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News Releases

Enerplus reports strong 2nd quarter results and increases guidance for 2010

August 6, 2010

CALGARY, Aug. 6 /CNW/ - Enerplus Resources Fund ("Enerplus") (TSX - ERF.un, NYSE - ERF) is pleased to announce operating and financial results for the three months ended June 30, 2010. Full copies of our first quarter 2010 Financial Statements and MD&A have been filed on our website at, under our profile on SEDAR at, and on the EDGAR website at




- We added new positions during the quarter in key focus areas:

           -  Bakken/Tight Oil - added 14,000 net acres of undeveloped land
              in North Dakota and over 100,000 net acres of undeveloped land
              in southern Saskatchewan.
           -  Marcellus Shale Gas - added an additional 6,000 net acres of
              land that will be operated and controlled by Enerplus.
           -  Deep Basin Tight Gas - added approximately 6,300 net acres of
              undeveloped land.

- We now have over 350,000 net acres of prospective lands primarily in the Marcellus shale gas play and the Bakken light oil play that will provide us with extensive growth prospects for the future.

- We sold 3,400 BOE/day of non-core production for approximately $198 million.

- We negotiated a new $1 billion credit facility with our syndicate of banks. Although our asset base would support a larger credit facility, we chose to reduce its size due to the significant increase in the cost of maintaining unused credit capacity.




- Production was on track with expectations, averaging 84,909 BOE/day.

- Development capital expenditures totaled $91 million (44% gas, 56% oil). We drilled 19 net wells with a drilling success rate of 99%.

- Cash flow from operations totaled $163 million ($0.92/unit). Approximately 59% of this was distributed to Unitholders and when combined with development capital spending, our adjusted payout ratio was approximately 115% of cash flow.

- Operating costs were reduced to $9.82/BOE and general and administrative costs dropped to $1.89/BOE.

- Our financial position remains strong with a debt to cash flow ratio of 0.9x with only $170 million drawn on our bank facility at the end of the quarter.

- We are updating our average annual production guidance to 85,000 BOE/day and exit production guidance to 86,000 BOE/day to reflect the impact of our year-to-date acquisition and divestment activity. As well, we are increasing our development capital spending guidance to $485 million and have adjusted our operating cost guidance down to $10.20/BOE.


    SELECTED FINANCIAL RESULTS      Three months ended      Six months ended
                                               June 30,              June 30,

    (in Canadian dollars)              2010       2009       2010       2009
    Financial (000's)
      Cash Flow from Operating
       Activities                  $163,383   $210,608   $352,740   $379,996
      Cash Distributions to
       Unitholders(1)                95,909     89,610    191,621    179,147
      Excess of Cash Flow Over
       Cash Distributions            67,474    120,998    161,119    200,849
      Net Income                     31,296     (3,569)   111,299     48,217
      Debt Outstanding - net of
       cash                         697,817    713,536    697,817    713,536
      Development Capital
       Spending(2)                   90,538     34,865    185,813    131,453
      Property and Land
       Acquisitions(2)              311,874     29,113    353,201     33,745
      Divestments                   181,238      1,723    182,776      1,736

    Actual Cash Distributions
     paid to Unitholders           $   0.54   $   0.54   $   1.08   $   1.15

    Financial per Weighted
     Average Trust Units(3)
      Cash Flow from Operating
       Activities                  $   0.92   $   1.27   $   1.99   $   2.29
      Cash Distributions per
       Unit(1)                         0.54       0.54       1.08       1.08
      Excess of Cash Flow Over
       Cash Distributions              0.38       0.73       0.91       1.21
      Net Income/(Loss)                0.18      (0.02)      0.63       0.29
      Payout Ratio(4)                   59%        43%        54%        47%
      Adjusted Payout Ratio(2)(4)      115%        60%       107%        83%

