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. 10, 2012 /CNW/ – Enerplus Corporation (“Enerplus”) (TSX:
ERF) (NYSE: ERF) announces guidance for 2013 and the acquisition of
additional low decline, light oil interests in Montana.

Acquisition of Bakken Interests in Montana

Consistent with our strategy of consolidating core positions within our
portfolio, Enerplus has agreed to enter into an agreement to acquire an
additional 20% working interest in our operated leases in the Sleeping
Giant area in the Elm Coulee field in Richland County, Montana for
approximately US$131 million (approximately US$121 million after
estimated closing adjustments of US$10 million). By investing
approximately half of the proceeds from the sale of our Manitoba
assets, we expect to replace the sold production, improve the
concentration of our asset base and improve our operating metrics.

The acquisition is complementary to our existing operations in Sleeping
Giant where we currently own an operated 70% working interest. This is
a mature light oil property with an average decline rate of 14%. Our
internal reserves assessment has identified a total of 6.2 million BOE
of proved plus probable reserves associated with the acquisition and
daily production of approximately 1,550 BOE/day (both of which are
weighted 80% to light crude oil). The transaction has attractive
acquisition metrics of 4.2 times annual funds flow after estimated
closing adjustments, $23.00/BOE of proved plus probable reserves
including future development capital and is expected to be 4% accretive
to funds flow in 2013 (2% on a debt-adjusted basis). This light oil
property has current netbacks of approximately $50/BOE with low
operating costs averaging $5.50/BOE in 2012. We do not expect any
increases in general and administrative costs as a result of the
acquisition.

We believe there is additional upside potential in this field through
production optimization, refracs and limited infill drilling. With
approximately 400 million barrels of original oil in place on our
operated leases, we are also evaluating the potential for enhanced oil
recovery schemes as the current reserve bookings results in a 14%
recovery factor. The total crude oil recovered to date is approximately
8%. We anticipate closing the acquisition mid-December, after which
Enerplus will own a 90% working interest in the operated leases with
production of approximately 7,300 BOE/day. We expect a modest level of
capital spending at Sleeping Giant in 2013.

Guidance for 2013

In addition, the Board of Directors of Enerplus has approved a capital
spending program for 2013. Highlights of the program are as follows:

• We expect to deliver funds flow growth of over 11% in 2013. On a
  debt-adjusted basis, funds flow is expected to grow by 6% per share.
  This growth, along with a current yield of approximately 8%, aligns
  with our long-term business strategy of providing an attractive total
  return to investors comprised of both growth and income.
• We are targeting a capital program of $685 million, 20% lower than our
  estimated spending in 2012, which more closely balances our capital
  spending and dividends with funds flow.
• We expect production to average between 82,000 BOE/day and 85,000
  BOE/day, which at the mid-point of the range, would represent a 2%
  increase over our estimated 2012 average daily production after
  adjusting for our recent acquisition and divestment activities. Based
  upon current cost structures and the commodity price outlook for both
  crude oil and natural gas in 2013, we believe this is an appropriate
  level of production growth. We plan to continue to pursue acquisition
  opportunities in core areas and rationalize non-core assets to enhance
  our portfolio and profitability.
• With an expected increase in funds flow, combined with a reduced capital
  spending program and maintenance of our dividend, we expect our
  adjusted pay-out ratio to improve to approximately 130% net of our
  Stock Dividend Program (“SDP”). We intend to continue to focus our
  portfolio and improve our cost structure to enhance the sustainability
  of our business.
• We have successfully managed our balance sheet throughout 2012. We
  continue to pursue joint venture opportunities and non-core asset sales
  in an effort to allow us to enhance shareholder value. Our debt to
  funds flow ratio is expected to be 1.9 times at the end of 2013 based
  upon current forward market commodity prices, our estimate of
  production and costs and before any additional acquisition or
  divestment activities
• We remain committed to providing a meaningful dividend to investors.
  Given the steps we have proactively taken to improve the sustainability
  of our business including the sale of non-core assets and reducing our
  capital spending plans, we currently have no plans to adjust our
  monthly dividend. We will continue to review dividend levels in the
  context of commodity prices, capital spending, cost structures and debt
  levels.

Summary Guidance*

	2012E	2013E
Capital Expenditures ($millions)	$850	$685
Annual Average Daily Production (BOE/day)	82,000	82,000 – 85,000
Oil & Liquids Weighting	49%	50%
Exit Production (BOE/day)	85,000 – 88,000	84,000 – 88,000
Oil & Liquids Weighting	49%	50%
Adjusted Payout Ratio**	190%	130%
Debt/Funds Flow at Year-End	1.8x	1.9x

*Assumptions:
Based upon forward commodity prices and forecast costs as of November
26, 2012 including the impact of hedging and does not include any
acquisition or divestment activities not previously announced. Based
upon our current capital spending plans for Q42012, forecast YE2012
debt is approximately $1.1 billion
** 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”
below.

