Enerplus Increases 2013 Production Estimate and Forecasts 10% Production Growth in 2014

Enerplus Increases 2013 Production Estimate and Forecasts 10% Production 
Growth in 2014 
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. For information regarding the presentation 
of certain information in this news release, see "Currency, BOE and 
Operational Information" at the conclusion of this news release. 
CALGARY, Dec. 2, 2013 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) 
(NYSE: ERF) is pleased to announce that based upon continued strong 
operational performance during the months of October and November, we are 
increasing our annual average production forecast for 2013 to 89,000 BOE/day 
from 87,500 BOE/day. Production volumes during the fourth quarter are 
expected to average approximately 92,000 BOE/day due primarily to higher 
natural gas production. 
In addition, the Board of Directors of Enerplus has approved the capital 
program for 2014 which includes the following highlights: 

    --  We expect to deliver 10% production growth in 2014, targeting
        annual average production between 96,000 BOE/day and 100,000
    --  Crude oil production is expected to grow by 12%, resulting in a
        production mix of 48% crude oil and natural gas liquids and 52%
        natural gas.
    --  Capital spending is planned at $760 million, up 11% from 2013,
        with two thirds of our program directed to crude oil projects.
    --  Based upon our forecast exit volumes, capital efficiencies have
        significantly improved in 2013 to under $30,000/BOE/day. We
        expect to achieve similar capital efficiencies in 2014.
    --  We expect a reduction in both operating costs and general and
        administrative costs per BOE.

Production Growth

Based upon our capital spending plans, we forecast average production in 2014 
will range between 96,000 BOE/day and 100,000 BOE/day. The mid-point of this 
range reflects a 10% increase in production volumes year-over-year and 9% per 
share. Crude oil and natural gas liquids production is expected to increase 
by approximately 12%. We expect continued growth from our U.S. oil 
properties at Fort Berthold where production will increase by roughly 15% in 
2014, driving our light crude oil volumes to represent 67% of our total oil 
production. Natural gas liquids are expected to be approximately 4% of total 
production. Our total corporate natural gas production is expected to average 
just over 300 MMcf/day next year, up 7% from 2013, with the majority of the 
growth attributable to the Marcellus.

As a result of the growth in production from our Bakken/Three Forks and 
Marcellus properties, over 50% of our corporate production volumes will be 
attributable to our U.S. assets. Our production mix is expected to remain at 
48% crude oil and natural gas liquids and 52% natural gas. With the 
acquisition of additional interests in the Marcellus combined with the growth 
in our earlier stage plays in North Dakota and the Wilrich, our corporate 
production declinerate is expected to marginally increase to 25% in 2014 
from 24% in 2013.

Capital Spending

We are targeting a capital spending program of $760 million in 2014, up 11% 
from our 2013 capital forecast of $685 million. We plan to continue to focus 
our activities on oil projects with two thirds of our budget directed to our 
Bakken/Three Forks oil projects in the United States and our Canadian oil 
waterflood properties. The remainder of our budget will be directed to our 
core natural gas assets in the Marcellus and in the Deep Basin region as we 
move into development in the Wilrich and continue to evaluate the Duvernay.

The improvement in asset quality within our portfolio and a focused effort on 
reducing costs and driving operational performance has resulted in a 
significant improvement in capital efficiencies across our portfolio. 
Approximately $570 million is expected to be directed to drilling and 
development activities which we anticipate will deliver growth in production 
and reserves. We plan to allocate approximately $50 million to exploration and 
seismic activities.

2014 Capital Spending Breakdown by Activity             ($ millions) 

Development Drilling & Completions                              $570 

Plant/Facilities                                                $115 

Maintenance                                                      $25 

Exploration & Seismic                                            $50 

Total                                                           $760 

Financial Outlook

The sustainability of our business has improved significantly throughout 2013 
as a result of the growth in production volumes and improved capital 
efficiencies. We expect to build from this improvement in 2014 to deliver 
another year of profitable growth for our investors. We have recently entered 
into another agreement to sell $42 million of non-core assets in the U.S. 
representing approximately 2.5 MMcf/day of natural gas production associated 
with an over-riding royalty interest which we expect to close in early 
January. Our balance sheet has been strengthened by our divestment efforts 
which we expect will generate net proceeds, after acquisitions, of 
approximately $250 million. This has allowed us to increase our capital 
spending plans in 2014 while preserving our financial strength. We expect our 
2014 adjusted payout ratio will be approximately 120% before any acquisition 
and divestment activity.

We expect the recent weakness in crude oil differentials could persist into 
2014 and that the basis differential in the Marcellus may widen from the 
levels we realized during the third quarter. Based upon these assumptions 
and considering the backwardation in the forward crude oil market, funds flow 
is expected to grow by 3% in 2014 to approximately $775 million.

2014 Commodity Price & Differentials        

2014 Commodity Price Outlook*:                            
    West Texas Intermediate Crude Oil Price   US$92.80/bbl 
    NYMEX Natural Gas Price                    US$3.90/Mcf 
    AECO Natural Gas Price                       $3.45/Mcf 

Differential/Basis Outlook:                               
    Mixed Sweet Blend (MSW)                    ($8.00)/bbl 
    Western Canada Select (WCS)               ($25.00)/bbl 
    U.S. Bakken*                            (US$12.00)/bbl 
    Marcellus Basis*                         (US$0.75)/Mcf 

*Forward commodity price outlook as at November 26, 2013. The 
differential/basis outlook includes the impact of Enerplus' marketing and 
transportation arrangements.