    Selected Financial Results
     per BOE(5)
      Oil & Gas Sales(6)           $  41.18   $  35.60   $  44.39   $  35.42
      Royalties                       (7.35)     (6.28)     (7.95)     (6.36)
      Commodity Derivative
       Instruments                     2.23       4.95       1.38       5.16
      Operating Costs                (10.09)     (9.58)    (10.00)     (9.77)
      General and Administrative      (1.66)     (2.27)     (2.06)     (2.16)
      Interest and Other Expenses     (1.79)      1.02      (1.33)      0.07
      Taxes                           (0.05)     (0.21)     (0.03)     (0.15)
      Asset Retirement
       Obligations Settled            (0.46)     (0.29)     (0.51)     (0.36)
    Cash Flow from Operating
     Activities before changes in
     non-cash working capital      $  22.01   $  22.94   $  23.89   $  21.85

    Weighted Average Number
     of Trust Units Outstanding(3)  177,526    166,264    177,349    165,807
    Debt to Trailing Twelve
     Month Cash Flow Ratio             0.9x       0.7x       0.9x       0.7x

    SELECTED OPERATING RESULTS      Three months ended      Six months ended
                                               June 30,              June 30,
                                       2010       2009       2010       2009
    Average Daily Production
      Natural gas (Mcf/day)         296,566    338,193    297,737    338,538
      Crude oil (bbls/day)           31,559     33,715     31,268     34,075
      Natural gas liquids
       (bbls/day)                     3,922      4,420      3,924      4,241
      Total daily sales
       (BOE/day)                     84,909     94,501     84,815     94,739

      % Natural gas                     58%        60%        59%        60%

    Average Selling Price(6)
      Natural gas (per Mcf)        $   3.78   $   3.49   $   4.44   $   4.31
      Crude oil (per bbl)             68.72      59.80      71.25      51.06
      NGLs (per bbl)                  47.55      35.47      52.49      37.91
      CDN$/US$ exchange rate           0.97       0.86       0.97       0.83

    Net Wells drilled                    19          5        158        128
    Success Rate(7)                     99%       100%        99%        99%
    (1) Calculated based on distributions paid or payable.
    (2) Land acquisitions in prior periods have been reclassified from
        development capital expenditures to property acquisitions to conform
        with the current year presentation.
    (3) Weighted average trust units outstanding for the period, includes the
        equivalent exchangeable limited partnership units.
    (4) Payout ratio is calculated as cash distributions to Unitholders
        divided by cash flow from operating activities. Adjusted payout ratio
        is calculated as the sum of cash distributions to Unitholders plus
        development capital and office expenditures divided by cash flow from
        operating activities. See "Non-GAAP Measures" below.
    (5) Non-cash amounts have been excluded.
    (6) Net of oil and gas transportation costs, but before the effects of
        commodity derivative instruments.
    (7) Based on wells drilled, cased and tied in.

    Trust Unit Trading Summary                   TSX - ERF.un  U.S.* - ERF
    For the three months ended June 30, 2010            (CDN$)          (US$)
    High                                         $      25.07   $      24.84
    Low                                          $      18.22   $      13.76
    Close                                        $      22.89   $      21.57
    * U.S. Composite Exchange Data including NYSE.

    2010 Cash Distributions Per Trust Unit
    Payment Month                                        CDN$            US$
    First Quarter Total                          $       0.54   $       0.52

    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   $       1.05




On June 29, 2010, we increased our working interests in Fort Berthold, North Dakota through the acquisition of our partner's 50% working interest, adding approximately 14,000 net acres of prospective land and 1,100 BOE/day of early stage, high netback crude oil production from 4 operated wells and 1 non-operated well. The total cost of the acquisition was approximately US$108 million before closing adjustments. Our undeveloped acreage position in Fort Berthold is now 25,000 net acres with a 95% working interest which we believe is prospective for both the Bakken and Three Forks formations. These lands are located primarily in the northern part of Dunn County, which has some of the best economics and performance results for Bakken production across the state. Based upon our internal assessment of the Bakken potential on these lands, we believe we can drill up to 2 wells per section through a combination of long and short length lateral horizontal wells. We also believe the lands are prospective for the Three Forks formation and will be testing this potential this year. Operating netbacks are expected to average over $55/BOE based upon current commodity prices with operating costs below $5.00/BOE. We expect significant production growth from this area in the coming years.