Capital Spending

We are targeting a capital spending program of $685 million in 2013.
Through this spending, we expect to offset our corporate production
decline rate of approximately 24% and grow production modestly by 2%.
Approximately 85% of our program is currently planned to be directed to
oil and liquids rich natural gas projects, with over 75% directed
specifically to crude oil projects. Our capital program is based upon
delivering a minimum internal rate of return of 25%.

The Fort Berthold region of North Dakota has delivered significant light
oil production growth for Enerplus over the past two years. Through our
2012 drilling program, we have effectively managed our lease
expirations in the region and grown production to approximately 14,000
BOE/day during the month of November. We expect to reduce capital
spending by 25% to approximately $340 million next year as we focus on
improving our costs and efficiencies while still delivering production
growth. We’re forecasting average daily production growth of 30% next
year over expected 2012 average volumes. We plan to run a two-rig
program targeting both the Bakken and Three Forks formations and expect
to drill, complete and bring on-stream between 20 to 25 net wells at
Fort Berthold next year. The majority of these wells will be long
horizontal wells. We expect non-operating spending will represent
approximately 15% of our total spending in this area in 2013.

We expect to continue to invest in our oil waterflood properties in
Canada next year targeting a capital spending program of approximately
$160 million similar to 2012 levels. Under our planned spending, we
will continue to invest in drilling projects at Freda Lake in
Saskatchewan and Medicine Hat, Giltedge and Pembina in Alberta.
Waterflood optimization will remain a focus area as we continue to
balance drilling activity with our pressure maintenance programs to
effectively manage performance from these fields. Our volumes are
expected to be modestly impacted next year as we plan to curtail
approximately 400 BOE/day and 2 MMcf/day of natural gas at Pembina
early in the first quarter as part of this on-going program. We
anticipate that these volumes will be recovered over the course of the
next 6 to18 months and believe this will result in better long-term
recoveries. Finally, we plan to continue to advance on our existing
polymer projects at Medicine Hat and Giltedge. Overall we have been
encouraged by the performance of these projects. We plan to evaluate
performance over the course of next year and if performance continues
as we expect, would be in a position to consider expansion of the
program.

We plan to reduce capital spending in the Marcellus region by over 50%
to $80 million in 2013 directed to non-operated drilling projects in
the northeast region of Pennsylvania. Through this drilling program,
we expect to have retained the majority of what we believe to be core
non-operated acreage by the end of 2013. We expect continued
production growth from 55 MMcf/day currently to roughly 75 MMcf/day as
we exit 2013. Given the lower operating costs associated with this
production ($0.75/Mcf) and NYMEX based pricing, operating netbacks are
currently averaging approximately $2.00/Mcf. As a result, our Marcellus
production is expected to contribute to the increase in funds flow in
2013. We anticipate that 25% of our corporate natural gas production
volumes will be attributable to the Marcellus in 2013. We continue to
see positive results from our drilling program despite the delays
associated with infrastructure in the region.

We expect to continue investing in the Deep Basin region in 2013 on both
our operated and non-operated leases. Approximately $75 million will be
allocated to develop natural gas projects with associated liquids.
Based upon our success in the Wilrich play in Alberta in 2012, we are
planning an additional 3 to 5 wells next year.

Approximately 75% of our capital spending is expected to be directed to
drilling projects with around 90 net wells planned in 2013 with 80 net
wells brought on-stream throughout the year. The program is weighted to
the first half of the year with about one third of the capital planned
for investment in the first quarter. We expect that approximately 75%
of our capital spending will be directed to properties where we control
the pace and level of spending. We expect to allocate less than $30
million to delineate our undeveloped acreage in 2013.

2013 Capital Spending Breakdown	2013E ($ millions)
Development Drilling & Completions	$555
Plant/Facilities	$70
Maintenance	$30
Exploration & Seismic	$30
Total	$685

We expect to review our capital spending program on a regular basis
throughout the year in the context of prevailing commodity prices,
economic conditions and cost structures and may modify our spending
plans as required.

