Enerplus reports strong 2nd quarter results and increases guidance for 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 www.enerplus.com, under our profile on SEDAR at www.sedar.com, and on the EDGAR website at www.sec.gov.
STRATEGIC EXECUTION:
- 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.
QUARTERLY OPERATING AND FINANCIAL PERFORMANCE:
- 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
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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)
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Cash Flow from Operating
Activities before changes in
non-cash working capital $ 22.01 $ 22.94 $ 23.89 $ 21.85
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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
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SELECTED OPERATING RESULTS Three months ended Six months ended
June 30, June 30,
2010 2009 2010 2009
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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%
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(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$) (US$)
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High $ 25.07 $ 24.84
Low $ 18.22 $ 13.76
Close $ 22.89 $ 21.57
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* U.S. Composite Exchange Data including NYSE.
2010 Cash Distributions Per Trust Unit
Payment Month CDN$ US$
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First Quarter Total $ 0.54 $ 0.52
April $ 0.18 $ 0.18
May 0.18 0.17
June 0.18 0.18
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Second Quarter Total $ 0.54 $ 0.53
Total Year-to-Date $ 1.08 $ 1.05
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ACQUISITIONS & DIVESTMENTS
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.
UPDATING 2010 GUIDANCE
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)
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Original Guidance 86,000 88,000
Effect of Asset Dispositions (1,700) (3,100)
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Sub-Total 84,300 84,900
Incremental production relating to
acquisitions & capital spending 700 1,100
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Revised Guidance 85,000 86,000
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OPERATIONS
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 $91 million of development capital (44% natural gas, 56% oil) of which approximately 60% was spent in our Marcellus shale gas and Bakken tight oil plays.
PRODUCTION AND CAPITAL SPENDING SUMMARY
Three months ended Six months ended
June 30, June 30,
2010 2010
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Average Capital Average Capital
Production Spending Production Spending
Volumes ($ Volumes ($
Play Type millions) millions)
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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
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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
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Total Gas (Mcfe/day) 298,928 40 298,833 81
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Company Total 84,909 91 84,815 186
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DRILLING ACTIVITY (NET WELLS)
For the three months ended June 30, 2010
Wells
Pending Dry &
Hori- Comple- Wells Aban- Drilling
zontal Vertical Total tion/ On- doned Success
Play Type Wells Wells Wells Tie-in stream Wells Rate
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Bakken/
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%
Conventional
Oil 4.4 - 4.4 4.4 - - 100%
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Total Oil 12.1 0.3 12.4 10.0 2.4 - 100%
Marcellus
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%
Conventional
Gas - 0.1 0.1 0.1 - - 100%
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Total Gas 3.2 2.9 6.1 6.1 - 0.1 99%
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Company
Total 15.3 3.2 18.5 16.1 2.4 0.1 99%
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MARCELLUS SHALE GAS
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)
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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.
BAKKEN/TIGHT OIL
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
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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)
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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.
GO-FORWARD STRATEGY
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.
CONSOLIDATED FINANCIAL STATEMENTS AND MD&A
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 www.enerplus.com, under our profile on SEDAR www.sedar.com and on the EDGAR website at www.sec.gov.
INFORMATION REGARDING DISCLOSURE IN THIS NEWS RELEASE
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 www.enerplus.com and on our SEDAR profile at www.sedar.com. 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 www.sec.gov. 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.
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 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.
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", "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 www.sedar.com 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 www.sec.gov.
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.
NON-GAAP MEASURES
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
For further information: or a copy of our 2010 second quarter interim report, please contact our investor relations department at 1-800-319-6462 or email [email protected]
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