In April we acquired 154 new sections (approximately 100,000 net acres) of undeveloped land in southern Saskatchewan at a Crown land sale for $117 million. These lands are in an emerging Bakken play area and are contiguous to our existing land holdings. We now hold a 100% working interest in approximately 142,000 acres in the Freda Lake/Neptune/Oungre area. To date we have drilled 4 wells on these lands and are evaluating results with an expectation that we will drill a number of wells in the second half of 2010 to delineate the play. In aggregate we hold over 170,000 net acres of undeveloped land in the Bakken/tight oil areas of Saskatchewan, North Dakota and Manitoba which are in the early stages of development.

On June 30, 2010, we also executed our first non-core asset divestment. Approximately 3,400 BOE/day (90% crude oil) and approximately 13 million BOE of proved plus probable reserves were sold for $198 million before adjustments representing sale metrics of approximately $58,000 per flowing BOE of production and $22.83/BOE of proved plus probable reserves including future development costs. This production was located in central and northern Alberta and comprised of varied working interests in 14 properties. The average operating netback of these properties was approximately $27.00/BOE with operating costs of approximately $17.00/BOE.

These transactions represent significant progress in our strategy to better focus our efforts on properties that have greater development potential and superior operating metrics. We are continuing to market assets that do not fit our strategy and expect to sell additional properties in 2010 and beyond. We are also considering various alternatives relating to our Kirby oil sands interest given our desire to focus on plays that offer scope and scale with nearer-term cash flow. We will provide an update as developments occur.




Given the recent acquisition and divestment activity and the capital opportunities associated with the new Bakken lands in Saskatchewan, North Dakota and our Marcellus shale gas play, we are adjusting our 2010 operating guidance. Annual production volumes are now expected to average 85,000 BOE/day versus our original estimate of 86,000 BOE/day with exit rates of 86,000 BOE/day versus our original estimate of 88,000 BOE/day. We plan to increase our capital spending by $60 million to $485 million with the majority of the increase on light oil projects that are highly economic in the current commodity price environment. As this incremental capital spending is occurring late in 2010, we expect to see a greater impact on production volumes in 2011. Total expenditures on oil projects are now expected to be 63% of our total development capital budget. In addition, we are reducing our operating cost guidance given our lower realized costs year-to-date and the elimination of higher cost properties associated with our divestment. We now anticipate operating costs to average $10.20/BOE for 2010. Please see our Management's Discussion and Analysis for further detail on changes to our 2010 guidance.

The following table reconciles our original 2010 production guidance to our revised guidance taking into consideration the impacts of our acquisition and divestment activity as well as our increased capital spending guidance:


                                               Annual Average      Exit Rate
                                                     (BOE/day)      (BOE/day)
    Original Guidance                                  86,000         88,000
    Effect of Asset Dispositions                       (1,700)        (3,100)
    Sub-Total                                          84,300         84,900
    Incremental production relating to
     acquisitions & capital spending                      700          1,100
    Revised Guidance                                   85,000         86,000




Our oil and gas production averaged 84,909 BOE/day in the second quarter, slightly higher than the first quarter of this year and on track with our expectations. Our operations generated cash flow of $163 million during the quarter ($0.92/unit) down 14% from the first quarter of 2010 due to lower commodity prices. Approximately 59% of cash flow was distributed to Unitholders through monthly distributions of $0.18/unit. Distributions and development capital spending combined resulted in an adjusted payout ratio of 115%.

Development capital spending and drilling activity slowed considerably in the second quarter due to spring breakup and excessively wet conditions throughout much of Saskatchewan and southern Alberta. We drilled a total of 19 net wells in the quarter including 4 net wells in the Marcellus and another 6 net wells in our Bakken/tight oil resource play. We invested approximately $91 million of development capital (44% natural gas, 56% oil) of which approximately 60% was spent in our Marcellus shale gas and Bakken tight oil plays.




