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Enerplus Delivers Production Growth Through Second Quarter 2012

August 10, 2012

All financial figures are unaudited and in Canadian dollars (CDN$)
unless noted otherwise.  All financial statements have been prepared in
accordance with International Financial Reporting Standards (“IFRS”).

This news release includes forward-looking statements and information
within the meaning of applicable securities laws.  Readers are advised
to review “Forward-Looking Information and Statements” at the
conclusion of this news release.  Readers are also referred to “Notice
to U.S. Readers” and “Non-GAAP Measures” at the end of this news
release for information regarding the presentation of the financial and
operational information in this news release.  A full copy of our 2012
Second Quarter 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. 10, 2012 /CNW/ – Enerplus Corporation (“Enerplus” or the
“Corporation”) (TSX: ERF) (NYSE: ERF) is pleased to announce the
results for the second quarter of 2012. Highlights of the quarter were
as follows:

        --  Our operations delivered another quarter of growth with
            production averaging 82,108 BOE/day during the second quarter,
            up approximately 4% over our average volumes for the first
            quarter of 2012 and up almost 9% over the same period last
            year.

        --  Total crude oil volumes increased by 7% in the second quarter
            over the first quarter, with light oil production from Fort
            Berthold increasing by almost 35%.  Our light and medium crude
            oil now represents 76% of our total oil production, an
            improvement from 72% last year at this time. Total crude oil
            and natural gas liquids now represent 49% of our production
            volumes, a 6% increase over the second quarter of 2011.  Our
            Canadian natural gas production declined quarter over quarter
            as expected due primarily to the limited capital investment in
            our conventional and shallow gas assets. However, our gas
            production volumes in the Deep Basin region were higher as a
            result of our drilling success in the Ansell area earlier this
            year.

        --  We invested $209 million in exploration and development capital
            during the second quarter.  Approximately 80% of this spending
            was focused on our crude oil resource plays, specifically at
            Fort Berthold in the U.S. and on our waterflood assets in
            Canada. The bulk of our natural gas spending was focused in the
            Marcellus with our non-operated partners as we continued to
            focus on lease retention in the region.

        --  A total of 18.7 net wells were drilled during the quarter, of
            which approximately 75% were oil wells.  A total of 18.4 net
            wells were brought on stream, 67% of which were oil.

        --  Funds flow was approximately $147 million during the quarter
            ($0.74 per share), down 10% from the first quarter of 2012.
            Our growing production as well as our crude oil hedges helped
            offset the impact of lower commodity prices and wider crude oil
            differentials during the quarter. Our oil hedging program added
            $1.50/bbl of cash gains to our realized crude oil pricing
            during the quarter.

        --  Our trailing twelve month debt to funds flow ratio was 2.0x at
            June 30, 2012 and we had $680 million available on our $1
            billion bank credit facility.

        --  Operating costs were on track with expectations averaging
            $10.78/BOE for the second quarter and general and
            administrative costs (including equity based compensation) at
            $2.81/BOE were lower than expected due to lower costs
            associated with our long-term incentive plans.

        --  We continued to protect our balance sheet throughout the
            quarter in response to the further decline in natural gas
            prices as well as the sharp decline in crude oil prices. In May
            we closed a $405 million private placement of long-term, senior
            unsecured notes, the proceeds of which were used to reduce
            borrowings under our bank credit facility. These notes have
            terms ranging from seven to twelve years with attractive
            interest rates of approximately 4.4%.

        --  A Stock Dividend Program ("SDP") was implemented in June to
            allow all of our shareholders the option to elect to receive
            shares instead of a cash dividend.  We believe this program
            will provide an additional source of funding for our capital
            investment strategies.

        --  As a result of lower cash flow expectations due to the drop in
            commodity prices, we elected to reduce our monthly dividend
            from $0.18/share to $0.09/share commencing with our July
            dividend. We believe this reduction was necessary in order to
            strike a better balance between yield and growth for our
            investors and also preserve financial flexibility going
            forward.

