Enerplus Reports Strong 2013 Third Quarter Results, Acquisition of Additional Interests in the Marcellus and Sale of Montney

Enerplus Reports Strong 2013 Third Quarter Results, Acquisition of Additional 
Interests in the Marcellus and Sale of Montney Leases 
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 
third 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, Nov. 8, 2013 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) 
(NYSE: ERF) is pleased to announce results for the third quarter of 2013 that 
were once again ahead of expectations: 

    --  As a result of strong operational performance from our core
        areas in both Canada and the U.S. daily production during the
        third quarter averaged just under 88,000 BOE/day, up 8% from
        the same period last year.
    --  Production from our North Dakota assets continues to outperform
        our expectations, increasing by almost 20% during the quarter
        to a new record level of 18,000 BOE/day, achieving our 2013
        exit forecast for these properties one full quarter ahead of
    --  Year-to-date, production has averaged 88,318 BOE/day, up 9%
        from the same period a year ago in spite of divestments earlier
        in the year, and ahead of our revised guidance of 87,500
    --  We generated funds flow of $196 million ($0.98 per share) in
        the third quarter, up 45% from the third quarter of 2012.
    --  Our adjusted payout ratio during the quarter fell to 97% and
        year-to-date is 103%, a significant improvement from the same
        periods in 2012.
    --  The majority of our $146 million capital program during the
        quarter was allocated to our U.S. oil and Canadian waterflood
        oil assets, where 70% of our drilling program took place.  We
        are seeing improved cost performance in a number of our key
        operating areas, most notably in Fort Berthold and in the
    --  Our capital spending program remains on track with our original
        guidance for 2013 with a focus on maximizing crude oil and
        liquids production.  In the first nine months of 2013, we have
        spent only two thirds of our annual capital budget yet are
        exceeding our forecasts for both annual average and exit
        production, despite the sale of 1,300 BOE/day of non-core
    --  Operating and general and administrative costs per BOE are also
        on track and we are maintaining our guidance on both metrics
        for the full year.
    --  Our financial flexibility has also continued to improve in part
        from the growth in funds flow and also by our non-core asset
        sales. The trailing twelve month debt-to-funds flow ratio fell
        to 1.2 times at the end of September, compared to 1.9 times for
        the same period last year.
    --  On October 22, 2013, we announced an additional sale of
        non-core assets for approximately $105 million before closing
        adjustments which further focuses our operations, strengthens
        our balance sheet and improves our financial position.
    --  With more than 80% of our corporate netback derived from crude
        oil, we continue to hedge our exposure to crude oil prices to
        help protect our funds flow and ensure our on-going financial
        strength.  About 74% of our forecast crude oil production, net
        of royalties, is hedged at just over US$100/bbl for the
        remainder of 2013.  For the first half of 2014, we have price
        protection on 66% of our forecast crude oil production, net of
        royalties, at an average price of US$93.70/bbl, while 49% of
        our forecast crude oil production net of royalties for the
        second half of 2014 is hedged at US$92.73/bbl.  We have 25% of
        our 2014 forecast natural gas production, net of royalties,
        hedged at a price of $4.15/Mcf, before considering the
        acquisition of additional interests in the Marcellus.
    --  Subsequent to the quarter, we have entered into an agreement to
        purchase additional interests in our core Marcellus properties
        for approximately US$153 million before closing adjustments.
        The acquisition includes 17,000 net acres of land in the
        northeast region of Pennsylvania and approximately 42 MMcf/day
        of natural gas production. This acquisition will increase our
        exit production forecast from 88,000 BOE/day to 95,000 BOE/day.
    --  In addition, subsequent to the quarter, we have entered into an
        agreement to sell our Montney interests at Julienne Creek for
        $130 million. The sale includes 33,300 net acres of land with
        no associated production or reserves.