                                    Three months ended      Six months ended
                                               June 30,              June 30,
                                                  2010                  2010
                                    Average    Capital    Average    Capital
                                 Production   Spending Production   Spending
                                    Volumes         ($    Volumes         ($
    Play Type                                 millions)             millions)
    Bakken/Tight Oil (BOE/day)       10,260         32      9,547         63
    Crude Oil Waterfloods (BOE/day)  15,762         16     15,863         36
    Conventional Oil (BOE/day)        9,066          3      9,600          6
    Total Oil (BOE/day)              35,088         51     35,010        105

    Marcellus Shale Gas (Mcfe/day)    6,351         21      4,523         35
    Shallow Gas (Mcfe/day)          122,710          3    124,581         10
    Tight Gas (Mcfe/day)             87,371          8     88,569         22
    Conventional Gas (Mcfe/day)      82,496          8     81,160         14
    Total Gas (Mcfe/day)            298,928         40    298,833         81

    Company Total                    84,909         91     84,815        186



For the three months ended June 30, 2010


                                          Pending             Dry &
                 Hori-                    Comple-    Wells    Aban- Drilling
                zontal Vertical    Total    tion/      On-    doned  Success
    Play Type    Wells    Wells    Wells   Tie-in   stream    Wells     Rate
     Tight Oil     6.5        -      6.5      4.8      1.7        -     100%
    Crude Oil
     Waterfloods   1.2      0.3      1.5      0.8      0.7        -     100%
     Oil           4.4        -      4.4      4.4        -        -     100%
    Total Oil     12.1      0.3     12.4     10.0      2.4        -     100%

     Shale Gas     3.1      0.8      3.9      3.9        -      0.1      99%
    Shallow Gas      -        -        -        -        -        -     100%
    Tight Gas      0.1      2.0      2.1      2.1        -        -     100%
     Gas             -      0.1      0.1      0.1        -        -     100%
    Total Gas      3.2      2.9      6.1      6.1        -      0.1      99%

     Total        15.3      3.2     18.5     16.1      2.4      0.1      99%




Production in our Marcellus shale gas play averaged 6.4 MMcf/day in the second quarter, up from 2.7 MMcf/day during the first quarter. We spent approximately $21 million in development capital and drilled 21 gross wells (4 net wells). In addition, 15 gross wells were completed and another 7 wells were tied in. The bulk of the drilling activity was focused in Bradford, Lycoming, and Susquehanna counties in Pennsylvania as well as Marshall County in West Virginia. We currently have 6 rigs running in this play and may add a 7th during the fourth quarter. Current production from the Marcellus is over 9 MMcf/day.

We have increased the number of frac stages on our most recent horizontal wells from an average of 8 stages per well to 10 to 15 stages per well depending on lateral length. 24 hour test rates on the 7 wells completed and tied in during the quarter averaged 4.3 MMcf/day per well, 3 of which have averaged 5.7 MMcf/day. Our highest 24 hour test rate was 14 MMcf/day on a well awaiting tie-in in Greene County, PA. Given the longer lateral lengths and increased number of frac stages, we have seen an improvement in 24 hour test rates such that the 10 well moving average over the last 9 months has gone from 3.5 MMcf/day to over 5 MMcf/day. Overall, we are encouraged with the performance of the wells brought on-stream to date. In addition to improving well productivity, we are seeing lower than expected decline rates in a majority of areas.

The table below provides additional detail on the majority of our producing horizontal wells. Of note, production from Marshall County which has associated natural gas liquids is currently restricted due to processing limitations in the area. We expect this issue to be resolved in the coming months. In Lycoming County, the average 30 day production rate does not include the most recent 4 wells on production as we do not have 30 days of production data. However, the average 24 hour peak rate on these wells is 4.5 MMcf/day.



                                                                Avg. 30
                                         Avg.      Avg.   Producing Day
                          No. of      Lateral    No. of       Gross IP
     County             HZ Wells    Length(ft)    Fracs       (Mcf/day)
    Bradford                   2        2,241         7          2,556
    Lycoming                   9        2,950         8          3,028
    Marshall                   6        2,765         8          2,527
    Susquehanna                2        2,715         9          6,484


28 gross wells are currently on production in our Marcellus play (23 horizontal wells and 5 vertical wells), with an additional 39 wells waiting on completion and 11 wells waiting on pipeline. Completion activity remains challenging due to the limited availability of frac and cementing crews in the region, however we expect these conditions may ease somewhat heading into the winter drilling season as indications are that more crews and equipment are being added into this region by suppliers. Given the favourable summer weather, our midstream partners expect to make substantial progress in building the gas gathering infrastructure necessary to bring more of these wells on-stream.