        --  We have 18,500 bbls/day of oil production hedged at
            US$96.17/bbl for the remainder of 2012 and 14,500 bbls/day of
            oil production hedged at US$101.36/bbl for 2013. In response to
            the recent increase in natural gas prices, we've started to add
            hedge positions on our natural gas production for 2013,
            purchasing put protection which allows us to retain the upside
            price on approximately 23 MMcf/day of natural gas production
            hedged at $3.17/Mcf.

        --  We continue to progress on our plans for the partial sale
            and/or monetization of a portion of our early stage asset
            portfolio which includes the Duvernay, Montney and operated
            Marcellus.  We have retained a financial advisor and are
            actively marketing these assets.  In addition, our plans also
            include selling a portion of our equity portfolio and other
            non-core producing assets to help maintain our financial
            flexibility.

SELECTED FINANCIAL & OPERATING RESULTS


                       Three months ended June Six months ended June 30,
                                 30,

                            2012          2011      2012            2011

    Financial (000's)                                                   

      Funds Flow        $146,547      $132,441  $309,253        $293,665

      Cash and Stock      88,599        97,077   194,594         193,763
      Dividends

      Net Income         100,264       267,982    66,443         297,531

      Debt Outstanding 1,152,746       460,087 1,152,746         460,087
      - net of cash

      Capital Spending   208,587       145,165   525,653         319,609

      Property and        23,649        94,415    56,669         142,633
      Land
      Acquisitions

      Divestments           (87)       571,096    52,524         630,788

      Debt to Trailing      2.0x          0.7x      2.0x            0.7x
      12 Month Funds
      Flow

    Financial per
    Weighted Average
    Shares Outstanding

      Funds Flow           $0.74         $0.74     $1.60           $1.64

      Net Income            0.51          1.50      0.34            1.66

      Weighted Average   196,768       179,583   193,306         179,209
      Number of Shares
      Outstanding

    Selected Financial
    Results per BOE(1)

      Oil & Gas Sales     $42.07        $51.62    $44.51          $49.28
      (2)

      Royalties           (8.36)        (9.07)    (8.80)          (8.85)

      Commodity             0.68        (3.03)    (0.38)          (1.30)
      Derivative
      Instruments

      Operating Costs    (10.80)        (9.86)   (10.32)          (9.37)

      G&A and Equity      (2.57)        (3.16)    (2.83)          (3.21)
      Based
      Compensation

      Interest and        (0.90)        (0.89)    (0.81)          (1.82)
      Other Expenses

      Taxes               (0.51)        (6.30)    (0.31)          (3.22)

      Funds Flow          $19.61        $19.31    $21.06          $21.51


                       Three months ended June Six months ended June 30,
                                 30,

                          2012            2011    2012              2011

    Average Daily
    Production

      Crude oil         36,527          29,330  35,300            29,831
      (bbls/day)

      NGLs (bbls/day)    3,393           3,442   3,698             3,337

      Natural gas      253,126         255,665 249,905           253,584
      (Mcf/day)

      Total (BOE/day)   82,108          75,383  80,649            75,433

      % Crude Oil &        49%             43%     48%               44%
      Natural Gas
      Liquids

    Average Selling
    Price(2)

      Crude oil (per   $ 74.36          $90.92 $ 79.93            $84.23
      bbl)

      NGLs (per bbl)     60.11           66.20   58.30             63.35

      Natural gas (per    2.06            3.86    2.17              3.88
      Mcf)

      USD/CDN exchange    1.01            0.97    1.01              0.98
      rate

    Net Wells drilled       19              14      53                40

    (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 June 30, 2012     (CDN$)        (US$)

    High                                         $22.57       $22.78

    Low                                          $11.67       $11.35

    Close                                        $13.08       $12.87

    *  TSX and other Canadian trading data combined.

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

    2012 Dividends Per Share(2)             

    Payment Month                CDN$ US$(1)

    First Quarter Total         $0.54  $0.54

    April                       $0.18  $0.18

    May                          0.18   0.17

    June                         0.18   0.18

    Second Quarter Total        $0.54  $0.53

    Total Year-to-Date          $1.08  $1.07

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

    (2)   The dividend has been reduced to $0.09 per share effective for
          the July 20, 2012 payment.

