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News Releases


December 17, 2010

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. 17 /CNW/ - Enerplus Resources Fund ("Enerplus") (TSX - ERF.un, NYSE - ERF) today announced capital spending and operational guidance for 2011 and a preliminary outlook for 2012 that is expected to result in organic growth in production and reserves.  Throughout the past 18 months, Enerplus has captured over 475,000 net acres of prospective land primarily in two of the most economic plays in North America - the Bakken light oil play and the Marcellus gas play.  In addition, the sale of over 10,000 BOE/day of non-core assets as well as our Kirby oil sands lease has helped finance our acquisition activities and improved our operational focus and profitability. We have a foundation of mature, low production decline properties that complement our new growth assets that we believe provides a stable platform of production and cash flow from operating activities from which to grow. We believe our strategy provides a compelling investment opportunity comprised of yield and growth. Initially a large portion of our total return will be comprised of dividend yield, but as the development of our growth plays accelerates, we expect to complement our dividend with repeatable annual growth in production and reserves per share.


  • 2011 capital spending is anticipated to increase by over 25% to $650 million with 65% projected to be invested in oil projects. We expect to focus approximately 85% of our spending on our Bakken, Waterflood and Marcellus resource plays. A minimum level of capital investment is planned for our natural gas assets with the majority directed to our non-operated Marcellus interests to further delineate the resource and preserve our lease positions.  We also expect a similar level and allocation of spending in 2012.

  • Production is expected to grow by 10% - 15% over the next two years, exiting 2012 in the range of 86,000 - 90,000 BOE/day.  Crude oil volumes are expected to increase more than 20% over the next two years and will represent approximately 48% of total volumes by the end of 2012.

  • In 2011, we expect annual production to average 78,000 - 80,000 BOE/day, increasing to 80,000 - 84,000 BOE/day by year end. Given the longer lead time to production associated with a majority of our capital spending in the Marcellus and the Bakken, up to 40% of the production associated with our 2011 drilling program will not come on stream until the remaining completion and tie-in capital is expended in 2012.

  • Light oil production is expected to grow by over 20% as we exit 2011. Natural gas volumes are expected to remain essentially flat throughout the year however we anticipate shallow gas production will decline and be replaced by more profitable natural gas from the Marcellus.

  • Based upon the current forward commodity price markets, we project cash flow from operating activities ("cash flow") will grow by approximately 15% by 2012 as a result of increased production, the higher oil weighting in the portfolio and higher crude oil prices. Cash flow in 2011 is expected to be relatively unchanged from 2010 levels despite selling 10,000 BOE/day of production throughout 2010. This is mainly a result of the increase in crude oil volumes and the increased price outlook for crude oil.

  • We expect rates of return on our oil projects to range from 35% to over 100% based on current forward prices.  Returns on our natural gas investments, the majority of which are being made to delineate and retain land positions, are expected to exceed 15% in today's natural gas price. We are targeting finding and development costs on our oil properties of approximately $20/bbl and $2.00/Mcf on our natural gas assets.

  • Approximately $140 million of our 2011 expenditures are expected to be directed to natural gas delineation activities in areas such as the Marcellus and the Western Canadian Deep Basin. We do not expect this spending to result in meaningful production additions in 2011 but will provide valuable insight into the viability and opportunity within new play areas.

  • We intend to continue to distribute a significant portion of the cash flow that is generated from our operations and plan to maintain our monthly dividend rate of $0.18/share in our forecast for the next two years. However, we will continue to examine dividend levels as the results of our capital spending plans and commodity prices unfold.

  • We expect our capital spending and dividends to exceed our cash flow in both 2011 and 2012 however our balance sheet provides us with the financial flexibility to support our plans. In order to maintain our financial strength beyond 2011, we have assumed the sale of non-cash flow generating assets within our private equity portfolio or a portion of our non-operated working interests in the Marcellus in 2012. Thereafter, our debt-to-cash flow levels are expected to decline as production from our growth plays accelerates. We have not assumed any equity issuance beyond normal dividend reinvestment participation in our modeling. We expect our 2011 exit debt-to-cash flow ratio to be 1.7 times and 2 times by the end of 2012 based upon the current forward commodity markets. 

