production has averaged 17 MMcf per day since that time, well 
ahead of our expectations. 
Executive Changes 
On March 21, 2013, the Board of Directors of Enerplus announced that Gordon J. 
Kerr will be retiring as President & Chief Executive Officer effective June 
30, 2013. Ian C. Dundas, Executive Vice President & Chief Operating Officer, 
will succeed Mr. Kerr as President & Chief Executive Officer. Mr. Kerr will 
also be retiring as a Director of Enerplus on June 30, 2013, and Mr. Dundas 
will be appointed as a director at that time. 
Q1 Results Live Conference Call 
A conference call hosted by Mr. Gordon J. Kerr and Mr. Ian C. Dundas will be 
held today at 8:30 am MT (10:30 am ET) to discuss these results. Details of 
the conference call are as follows: 
Date:          Friday, May 10, 2013 
Time:           8:30 am MT (10:30 am ET) 
Dial-In:       647-427-7450   
           1-888-231-8191 (toll free) 
Audiocast:     http://www.newswire.ca/en/webcast/detail/1129683/1232193 
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:      24407425 
Minor Corrections to Year-End Filings 
Enerplus has filed a Notice that corrects certain minor and immaterial errors 
in the estimated net present value of future net revenues of oil and gas 
reserves, on an after-tax basis, presented in our 2012 year-end disclosure. A 
copy of the Notice is available on our SEDAR profile at www.sedar.com and our 
EDGAR profile at www.sec.gov. 
Currency and Production Amounts 
All amounts in this news release are stated in Canadian dollars unless 
otherwise specified. All oil, NGL and gas production volumes contained in this 
news release are presented on a "gross" basis, before deduction of royalties, 
as in accordance with Canadian practice. 
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; 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; and the performance of and future 
results from Enerplus' assets and operations, including anticipated production 
levels, decline rates and future growth prospects. 
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 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. 
Gordon J. Kerr
President & Chief Executive Officer
Enerplus Corporation 
For further information, please contact our Investor Relations  Department at 
1-800-319-6462 or emailinvestorrelations@enerplus.com. 
SOURCE: Enerplus Corporation 
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