                             Three months ended        Six months ended
                                June 30, 2012            June 30, 2012

                             Average      Capital    Average      Capital
                          Production     Spending Production     Spending
    Play Type                Volumes ($ millions)    Volumes ($ millions)

    Tight Oil (BOE/day)       18,329         $139     16,986         $301

    Crude Oil Waterflood      16,953           27     16,539           70
    (BOE/day)

    Conventional Oil           4,883            2      4,840           14
    (BOE/day)

    Total Crude Oil           40,165         $168     38,365         $385
    (BOE/day)

    Marcellus Shale Gas       36,868           29     32,493           90
    (Mcfe/day)

    Other Natural Gas        214,790           12    221,209           51
    (Mcfe/day)

    Total Gas (Mcfe/day)     251,658          $41    253,702         $141

    Company Total             82,108         $209     80,649         $526

Net Drilling Activity – for the three months ended June 30, 2012


                                                   Wells
                 Horizontal Vertical   Total     Pending                 Dry &
                      Wells    Wells   Wells Completion/       Wells Abandoned
    Play Type       Drilled  Drilled Drilled     Tie-in* On-stream**     Wells

    Tight Oil           7.2        -     7.2         7.2         8.0         -

    Crude Oil           5.8      1.0     6.8         6.8         4.4         -
    Waterflood

    Conventional          -        -       -           -           -         -
    Oil

    Total Crude        13.0      1.0    14.0        14.0        12.4         -
    Oil

    Marcellus           3.5        -     3.5         3.5         3.0         -
    Shale Gas

    Other               1.2        -     1.2         0.2         3.0         -
    Natural Gas

    Total Gas           4.7        -     4.7         3.7         6.0         -

    Company            17.7      1.0    18.7        17.7        18.4         -
    Total

    *  Wells drilled during the quarter that are pending potential
       completion/tie-in or abandonment

    ** Total wells brought on-stream during the quarter regardless of when
       they were drilled

OPERATIONS UPDATE

Tight Oil – Fort Berthold, ND

Production from the Fort Berthold region continued to increase through
the second quarter as planned. We spent $138 million on development
capital, drilling 7.0 net wells and bringing 8.0 net wells on-stream.
Production averaged 11,700 BOE/day, up almost 35% from 8,700 BOE/day
during the first quarter of this year and slightly ahead of
expectations.

We continued to pursue measures to control our costs in the Fort
Berthold region. Operated spending continues to be ahead of budget as
we have not been able to see a meaningful reduction in well costs
year-to-date. As part of our effort to manage costs, we have eliminated
our two least efficient operated drilling rigs and are now running two
rigs which we expect will effectively execute the remainder of our
operated 2012 capital program. Non-operated activity has also increased
significantly as our partners are drilling more than we originally
anticipated.  In conjunction with our drilling activities,
infrastructure build-out (compression, metering and pipelines) in the
region has continued at a brisk pace as we tie-in more wells and
capture the associated natural gas volumes, thereby reducing our
emissions. We originally expected to fund this tie-in activity through
a mid-stream third party however we have been funding these capital
costs directly year-to-date. We continue to evaluate fee-based
arrangements for the tie-in capital linked to the gathering agreements
now in place. We now have approximately 66% of our wells connected to
pipeline.

We expect spending to moderate in the second half of 2012. Year-to-date,
we’ve drilled 16.5 net horizontal wells at Fort Berthold, 82% of which
have been long horizontals.

Crude Oil Waterfloods

Production from our waterflood properties grew by 5% quarter over
quarter as a result of our development activities. Despite wet
conditions through spring break-up at our Medicine Hat waterflood
property, we were able to complete our plans on our polymer project and
began injecting polymer into five injector wells in the latter part of
May.  We also drilled 2.9 net producer wells and 1.4 net injector wells
at Medicine Hat as part of our on-going waterflood optimization
program. Production from this field was up 20% over the first quarter
and is currently producing at the highest volume achieved since 1997. 
We also restarted our drilling program in southeast Saskatchewan
targeting the Ratcliffe with two horizontal wells brought on stream
during the quarter.