Core Asset Activity

Our crude oil assets in the U.S. will continue to attract the largest 
percentage of our 2014 capital budget with $300 million to $325 million 
allocated to this core area. The majority of our spending is planned in the 
Fort Berthold region where we expect to continue running a two rig program 
targeting both the Bakken and the Three Forks. Approximately 20 net wells 
are expected to be drilled, completed and tied-in. During the fourth quarter 
of 2013, we drilled the first three wells of a seven well pad designed to test 
downspacing in the area. We also commenced drilling into the lower benches 
of the Three Forks to test the prospectivity of the lower zones.

Our low decline rate Canadian waterflood properties will continue to be an 
active part of our capital investment program. We plan to increase spending to 
approximately $160 million to $200 million in 2014 with a focus on drilling 
activities, advancement of our polymer projects at Giltedge and Medicine Hat 
and the implementation of new waterflood projects in Saskatchewan.

Capital spending in the Marcellus is expected to increase in 2014, ranging 
from $110 million to $130 million as a result of the additional working 
interests acquired in November 2013. Our spending will be focused in Bradford, 
Sullivan and Susquehanna counties where we have seen strong well performance 
throughout 2013. Based upon results to date, expected ultimate recoveries in 
these areas to range from 10 Bcf to over 13 Bcf of natural gas per well and 
provide compelling economics in the current natural gas price environment.

We plan to continue development of our assets in the Deep Basin region. We 
expect to continue our program in the Wilrich with 3 to 5 wells planned for 
the Ansell/Minehead area. We will also continue to advance our delineation 
activities in the Duvernay, completing one horizontal well drilled in late 
2013 and drilling and completing another horizontal well early in 2014.


We expect continued improvement in both operating costs and general and 
administrative costs in 2014. Operating costs are expected to average 
$10.25/BOE, down 4% from 2013. General and administrative expenses and cash 
equity based compensation are also expected to decrease, averaging $2.45/BOE 
and $0.25/BOE, down 9% and 58% respectively. We expect our average royalty 
rate will increase slightly to 23.5% of revenues due to the increase in 
production associated with our U.S. operations which have higher royalty rates 
and state fees than our Canadian operations. We have sufficient tax pools to 
shelter our cash flow in Canada for at least the next two years, and we 
forecast U.S. cash taxes of 3% to 5% of U.S. cash flows over the next two 


With the current crude oil price, over 75% of our expected 2014 funds flow 
will be derived from the sale of our crude oil and liquids production. As a 
result, our hedging strategy continues to be directed at protecting our oil 
volumes. We have approximately 51% of our expected 2014 oil volumes hedged, 
net of royalties, at a WTI price of US$93.28/bbl. We also have 27% of our 
expected 2014 natural gas production, net of royalties, hedged at a NYMEX 
price of US$4.14/Mcf and an additional 2% of our net natural gas production 
hedged at an AECO price of $3.96/Mcf.

2014 Forecast Guidance Summary*                                       

Capital Spending                                         $760 million 

Annual Average Production                    96,000 - 100,000 BOE/day 
     % liquids                                                    48% 

Operating Expense                                          $10.25/BOE 

General & Administrative Expense                            $2.45/BOE 

Cash Equity Based Compensation                              $0.25/BOE 

Royalties (including state fees)                                23.5% 

U.S. Cash Taxes                              3 - 5% of U.S. cash flow 

Cash Dividends                                            $220 million

Cash Dividends per share                                        $1.08 

Funds Flow                                               $775 million 

Funds Flow per Share                                             $3.81

Adjusted Payout Ratio                                            120% 


Based upon forward commodity prices, forecast costs and the Enerplus share 
price as of November 26, 2013 including the impact of hedging and does not 
include any acquisition or divestment activities not currently announced. 
Adjusted payout ratio is calculated as the sum of dividends paid to 
shareholders, net of participation in the Stock Dividend Plan plus capital 
expenditures divided by funds flow. See "Non-GAAP Measures" at the end of 
this release.
                                                   Est. effect on 2014 

2014 Sensitivities                                    Funds Flow/Share 

Change of $5.00/bbl WTI crude oil                                $0.15 

Change of $0.50/Mcf NYMEX natural gas                            $0.14 

Change of 1,000 BOE/day production                               $0.05 

Change of $0.01 in the US$/CDN$ exchange                         $0.05 

Electronic copies of our quarterly and annual results, news releases and 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 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 natural gas production volumes for 2013; our 
average realized crude oil and natural gas prices and future differentials; 
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 acquisitions 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 potential 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 and acquisitions; 
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 term "adjusted payout ratio" to analyze 
operating performance, leverage and liquidity. 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.

Enerplus believes that, in addition to net earnings and other measures 
prescribed by IFRS, the term "adjusted payout ratio" 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 GAAP 
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.

SOURCE  Enerplus Corporation 
Ian C. Dundas President & Chief Executive Officer Enerplus Corporation 
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CO: Enerplus Corporation
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