Production Growth

We are forecasting average daily production of 82,000 to 85,000 BOE/day
in 2013, a 2% increase over our estimated 2012 average daily production
after adjusting for our recent acquisition and divestment activities.
Crude oil production is expected to increase in 2013, averaging 38,000
bbls/day, up 2.5% from 2012. Oil production in the Fort Berthold region
of North Dakota is expected to grow again in 2013 but at a slower pace
than in 2012 given the reduced capital spending plans. Natural gas and
natural gas liquids volumes are expected to remain flat year-over-year.
The additional natural gas volumes associated with our 2012 Marcellus
drilling program are anticipated to come on-stream during the first
half of 2013 and are expected to offset the decline in our Canadian
conventional natural gas properties. Total natural gas production is
expected to average approximately 250 MMcf/day. Approximately 75% of
our total production will be operated by Enerplus.

As we plan to spend a greater proportion of our capital spending in the
first half of 2013, and given the variability and timing of our
non-operated spending, we expect exit production in 2013 to range
between 84,000 and 88,000 BOE/day.

Current Daily Production

Daily production during the month of November 2012 is estimated to be
86,000 BOE/day. Given the slow-down in drilling activity, we expect
December production will be similar.

Expenses

Operating costs are expected to average $10.70/BOE, unchanged from 2012
and general and administrative expenses are expected to average
$3.40/BOE, up marginally from 2012. We expect our average royalty rate
will increase slightly in 2013 due to an improvement in the natural gas
price outlook and the increase in production associated with our U.S.
operations which have higher royalty rates than our Canadian
operations. Royalties are expected to average 21% of revenues. We have
sufficient tax pools to shelter our funds flow in Canada in 2013 and
beyond, and we expect U.S. cash taxes to be approximately 3% of our
U.S. cash flow.

2013 Forecast Expenses	2013E
Operating Costs ($/BOE)	$10.70
Cash General & Administrative Expenses ($/BOE)	$3.15
Non-cash General & Administrative Expenses ($/BOE)	$0.25
Royalties	21%
Cash Taxes ($MM)	$12
Interest Expense ($MM)	$65

Funds Flow Growth

Based upon current forward commodity prices, we expect funds flow to
grow in 2013 by 6% per debt-adjusted share. Improvements in natural gas
prices as well as the growing NYMEX based natural gas production in the
Marcellus are key factors contributing to this expected growth. Our
hedging program is expected to provide support to this increase as we
have 57% of our anticipated net oil production volumes hedged at a
price of US$100.84 per barrel and 12% of our projected net natural gas
volumes swapped at a fixed price of $3.63/Mcf and a further 11% of our
projected net natural gas production hedged with put protection at
$3.17/Mcf. We estimate that approximately 75% of the net operating
income will be generated from our oil plays.

2013 Sensitivities	Est. effect on 2013 Funds Flow/Share
Change of $5.00/bbl WTI crude oil	$0.14
Change of $0.50/Mcf AECO natural gas	$0.18
Change of 1,000 BOE/day production	$0.05
Change of $0.01 in the US$/CDN$ exchange rate	$0.05

Financial Flexibility

We have preserved our financial flexibility throughout 2012 through the
sale of non-core assets, issuance of long-term debt and a reduction in
our dividend. We expect to exit 2012 with a debt-to-funds flow ratio
of 1.8 times which we anticipate is at the low end of our peer group.
Our adjusted pay-out ratio is expected to drop significantly in 2013 to
approximately 130% net of the participation in the SDP. In the context
of current commodity prices, we expect a debt-funded shortfall of $200
million (funds flow including participation in the SDP less capital
spending and dividends). We expect to continue to divest of non-core
assets to offset our funding shortfall and to improve the concentration
and focus within our portfolio. Our debt to funds flow ratio is
expected to be 1.9 times at the end of 2013 before consideration of any
joint venture, asset sale or acquisition activities.

Gordon J. Kerr
President & Chief Executive Officer
Enerplus Corporation

Currency, BOE and Operational Information

All dollar amounts or references to “$” in this news release are in
Canadian dollars unless specified otherwise. Enerplus has adopted the
standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may
be misleading particularly if used in isolation. A BOE conversion ratio
of 6 Mcf:1 BOE is based on an energy equivalency conversion method
primarily applicable at the burner tip and does 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. Unless
otherwise stated, all oil and gas production information and estimates
are presented on a gross basis, before deducting royalty interests.