Marcellus

We continued to invest with our non-operated partners in the Marcellus
during the second quarter spending $29 million and participating in
drilling 3.5 net wells with 3.0 net wells brought on-stream.  Our
capital program has been designed to maximize lease retention in this
region throughout 2012.  Some of our partners have slowed completion
and tie-in activities including reducing the number of frac stages per
well, in an effort to preserve capital. As a result of these
activities, we believe production may be lower than originally expected
in the latter half of the year exiting 2012 at approximately 60
MMcf/day compared to our original estimate of 70 MMcf/day. Our
Marcellus production increased to 37 MMcf/day in the second quarter.

Update on 2012 Guidance

We continue to manage spending levels throughout our operations in order
to offset higher spending in the Fort Berthold region.  While we expect
capital spending to be lower in the second half of 2012, the increased
capital expenditures at Fort Berthold have increased our overall
capital spending program for 2012. We now expect full year capital
expenditures to be approximately $850 million, up from our original
estimate of $800 million. 

We are increasing our annual average production guidance from 83,000
BOE/day to 83,500 BOE/day however we are maintaining our exit
production guidance of 88,000 BOE/day. The additional spending at Fort
Berthold is expected to add oil production to our exit volumes, however
we expect this will be offset by lower production associated with
slower completion and tie-in activity in the Marcellus region.  We
continue to expect our oil and liquids production weighting to be
approximately 50% as we exit 2012. We are maintaining our guidance for
full year operating costs at $10.40/BOE however, general and
administrative costs are now expected to average $3.30/BOE down from
our previous forecast of $3.55/BOE due to reduced costs associated with
our long-term incentive programs.

Outlook

I am very pleased with the progress we continue to make on the
operational front. We are increasing production quarter over quarter
and have successfully shifted our production mix to be close to 50%
crude oil and natural gas liquids. Although weaker commodity prices and
widening differentials have presented challenges for ourselves and the
industry in general, we’ve taken a number of steps to manage our
balance sheet and continue to pursue additional funding sources to help
improve our liquidity beyond 2012.  Based upon our success and the
outlook for commodity prices, we will adjust our growth targets and
capital spending levels as needed in order to ensure we have sufficient
liquidity and deliver a competitive return to our investors.

I am also pleased to announce that Mr. Chris Stephens has been promoted
to the position of Vice-President, Canadian Assets.  Mr. Stephens is
accountable for the implementation of the Canadian asset strategy and
performance and has been with Enerplus since June of 2008.  In
addition, Mr. Gordon Love has been promoted to the position of
Vice-President, Technical and Operations Services and will oversee our
services and field operations in Canada as well as Facility Asset
Management and Supply Chain Management for both our U.S. and Canadian
operations. Mr. Love joined Enerplus in 2010.  Both Mr. Stephens and
Mr. Love report to Mr. Ray Daniels, Senior Vice-President of Operations
for Enerplus.

Gordon J. Kerr
President & Chief Executive Officer
Enerplus Corporation

NOTICE TO U.S. READERS

The oil and natural gas reserves information contained in this news
release has generally been prepared in accordance with Canadian
disclosure standards, which are not comparable in all respects to
United States or other foreign disclosure standards. Reserves
categories such as “proved reserves” and “probable reserves” may be
defined differently under Canadian requirements than the definitions
contained in the United States Securities and Exchange Commission (the
SEC“) rules. In addition, under Canadian disclosure requirements and
industry practice, reserves and production are reported using volumes
prior to deduction of royalty and similar payments. The practice in the
United States is to report reserves and production using net volumes,
after deduction of applicable royalties and similar payments. Canadian
disclosure requirements require that forecasted commodity prices be
used for reserves evaluations, while the SEC mandates the use of an
average of first day of the month price for the 12 months prior to the
end of the reporting period.

BARRELS OF OIL EQUIVALENT AND CUBIC FEET OF GAS EQUIVALENT

This news release also contains references to “BOE” (barrels of oil
equivalent) and “cfe” (cubic feet of gas 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, and one barrel
of oil to six thousand cubic feet of gas (1 bbl: 6 Mcf) when converting
oil to cfes. BOEs and cfes 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 crude oil as compared to
natural gas is significantly different from the energy equivalency of
6:1, utilizing a conversion on a 6:1 basis may be misleading as an
indication of value. 