                      Three months ended Nine months ended September
                     September 30,                30,
                       2013      2012     2013               2012

Financial (000's)                                                

Funds Flow         $196,187  $134,980 $573,489           $444,233

Cash and Stock       54,405    53,394  162,199            247,988

Net Income           34,020  (63,466)   81,404              2,977

Debt Outstanding -  964,577 1,118,569  964,577          1,118,569
net of cash

Capital Spending    145,811   166,988  458,399            692,641

Property and Land    15,792     7,277   71,451             63,946

Property            124,462     3,112  197,086             55,636

Debt to Trailing       1.2x      1.9x     1.2x               1.9x
12 Month Funds

Financial per                                                    
Weighted Average
Shares Outstanding

Funds Flow            $0.98     $0.68    $2.87              $2.28

Net Income             0.17    (0.32)     0.41               0.02

Weighted Average    201,117   197,618  200,002            194,753
Number of Shares

Selected Financial                                               
Results per BOE(

Oil & Gas Sales(     $53.61    $43.30   $49.67             $44.10

Royalties           (11.91)    (8.61)  (10.46)             (8.74)

Commodity            (1.30)      1.06     0.42               0.11

Operating Costs     (10.58)   (12.32)  (10.52)            (11.00)

General and          (2.48)    (2.48)   (2.63)             (2.70)

Equity Based         (0.60)    (0.69)   (0.58)             (0.24)

Interest and Other   (1.78)    (2.56)   (1.78)             (1.40)

Taxes                (0.65)      0.29   (0.33)             (0.10)

Funds Flow           $24.31    $17.99   $23.79             $20.03

                         Three months ended Nine months ended September
                        September 30,                30,
                         2013       2012    2013                2012

Average Daily                                                       

  Crude oil            38,883     36,810  38,426              35,807

  NGLs (bbls/day)       2,985      3,538   3,357               3,644

  Natural gas         275,164    247,347 279,212             249,046

  Total (BOE/day)      87,729     81,573  88,318              80,959

  % Crude Oil &           48%        49%     47%                 49%
  Natural Gas Liquids

Average Selling Price                                               

  Crude oil (per bbl) $ 96.30    $ 76.41 $ 86.05             $ 78.72

  NGLs (per bbl)        49.88      47.81   51.48               54.88

  Natural gas (per       2.96       2.20    3.26                2.18

Net Wells drilled          15         17      50                  70

((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 Nine months ended September
                      September 30,                30,
                       2013       2012   2013                 2012

Average Benchmark                                                 

WTI crude oil       $105.82     $92.22 $98.14               $96.21

AECO- monthly index    2.82       2.19   3.16                 2.18

AECO- daily index      2.43       2.29   3.05                 2.11

NYMEX- monthly NX3     3.60       2.81   3.68                 2.62
index (US$/Mcf)

USD/CDN exchange       1.04       1.00   1.02                 1.00

SHARE TRADING SUMMARY                         CDN* - ERF U.S.** - ERF

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

High                                              $18.35       $17.69

Low                                               $15.29       $14.43

Close                                             $17.05       $16.59

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

2013 DIVIDENDS PER SHARE               
                          CDN$ US$((1))

First Quarter Total      $0.27    $0.27

Second Quarter Total     $0.27    $0.26

July                     $0.09    $0.09

August                   $0.09    $0.08

September                $0.09    $0.09

Third Quarter Total      $0.27    $0.26

Total Year-to-Date       $0.81    $0.79

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

                         Three months ended         Nine months ended
                         September  30, 2013       September 30, 2013
                         Average      Capital      Average      Capital

                  Production     Spending   Production     Spending
Crude Oil & NGLs
(BOE/day)                Volumes ($ millions)      Volumes ($ millions) 
Canada                    19,511          $35       21,035         $117 
United States             22,357           66       20,748          221 
Total Crude Oil &         41,868         $101       41,783         $338
NGLs (BOE/day) 
Natural Gas (Mcf/day)                                                   
Canada                   174,169          $22      179,503          $67 
United States            100,995           23       99,709           53 
Total Natural Gas        275,164          $45      279,212         $120
Company Total             87,729         $146       88,318         $458
NET DRILLING ACTIVITY - for the three months ended September 30, 2013 

                                          Pending                 Dry &
            Horizontal          Total Completion/       Wells Abandoned