2011 & 2012 Estimates*

  2011 2012
Capital Expenditures ($millions) $650 $675
Oil & Liquids Weighting 65% 65%
Annual Average Daily Production:    
    Oil & Natural Gas Liquids (bbls/day) 36,000 - 37,500 39,000 - 41,000
    Natural Gas (Mcf/day) 250,000 - 256,000 260,000 - 265,000
    Total (BOE/day) 78,000 - 80,000 83,000 - 85,000
Oil & Liquids Weighting 47% 48%
Exit Production (BOE/day)    
     Oil & Natural Gas Liquids (bbls/day) 39,000 - 41,500 43,000 - 45,000
     Natural Gas (Mcf/day) 247,000 - 257,000 255,000 - 270,000
     Total (BOE/day) 80,000 - 84,000 86,000 - 90,000
Exit Change Year-over-Year 5% 8%
Oil & Liquids Weighting 48% 50%
Cash Flow From Operating Activities ($millions) $700 $800
Oil & Liquids Weighting 70% 70%
Simple Payout Ratio (1) 55% 50%
Adjusted Payout Ratio (1) 150% 135%
Debt/Cash Flow at Year-End* 1.7x 2.0x

Based upon the forward commodity prices and forecast costs as of December 8, 2010 including the impact of hedging.
Based upon our current capital spending plans for Q42010, forecast YE2010 debt is approximately $750 million.
2011 and 2012 debt calculations include Marcellus carry commitments of $116 million and $66 million respectively.
Monthly dividends held constant at CDN$0.18/share through 2011 and 2012.
Recover in 2012 of $40 million in U.S. tax previously paid.
Assumes $80 million of disposition proceeds in 2012 from equity investment portfolio or portion of non-operated Marcellus interest.

(1) Payout ratio is calculated as dividends paid to shareholders divided by cash flow from operating activities. Adjusted payout ratio is calculated as the sum of dividends paid to shareholders plus development capital and office expenditures divided by cash flow from operating activities. See "Non-GAAP Measures" below.

2011 Capital Spending & Production Outlook

We are targeting a capital spending program of $650 million in 2011, with approximately 70% of our spending directed to our Bakken and Marcellus properties where we expect to see significant growth in production and 15% to our waterflood assets where we expect to maintain production volumes. We plan to spend over $435 million on development drilling, recompletions and facilities, $140 million on delineation activities, $29 million on maintenance activities and $44 million on seismic.  In total, approximately 113 net wells are planned, two thirds of which we would operate and 95% of which would be horizontal wells.

As a result of this spending, we expect annual 2011 production to average 78,000 - 80,000 BOE/day, essentially unchanged from exit 2010, and to increase to 80,000 - 84,000 BOE/day by year-end.  Oil and liquids production is expected to grow 15% by year-end and should represent 48% of total volumes at that time.  Shallow gas and other conventional oil and gas production is expected to decline throughout the year due to reduced capital investment and marginal economic returns in the current natural gas price environment.

As a result of our divestment activities in 2010 and our increased focus on growth plays in 2011, we expect our decline rate will increase from 18% to approximately 22% - 23% in 2011. We intend to spend our capital budget relatively evenly throughout 2011 and have not assumed any material acquisitions or divestments. We will review our 2011 capital investment plans regularly throughout the year in the context of prevailing economic conditions and potential acquisitions, and make adjustments when necessary.  