Flow test results and initial production rates: A pressure transient
analysis or well-test interpretation has not been carried out and thus
certain of the test results provided herein should be considered to be
preliminary until such analysis or interpretation has been done. Test
results and initial production rates disclosed herein may not
necessarily be indicative of long-term performance or of ultimate
recovery.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This news release contains certain forward-looking information and
statements (“forward-looking information“) within the meaning of applicable securities laws. The use of any of
the words “expect”, “anticipate”, “continue”, “estimate”, “guidance”,
“objective”, “ongoing”, “may”, “will”, “project”, “should”, “believe”,
“plans”, “intends”, “budget”, “strategy” and similar expressions are
intended to identify forward-looking information. In particular, but
without limiting the foregoing, this news release contains
forward-looking information pertaining to the following: Enerplus’
strategy to deliver both income and growth to investors and Enerplus’
related asset portfolio; future capital and development expenditures
and the timing and allocation thereof among our resource plays and
assets; future development and drilling locations and plans; the
performance of and future results from Enerplus’ assets and operations,
including anticipated production levels and decline rates; future
growth prospects, acquisitions and dispositions; the volumes and
estimated value of Enerplus’ oil and gas reserves and contingent
resource volumes and future commodity price and foreign exchange rate
assumptions related thereto; the life of Enerplus’ reserves; the volume
and product mix of Enerplus’ oil and gas production; securing necessary
infrastructure and third party services; future cash flows and
debt-to-cash flow levels; returns on Enerplus’ capital program; future
costs and expenses; and future issuances of debt or equity, including
the terms and timing thereof and the expected use of proceeds
therefrom.

The forward-looking information contained in this news release reflect
several material factors and expectations and assumptions of Enerplus
including, without limitation: that Enerplus will conduct its
operations and achieve results of operations as anticipated; that
Enerplus’ development plans will achieve the expected results; the
general continuance of current or, where applicable, assumed industry
conditions; the continuation of assumed tax, royalty and regulatory
regimes; the accuracy of the estimates of Enerplus’ reserve and
resource volumes; commodity price and cost assumptions; the continued
availability of adequate debt and/or equity financing and cash flow to
fund Enerplus’ capital and operating requirements as needed; and the
extent of its liabilities. Enerplus believes the material factors,
expectations and assumptions reflected in the forward-looking
information are reasonable but no assurance can be given that these
factors, expectations and assumptions will prove to be correct.

The forward-looking information included in this news release is not a
guarantee of future performance and should not be unduly relied upon.
Such information involves known and unknown risks, uncertainties and
other factors that may cause actual results or events to differ
materially from those anticipated in such forward-looking information
including, without limitation: changes in commodity prices; changes in
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
reserve and resource volumes; limited, unfavourable or a lack of access
to capital markets; increased costs; a lack of adequate insurance
coverage; the impact of competitors; reliance on industry partners; a
failure to complete planned assets dispositions on the terms
anticipated or at all; 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 described above).

The forward-looking information contained in this news release speak
only as of the date of this news release, and none of Enerplus or its
subsidiaries assumes any obligation to publicly update or revise them
to reflect new events or circumstances, except as may be required
pursuant to applicable laws.

NON-GAAP MEASURES

In this news release, we use the term “funds flow” to analyze operating
performance, leverage and liquidity. We calculate funds flow based on
cash flow from operating activities before changes in non-cash
operating working capital and decommissioning liabilities settled, all
of which are measures prescribed by International Financial Reporting
Standards (“IFRS“) and which appear in our Consolidated Statements of Cash Flows.

Enerplus believes that, in addition to net earnings and other measures
prescribed by IFRS, the term “funds flow” is a useful supplemental
measure as it provides an indication of the results generated by
Enerplus’ principal business activities. However, this measure is not a
measure recognized by IFRS and does not have a standardized meaning
prescribed by IFRS. Therefore, this measure, as defined by Enerplus,
may not be comparable to a similar measure presented by other issuers.

 

 

 

 

 

 

 

 

 

SOURCE Enerplus Corporation


Source: PR Newswire