Cautionary Note Regarding Forward-Looking Information and Statements

This news release contains certain forward-looking information and
statements (collectively, “forward-looking information”) within the
meaning of applicable securities laws. The use of any of the words
“expect”, “anticipate”, “continue”, “estimate”, “budget”, “guidance”,
“objective”, “ongoing”, “may”, “will”, “project”, “should”, “believe”,
“plans”, “intends”, “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 and statements pertaining to the following: future capital
spending amounts, the timing and locations of such spending and the
types of projects on which such capital will be spent; future growth in
production, and cash flow and other anticipated growth opportunities; a
financing strategy to fund anticipated capital expenditures, including
funds raised from our Stock Dividend Plan; future oil, natural gas
liquids and natural gas prices and production levels (including
anticipated 2013 average daily and exit production rates), the product
mix and sources of such production, and production decline rates;
future drilling activities and results and undeveloped land
acquisitions; future capital efficiencies, corporate netbacks and cash
flow levels; rates of return from our investments; the expected
ultimate recovery of oil or gas from a particular well; operating
costs, general and administrative expenses and royalty expenses; sales
of our non-core properties and the redeployment of proceeds realized
therefrom; dividend payments made by Enerplus and the related adjusted
payout ratio; the timing and payment of future taxes; our planned
commodity risk management program; and future liquidity, debt levels,
financial capacity and resources; and the completion of our proposed
acquisition of additional working interests in Montana, including the
terms and timing thereof.

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 achieve operational,
production and drilling results as anticipated; anticipated production
decline rates; the general continuance of current or, where applicable,
assumed industry conditions; commodity prices will remain within
Enerplus’ expected range of forecast prices, being the current forward
market prices; availability of adequate cash flow, debt and/or equity
sources to fund Enerplus’ capital and operating requirements as needed
and to pay dividends to shareholders as anticipated; the continuance of
existing and, in certain circumstances, proposed tax and royalty
regimes; availability of willing buyers for the properties proposed to
be disposed of; that capital, operating, financing and third party
service provider costs will not exceed Enerplus’ current expectations;
availability of third party service providers (including drilling rigs
and service crews) and cooperation of industry partners; certain
foreign exchange rate and other cost assumptions. Enerplus believes the
material factors, expectations and assumptions reflected in the
forward-looking information are reasonable at this time 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;
unanticipated operating or drilling results or production declines;
potential redeployment of available funding to alternative projects;
changes in tax or environmental laws or royalty rates; increased debt
levels or debt service requirements; insufficient available cash to pay
dividends as currently anticipated; inaccurate estimation of or changes
to estimates of Enerplus’ oil and gas reserve and resource volumes and
the assumptions relating thereto; limited, unfavourable or no access to
debt or equity capital markets; increased costs and expenses; a
shortage of third party service providers; the impact of competitors;
reliance on industry partners; an inability to agree to terms with
potential buyers of investments or assets that may be disposed of; and
certain other risks detailed from time to time in Enerplus’ public
disclosure documents including, without limitation, those risks
identified in our MD&A for the year ended December 31, 2011 and in
Enerplus’ Annual Information Form dated March 9, 2012 for the year
ended December 31, 2011, copies of which are available on Enerplus’
SEDAR profile at www.sedar.com and which also form part of Enerplus’ annual report on Form 40-F for
the year ended December 31, 2011 filed with the United States
Securities and Exchange Commission, a copy of which is available at www.sec.gov.

The forward-looking information contained in this news release speaks
only as of the date of this news release, and Enerplus assumes no
obligation to publicly update or revise such information to reflect new
events or circumstances, except as may be required pursuant to
applicable laws.

Any financial outlook or future oriented financial information in this
news release, as defined by applicable securities legislation, has been
approved by management of Enerplus. Such financial outlook or future
oriented financial information is provided for the purpose of providing
information about management’s reasonable expectations as to the
anticipated results of its proposed business activities for 2013.
Readers are cautioned that reliance on such information may not be
appropriate for other purposes.

Non-GAAP Measures

Enerplus utilizes the following terms for measurement within this news
release that do not have a standardized meaning or definition as
prescribed by IFRS and therefore may not be comparable with the
calculation of similar measures by other entities

We use the term “adjusted payout ratio” to measure operating
performance, leverage and liquidity. We calculate “adjusted payout
ratio” is calculated as dividends paid to shareholders net of the
participation in the Stock Dividend Plan plus capital expenditures
divided by funds flow. The term “adjusted payout ratio” does not have a
standardized meaning or definition as prescribed by IFRS and therefore
may not be comparable with the calculation of similar measures by other
entities.

Netback is used to measure operating performance and is calculated by
subtracting Enerplus’ expected royalties and operating costs from the
anticipated revenues in respect of the relevant properties. The term
“netback” does not have a standardized meaning or definition as
prescribed by IFRS and therefore may not be comparable with the
calculation of similar measures by other entities.

SOURCE Enerplus Corporation