Key 2011 Capital Spending Plans & Estimated Production


Resource Play Capital
of net
2010E Exit
Exit Production
Exit to Exit
Bakken/Tight Oil 300 48 13,000 18,000 - 21,000 50
Waterfloods 110 26 14,500 13,500 - 15,000 -
Marcellus Shale Gas 160 27 3,000 7,000 - 8,000 150
Resource Play Total $570 101 30,500 38,500 - 44,000 35

Crude Oil Investment

We expect to direct approximately 65% of our 2011 development spending toward oil projects, with the Bakken portfolio attracting $300 million of this spending.  The majority of our Bakken activity will be focused at Fort Berthold, North Dakota where we hold over 70,000 net acres (110 sections) of undeveloped land that is prospective for both the Bakken and Three Forks formations.

To date in Fort Berthold, we've drilled four short horizontal wells and three long horizontal wells into the play targeting the Bakken and results have exceeded our expectations.  As we move into the development stage, we expect production to grow from 4,000 bbls/day currently to over 20,000 BOE/day over the next four years. We are currently planning a drilling density at Fort Berthold for the Bakken of two short horizontal wells (~4,300 feet with 12 frac stages) per 640 acre spacing or two long horizontal wells (~9,000 feet with 24 frac stages) per 1,280 acre spacing.  Assuming  85% of the land is prospective, this would result in 95 - 185 future Bakken horizontal drilling locations, depending upon the number of long versus short wells.

Based upon current commodity prices and our type curves, we estimate short lateral wells have a net present value (before income taxes discounted at 12%) of $2.2 million to $5 million and are expected to achieve payout in two to three years. Under the same assumptions, long horizontal wells would have an estimated net present value of $8.4 million to $14 million and are expected to achieve payout in less than 1.7 years.  Given the more attractive economics associated with the long lateral wells, we expect that at least 75% of our drilling activity will be long lateral wells. The Three Forks formation underlies the Bakken throughout our entire acreage position at Fort Berthold. We plan to drill a number of Three Forks wells in 2011 to evaluate the potential and future prospectivity of this zone.

In 2011, we plan to have three to four rigs working in the play and expect to drill approximately 32 net operated wells (~90% working interest) and participate in another two net non-operated wells.  We recently entered into agreements to secure rigs and access to frac services and proppant which will help to ensure the timely execution of our plans. We also expect to have mid-stream arrangements in place by the middle of 2011 which will allow us to capture the associated natural gas volumes. Due to the high initial production rates associated with these wells, it will be challenging to predict exit production rates. As such, exit rates may vary considerably based upon when new wells come on stream.

  Fort Berthold Bakken Wells
  Type Curve Estimate Actual Results to Date
Long Laterals
Short Laterals
Long Laterals
(2 well average)
Short Laterals
(4 well average)
Average 30 Day Initial Production 1,100 - 1,200 bbls/day 550 - 650 bbls/day 1,190 bbls/day 800 bbls/day
Expected Ultimate Recovery 600 - 800 Mbbls 300 - 400 Mbbls    
Cost/Well $8 million $6 million $8 million $6 million
120 Day Cumulative Production (1) 81 Mbbls 40 Mbbls 108 Mbbls 59 Mbbls
Net Present Value (2)/well $8.4 - $14.0 million $2.2 - $5.0 million    
Netback (3) ~$48/bbl ~$48/bbl    
Payout Period (years) 1 to 1.7 years 2 to 3.0 years    

(1) Net present value before income taxes discounted at 12% using forward commodity price assumptions at December 8, 2010
(2) Only 2 long lateral wells have been on production for 120 days. Average 30 day initial production rates for 3 long lateral wells is 1,175 bbls/day
(3) 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. See "Non-GAAP Measures" below.

In our other Bakken prospects, six gross wells (four net) are expected to be drilled at Sleeping Giant in Montana, three of which will be long laterals. We continue to evaluate options regarding enhanced oil recovery opportunities as the number of drilling locations remaining within this property becomes limited. At Oungre, Saskatchewan, we are currently evaluating the results of two horizontal wells recently completed. We are also currently shooting seismic to further evaluate the Bakken and Ratcliffe potential in the Freda/Neptune/Oungre area. 