Crude Oil        Wells    Wells Wells    Tie-in * On-stream**     Wells 
Canada             4.7        -   4.7         2.7         5.7         - 
United             6.6        -   6.6         5.3         3.2         -
Total Crude       11.3        -  11.3         8.0         8.9         -
Natural Gas                                                             
Canada             1.1        -   1.1         1.1           -         - 
United             2.8        -   2.8         2.6         2.2         -
Total              3.9        -   3.9         3.7         2.2         -
Natural Gas 
Company           15.2        -  15.2        11.7        11.1         -
*Wells drilled during the quarter that are pending potential completion/tie-in 
or abandonment as at September 30, 2013.
**Total wells brought on-stream during the quarter regardless of when they 
were drilled. 
U.S. Crude Oil 
We continued to allocate the majority of our capital spending to the Williston 
Basin, targeting light crude oil from the Bakken and Three Forks oil plays. 
During the quarter we invested $66 million at Fort Berthold, North Dakota, 
drilling 6.6 net horizontal wells and bringing 3.2 net horizontal wells on 
stream. During this period our North Dakota production grew by almost 2,900 
BOE/day to a record 18,000 BOE/day, a 19% increase from the last quarter. 
Combined with our Bakken production from Montana, our U.S. assets now account 
for more than half of Enerplus' total crude oil and liquids volumes. 
We are also seeing a significant improvement in well performance as we 
continue to optimize our completion design. Since the start of 2013, we have 
evolved our completions, moving from ceramic proppant to white sand proppant 
while increasing the number of frac stages by 40% and the amount of proppant 
per stage by over 200%. Despite the increase in frac size, our average cost 
per frac stage has decreased by approximately 15%. More significantly, the 
average 30 day cumulative initial production in our most recent Bakken and 
Three Forks wells is 80% or higher than the rates we were achieving at the 
start of 2013. 
We've drilled 10.6 net wells in the Bakken and 4.9 net wells in the first 
bench of the Three Forks to date in 2013 and continue to explore downspacing 
and testing of the lower benches of the Three Forks in order to expand our 
drilling inventory. 
Canadian Crude Oil 
Production from our Canadian oil assets averaged approximately 19,500 BOE/day, 
down from second quarter results of 21,300 BOE/day largely due to downtime at 
our Medicine Hat "Glauc C" property and the sale of non-core production 
earlier in the year. 
In Saskatchewan, results on the Ratcliffe trend continued to exceed our 
expectations. These assets attracted the highest share of investment amongst 
our waterflood properties during the quarter as we drilled 3.7 net horizontal 
wells in the area, brought 2 net wells on stream, and continued to invest in 
infrastructure to support our growing production in the region. Initial 
production volumes over the first 30 days from these wells are exceeding our 
type curve expectations by almost 60%, with rates of about 220 bbls/day. We 
plan on drilling 2 additional gross (1.3 net) wells offsetting these producers 
during the fourth quarter of 2013. 
U.S. Natural Gas 
Production from the Marcellus averaged 83 MMcf/day of natural gas during the 
quarter, ahead of our planned 2013 exit rate of 75 MMcf/day. We continue to be 
encouraged by strong well performance and as new wells come on stream, we 
expect to reach record production levels in the fourth quarter. We invested 
$23 million in the Marcellus during the quarter, which included the drilling 
of 2.8 net wells and bringing 2.2 net wells on stream. As a result of the 
production growth achieved year-to-date and an improvement in NYMEX natural 
gas prices year-over-year, funds flow has increased significantly from the 
Marcellus with approximately $48 million realized year-to-date. 
Additionally, well costs have also improved, declining approximately 20% from 
our original budget expectations. Given the on-going production growth from 
the Marcellus and lagging infrastructure expansion, differentials in the 
region continued to widen. Our long-term sales contracts on over 75% of our 
current production provided us with a degree of protection, resulting in our 
average realized Marcellus gas price being about US$0.52/Mcf below the NYMEX 
price during the quarter. Until infrastructure catches up to the burgeoning 
natural gas supply and new markets open up, we expect that wide differentials 
will persist in the region. 
Canadian Natural Gas 
Our Canadian natural gas activities continued to be focused in the Deep Basin 
region of Alberta where we are advancing our development plans in the Wilrich 
and continuing to delineate the Duvernay. 
Based upon the success of our drilling activity in the Wilrich, we acquired an 
additional 5,000 net acres in the Minehead area during the third quarter and 
have moved one dedicated rig to the region to execute our development plans. 
We plan to drill and complete one well in the fourth quarter and expect to 
spud a second well which will be completed in early 2014. 