We continued to add to our Marcellus position during the quarter with the acquisition of over 6,000 net acres and now hold approximately 12,000 net acres of operated land in Center and Clinton counties. Current plans include shooting seismic in the area and we expect to drill our first operated well later this year. Full year 2010 capital spending plans have been increased by $10 million to $90 million, excluding our carry commitment of $64 million.




Production in our Bakken/tight oil resource play averaged approximately 10,260 BOE/day during the quarter, representing a 16% increase from the first quarter of 2010. We spent approximately $32 million drilling 6 net wells primarily in our Montana and North Dakota assets. Activity in southeast Saskatchewan was limited due to extremely wet weather and a longer than planned spring breakup.

We drilled 3.5 net horizontal wells in the Sleeping Giant field in Montana and tied in 4 wells. We've changed our completion techniques and the 30 day production rates on these wells are significantly better than our original type curve estimates. Initial production rates are 75% higher with an incremental cost of only 20%. The cost of the new wells are ranging from $4.5 million to $5.3 million depending upon the lateral length. Although the field is at a relatively advanced state of primary development, there are still a modest number of drilling locations remaining in addition to refrac and recompletion opportunities which we are evaluating.

One well was drilled at Fort Berthold, North Dakota during the quarter with 4 additional wells brought on stream. 30 day initial production rates for each of the 4 wells on stream have averaged approximately 800 bbls/day per well excluding any associated natural gas which is not being captured at this time. We are currently in the process of drilling and completing another 3 wells.


                                                           30 day
                                                No. of   Gross IP    Average
                                    Lateral       Frac    Rates*   Working
    Sleeping Giant, MT               Length     Stages   (BOE/day)  Interest
    Well No. 1                        3,750          8        326        81%
    Well No. 2                        5,750         10        272        81%
    Well No. 3(xx)                    9,250         18        984        69%
    Well No. 4(xx)                    9,500         18        949        69%

                                                           30 day
                                                         IP Rates
    Ft. Berthold, ND                                    (bbls/day)
    Well No. 1                        4,300         12        621       100%
    Well No. 2                        4,300         12        775       100%
    Well No. 3                        4,300         12        885       100%
    Well No. 4                        4,300         12        910       100%

    *    Sleeping Giant volumes include both crude oil and natural gas.
           Natural gas volumes are not being captured at Fort Berthold at
           this time.

    (xx)   Wells 3 and 4 were put on pump immediately following completion
           to enhance initial production whereas the first 2 wells were
           initially flowed without pump.


We have allocated additional capital to our Bakken/tight oil resource play, and now expect to invest over $170 million of our $485 million capital budget in this play in 2010. This additional capital will be spent on drilling 10 to 14 assessment wells on our Bakken lands at Freda Lake, Neptune and Oungre in Saskatchewan plus increased activity at Fort Berthold due to the additional interests acquired in late June. We expect to have up to 3 rigs running in Saskatchewan with 1 rig operating in North Dakota in the second half of the year. We expect this additional capital to add approximately 2,200 bbls/day of initial production, the majority of which will be realized in the first quarter of 2011.




We are excited by the opportunities that our investments in the Marcellus, Bakken/tight oil and Deep Basin plays present to us. We are becoming more focused on key plays in our portfolio and will continue our non-core asset disposition program. Our financial strength remains a competitive advantage for us as well. We are expecting to convert into a dividend paying company on January 1, 2011 assuming Unitholder approval and do not anticipate this will be a taxable event for our Unitholders. It is our intention to maintain our monthly distributions to Unitholders at current levels through the conversion assuming current commodity prices prevail. We are committed to providing a strong total return comprised of both growth and income to our investors and are well on our way to meeting this commitment.




Second quarter 2010 Consolidated Financial Statements and Notes to the Consolidated Financial Statements, along with the Management's Discussion and Analysis for Enerplus, have been filed on our website at, under our profile on SEDAR and on the EDGAR website at




All amounts in this news release are stated in Canadian dollars unless otherwise specified.

Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE in isolation may be misleading. "MMcfe" means million cubic feet of gas equivalent. Enerplus has adopted the standard of one barrel of oil to six thousand cubic feet of gas (1 barrel: 6 Mcf) when converting oil to MMcfes. MMcfes may be misleading, particularly if used in isolation. An MMcfe conversion ratio of 1 barrel: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

In accordance with Canadian practice, production volumes and revenues are reported on a gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom) are based on "company interest reserves" using forecast prices and costs. "Company interest reserves" consist of "gross reserves" (as defined in National Instrument 51-101 adopted by the Canadian securities regulators ("NI 51-101") plus Enerplus' royalty interests in reserves. "Company interest reserves" are not a measure defined in NI 51-101 and do not have a standardized meaning under NI 51-101. Accordingly, our company interest reserves may not be comparable to reserves presented or disclosed by other issuers. Our oil and gas reserves statement for the year ended December 31, 2009, which includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, is contained within our Annual Information Form for the year ended December 31, 2009 ("our AIF") which is available on our website at and on our SEDAR profile at Additionally, the Annual Information Form forms part of our Form 40-F that has been filed with the U.S. Securities and Exchange Commission and is available on EDGAR at Readers are also urged to review the Management's Discussion & Analysis and financial statements filed on SEDAR and EDGAR concurrently with this news release for more complete disclosure on our operations.




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 gross (or, as noted above, "company interest") volumes, which are 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. Additionally, the SEC prohibits disclosure of oil and gas resources, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not be construed as reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see "Information Regarding Disclosure in this News Release" above.




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", "guidance", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends" 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: the amount, timing and tax treatment of cash distributions to Unitholders; payout ratios and adjusted payout ratios; tax treatment of income trusts such as the Fund; the structure of the Fund and its subsidiaries including conversion to a corporate structure; the Fund's income taxes, tax liabilities and tax pools; the volume and product mix of the Fund's oil and gas production; production and operational matters including drilling plans and delayed projects; oil and natural gas prices and the Fund's risk management programs; the amount of asset retirement obligations; future liquidity and financial capacity and resources; future capital expenditures; cost and expense estimates; results from operations and financial ratios; the impact of the conversion to IFRS on the financial results of the Fund; the Fund's ongoing strategy; the Fund's credit exposure; cash flow sensitivities; royalty rates and their impact on the Fund's operations and results; future growth including development, exploration, and acquisition and development activities and related expenditures; and future dispositions of oil and gas assets. This press release also contains estimates of contingent resources, which are by their nature estimates that the quantities described exist in the amounts estimated.

The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of the Fund including, without limitation: that the Fund will continue to conduct its operations in a manner consistent with past operations; the general continuance of current or, where applicable, assumed industry conditions and tax and regulatory regimes; availability of cash flow, debt and/or equity sources to fund the Fund's capital and operating requirements as needed; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; the accuracy of the estimates of the Fund's reserve and resource volumes; and certain commodity price and other cost assumptions. The Fund 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 results or production declines; changes in tax or environmental laws or royalty rates; increased debt levels or debt service requirements; inaccurate estimation of the Fund's oil and gas reserves and resources volumes; limited, unfavourable or no access to debt or equity capital markets; increased costs and expenses; the impact of competitors; reliance on industry partners; and certain other risks detailed from time to time in the Fund's public disclosure documents including, without limitation, those risks identified in the MD&A, our MD&A for the year ended December 31, 2009 and in the Fund's Annual Information Form for the year ended December 31, 2009, copies of which are available on the Fund's SEDAR profile at and which also form part of the Fund's Form 40-F for the year ended December 31, 2009 filed with the SEC, 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 release and none of the Fund 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.




Throughout this news release we use the term "payout ratio" and "adjusted payout ratio" to analyze operating performance, leverage and liquidity and the term "operating netback" as a measure of operating performance. We calculate payout ratio by dividing cash distributions to Unitholders ("cash distributions") by cash flow from operating activities ("cash flow"), both of which appear on our consolidated statements of cash flows prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). "Adjusted payout ratio" is calculated as cash distributions plus development capital and office expenditures divided by cash flow. "Operating Netbacks" are calculated by subtracting Enerplus' expected royalties and operating costs from the anticipated revenues in respect of the relevant properties. The terms "payout ratio", "adjusted payout ratio" and "netback" 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. Refer to the Liquidity and Capital Resources section of the Management's Discussion and Analysis section in this interim report for further information.


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


%CIK: 0001126874

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