As a result of our capital spending across our entire Bakken/tight oil resource play in 2011, we expect production volumes will grow by 50%, exiting the year in the range of 18,000 - 20,000 BOE/day.

Our waterflood portfolio is comprised of a variety of crude oil properties in various plays, such as the Glauconitic, Viking, Cardium, and Ratcliffe.  These mature assets have significant amounts of original oil in place ("OOIP") with recovery to date of approximately 22%.  The average quality of oil in these play areas is approximately 30 degree API. Our plans for 2011 include drilling production and injection wells at our Medicine Hat, Freda Ratcliffe, Gleneath and Pembina 5-Way properties to increase oil production and maintain and/or improve reservoir pressures. In addition, we expect to invest in facility improvements to support future development plans and plan to continue work on two polymer pilots at Giltedge and Medicine Hat to increase ultimate recoveries.  The base production decline rate from these properties is approximately 16%. We plan to invest over $100 million, maintaining production volumes throughout the year at approximately 14,000 BOE/day.  A significant portion of this capital is being directed to activities that we believe will position us for future production and reserve growth.

Our waterflood properties are an important part of our future strategy as they generate a significant amount of free cash flow (cash flow after capital expenditures) to support our dividend and growth strategy.  At December 31, 2009, we had 77 million BOE of proved plus probable reserves booked to our waterfloods, representing an estimated recovery factor of 27%. We believe that through continued drilling and optimization as well as the application of enhanced oil recovery schemes, we could improve the ultimate recovery of oil from these pools to between 30% and 37%. This could add 50 - 150 million barrels of crude oil and associated natural gas to Enerplus' booked reserves.

Natural Gas Investment

With the current natural gas price outlook we plan to minimize our spending on our natural gas assets in 2011. Our efforts will be focused on delineating lease positions in new areas.  Approximately $230 million is expected to be invested into our natural gas assets in 2011, $160 million of which is planned for our Marcellus interests. The majority of the remainder of our natural gas spending is planned in the Deep Basin area where we hold over 65,000 net acres of undeveloped land.  We plan to drill four delineation wells targeting the Stacked Mannville in the South Ansell area where other producers have had recent success.  Our shallow gas activities will consist of recompletion activities at Shackleton. As a result of the decrease in spending in our tight and shallow gas resource plays, we expect production volumes from these plays will decline throughout 2011.

Approximately $160 million is planned for the Marcellus, the majority of which is anticipated to be spent on our non-operated interests.  With our joint venture partner, we plan to have eight to ten rigs working throughout the play in 2011 and expect to drill 150 gross wells (22.4 net).  We also expect to complete approximately 121 wells and we plan to have 94 new wells on stream by the end of the year.  Due to the timing of infrastructure, accessing frac crews and permitting, the estimated cycle time from commencement of drilling to production tie-in is approximately nine months. As a result of this timeframe, close to 75% of the wells that we plan to drill in 2011 will not be tied-in until 2012.  Production in 2011 is expected to grow by 150% to 45 MMcf/day by year-end. There are currently 42 gross wells on stream producing approximately 100 MMcf/day gross of natural gas. A further 45 MMcf/day of production is currently awaiting infrastructure, completion or tie-in. 

Well results over the past 18 months have either met or exceeded our expectations. Cumulative production on eight wells that have been on production for six months have ranged from 450 MMcf to 1.5 Bcf of natural gas per well with average 180 day cumulative production of 785 MMcf.  We have increased our type curve expectations in the Marcellus from 3.0 - 3.5 Bcf/well originally to 3.5 - 6.0 Bcf/well.  Well costs have also increased due to the drilling of longer lateral lengths with more frac stages.  In 2011 we estimate average well costs to range from $4.5 million to $6.0 million per well based upon drilling 3,500 - 5,000 foot lateral lengths with 8 - 12 frac stages. As a greater percentage of our drilling program moves into the development stage, we would expect well costs to decrease due to established water infrastructure and pad drilling.

The table below illustrates the economics associated with a range of type wells under different natural gas price scenarios.  We have assumed a $6 million cost per well under each scenario.