As a result of recent drilling activity, Enerplus now has core data from three 
Duvernay vertical delineation test wells on varying sections of our leases in 
the Willesden Green area. The core analysis from these wells is positive and 
in our view supports a range of expected free condensate of 75 - 150 bbls per 
million cubic feet of natural gas over a significant portion of our acreage 
block. This data supports our current plan to drill a horizontal re-entry 
which is underway in one of the vertical tests. We expect to follow with 
another horizontal well with completion of both wells scheduled in 2014. 
Marcellus Acquisition and Montney Disposition Subsequent to the Quarter 
Consistent with our strategy to concentrate our portfolio in top tier assets 
in core areas, we have entered into agreements to add to our U.S. gas position 
in the Marcellus and to also sell our Montney interests in northeastern 
British Columbia. 
We have entered into an agreement to acquire additional working interests in 
17,000 net non-operated acres within our core properties in the Marcellus with 
current production of approximately 42 MMcf/day of natural gas for 
approximately US$153 million before closing adjustments. 
The acquisition increases our working interest in existing non-operated leases 
within the northeast region of Pennsylvania. Since entering the play in 
2009, well performance from this region has surpassed our expectations and 
increased our confidence in the productivity and economic viability of the 
Marcellus. Based upon the drilling results achieved to date, we expect 
ultimate recoveries ("EUR") of natural gas in the best areas to range from 10 
Bcf to 13.5 Bcf or higher per well. Close to half of the acquired leases are 
located in 10 Bcf or greater areas and virtually all of the value of the 
transaction has been attributed to these Tier 1 areas with approximately 44 
net future drilling locations. 
Approximately 60% of the total leases being acquired are currently held by 
production. With the majority of our existing core leasehold acreage now held 
by production, we have seen an improvement in drilling efficiencies to date in 
2013 that has resulted in lower well costs. Based upon our expected ultimate 
recoveries and current well costs of under $7 million, we expect top tier full 
cycle finding, development and acquisition costs of less than $1.00 per Mcf 
with attractive recycle ratios. 
Upon closing of the acquisition, Enerplus' core Marcellus acreage will total 
approximately 60,000 net acres. We plan to more fully outline our capital 
spending plans when we release our 2014 production and capital forecast in 
December of this year. 
The acquisition is expected to close at the end of November 2013 and as a 
result will increase our 2013 exit rate guidance from 88,000 BOE/day to 95,000 
BOE/day. This increase in natural gas production in 2014 is expected to 
provide us with the opportunity to continue selling non-core assets and 
high-grading our portfolio. Our 2013 annual average production and capital 
spending forecast is not expected to change materially as a result of the 
We have also entered into an agreement to sell our Montney interests at 
Julienne Creek for $130 million. While we believe the Julienne Creek asset 
offers significant scope and scale, the natural gas produced in this area is 
predominantly dry with very little associated natural gas liquids production. 
Our core assets in the Williston Basin, our waterfloods, the Marcellus and the 
Deep Basin (Wilrich and Duvernay) provide us with a deep inventory of future 
drilling prospects that offer more favourable economics and will enable us to 
grow production, reserves and cash flow in existing areas in both the near and 
long-term. Enerplus has invested approximately $50 million building our 
position in the Montney. The sale includes 33,300 net contiguous acres (100% 
working interest) with no current production or reserves, representing sale 
metrics of approximately $3,900 per acre. 
Our quarterly results once again reflect the benefits of our multi-year 
strategy to position Enerplus in top tier resource plays and develop them 
within a disciplined capital allocation and cost management framework. Our 
non-core property dispositions continue to help us improve our financial 
flexibility and enable us to focus our expertise and capital spending within 
our four core areas. These strategies are driving improved capital 
efficiencies and achieving sustainable, profitable growth and income for our 
investors. We plan to continue on this path of value creation for our 
Q3 Results Live Conference Call 
A conference call will be held at 9:00 AM MT (11:00 AM ET) to discuss these 
results. Details of the conference call are as follows: 
Date:       Friday, November 8, 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/1238557/1364449 
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:  79678943 
Electronic copies of our Q3 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 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 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 
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