Marcellus Dry Gas Economics

  4.0 Bcf well 5.0 Bcf well 6.0 Bcf well
IRR Payout
NPV 12%
IRR Payout
NPV 12%
IRR Payout
NPV 12%
$6.00 27% 3.4 $2.51 41% 2.5 $4.57 57% 2.0 $6.62
$5.00 16% 4.9 $0.75 26% 3.4 $2.37 37% 2.6 $3.99
$4.00 7% 8.6 ($1.02) 13% 5.7 $0.17 20% 4.2 $1.35

We expect approximately 25% of our spending in 2011 will be focused on drilling in the liquids rich area of southwest Pennsylvania and northern West Virginia where the associated natural gas liquids provide better economics and the well costs are closer to $5 million.  This improves the internal rate of return on a typical 4.0 Bcf well from 7% to 21% in a $4 NYMEX gas price environment and improves the net present value before income taxes discounted at 12% from -$1.02 million to $1.34 million. These liquids rich wells are expected to have a breakeven supply cost of approximately $3.70/Mcf.  Approximately 30% of our spending is expected to be directed to delineation activity to preserve our lease positions and identify future potential.  We plan to spend the remaining 45% of our capital budget on development drilling in counties where we expect ultimate recoveries in the 4.5 - 5.5 Bcf range.

We also expect to drill five gross operated delineation wells (4 net) on our new Marcellus leases in 2011.

As a result of the sale of non-core, lower margin properties, operating costs in 2010 have decreased by 6% to approximately $10.20/BOE from our original guidance of $10.90/BOE.  We expect to see a further reduction in operating costs in 2011 to approximately $9.20/BOE due to a full year impact of the dispositions and the addition of lower cost production associated with our Bakken and Marcellus plays. 

In order to improve our operational effectiveness, Enerplus has been actively working to improve not only our underlying asset base, but also our internal technical capabilities.  We have increased our staffing levels within our U.S. operations by 50% in order to effectively manage our growing portfolio in the Bakken and the Marcellus and have also increased our technical capabilities within our Canadian operations. These changes have resulted in an increase in our general and administrative costs ("G&A"). The adoption of International Financial Reporting Standards ("IFRS") will also impact our G&A expenses going forward. Previously staff costs associated with our acquisition and divestment activities were capitalized however under IFRS, these costs will now be expensed. They are expected to contribute approximately $0.20/BOE of incremental cost to our G&A expense.  As a result of these changes and lower annual average production volumes expected in 2011 due to asset sales in 2010, we expect G&A costs will average approximately $3.30/BOE for the year.  As our capital plans are executed and production volumes increase throughout 2011 and into 2012, we expect to see a reduction in per BOE G&A expenses.

In the context of current forward commodity prices, we expect Crown and freehold royalties to be approximately 20% of our gross oil and gas sales in 2011 up from 18% in 2010 due to the increase in oil weighting within our portfolio and a stronger outlook for oil prices in 2011 compared to 2010.

Enerplus has received Unitholder and court approval to convert to a corporation effective January 1, 2011. As such, we will be subject to taxation at the same level as other Canadian corporations. Enerplus currently has approximately $3 billion in tax pools that we plan to utilize to meet our tax obligations in Canada and therefore do not expect to pay cash taxes in Canada for three to five years.  As a result of the higher capital spending in our U.S. operations, we expect cash taxes in the U.S. will be less than 5% of U.S. cash flow in 2011.

Our hedging program is designed to protect a portion of our cash flow to support our capital spending plans, the economics of our acquisitions and the dividend component of our business model.  Typically we will hedge forward with a view to providing downside protection in the event commodity prices fall while attempting to maintain some of the upside of future price improvements. Based upon the current forward market, Enerplus has floor protection on approximately 56% of our forecast 2011 crude oil production net of royalties at an effective price of US$87.10/bbl. For the first quarter of 2011, we have approximately 32% of our projected 2011 natural gas production volumes, net of royalties, hedged at an effective price of $6.14/Mcf. For 2012, we have approximately 7% of our projected crude oil production net of royalties hedged at an effective price of $90.29/bbl.  We expect to continue our price risk management program by adding to our crude oil hedge positions however we are reluctant to hedge any significant natural gas volumes in the current low price environment.

Acquisitions & Divestments
As part of our on-going business, we expect to acquire additional assets in key areas that fit with our business strategies and also divest of assets that are no longer part of our future plans. We do not have any specific plans to package and sell any significant producing non-core properties in 2011. As previously stated we expect to sell non-cash flow generating assets from our portfolio of equity investments or sell part of our non-operated Marcellus interests in 2012 in order to preserve our financial flexibility.  As part of our original acquisition agreement, we expect to spend $116 million on our capital carry commitments associated with the Marcellus in 2011.

We are positioning Enerplus to deliver competitive long-term returns that include a balance between growth and income to investors. We've made significant strides in repositioning our asset base and now have meaningful growth opportunities in our portfolio. We also have a strong foundation of mature, cash generating assets that can support our growth and income strategy.  We have maintained our financial flexibility throughout the past 18 months and our strong balance sheet will assist us in executing our strategy. Initially, a large portion of our total return will be comprised of dividend yield but as the development of our growth plays accelerates, we expect to supplement our dividend with sustainable growth in production and reserves per share.

Gordon J. Kerr
President & Chief Executive Officer
Enerplus Resources Fund

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. 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 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 or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: future capital spending amounts (including capital carry commitments), the timing thereof and the types of projects on which such capital will be spent; future growth opportunities; future oil, natural gas liquids and natural gas production levels, the product mix of such production and production decline rates; future cash flow levels; rates of return on our expenditures, investments and projects; the expected ultimate recovery of oil or gas from a particular well; finding and development costs, operating costs, general and administrative expenses and royalty expenses; sales of our equity portfolio and our non-operated working interests in the Marcellus play and the redeployment of proceeds realized there from; dividend payments made by Enerplus and the related payout and adjusted payout ratios; returns to our securityholders; debt levels and debt to cash flow ratios; drilling plans and results, including production rates, recovery factors, the cost, netback and net present value per well and well payout periods; the potential impact of IFRS on our financial and operating results; our conversion from an income trust to a corporation and the timing and payment of future taxes as a result; our planned commodity risk management program; and future liquidity, debt levels and financial capacity and resources. 

The forward-looking information and statements 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; the general continuance of current or, where applicable, assumed industry conditions; commodity prices will remain within Enerplus' expected range of forecast 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 and financing costs will not exceed Enerplus' current expectations; availability of third party service providers (including drilling rigs and service crews) and cooperation of industry partners; and certain foreign exchange rate and other cost assumptions. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information and statements 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 and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve 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 or statements including, without limitation: changes in commodity prices; unanticipated operating or drilling results or production declines; changes in tax or environmental laws or royalty rates; failure to receive required third party approvals; 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 reserves and resources 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 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, 2009 and in Enerplus'  Annual Information Form dated March 13, 2010 for the year ended December 31, 2009, copies of which are available on Enerplus' SEDAR profile at and which also form part of Enerplus' annual report on Form 40-F for the year ended December 31, 2009 filed with the United States Securities and Exchange Commission, a copy of which is available at  

The forward-looking information and statements contained in this news release speak only as of the date of this news release, and Enerplus assumes no 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

Throughout this news release we use the term "payout ratio" and "adjusted payout ratio" to measure operating performance, leverage and liquidity. We calculate payout ratio by dividing dividends paid to shareholders by cash flow. "Adjusted payout ratio" is calculated as dividends paid to shareholders plus development capital and office expenditures divided by cash flow. The terms "payout ratio" and "adjusted payout ratio" do not have a standardized meaning or definition as prescribed by GAAP 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 GAAP and therefore may not be comparable with the calculation of similar measures by other entities.


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