CALGARY, Nov. 12 /CNW/ -- CALGARY, Nov. 12 /CNW/ - Enerplus
Resources Fund ("Enerplus") (TSX - ERF.un, NYSE - ERF) is pleased
to announce operating and financial results for the third quarter
of 2010. Full copies of our third 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. TRANSITIONING THE ASSET BASE -- To date
this year Enerplus has acquired over $900 million of new
growth-oriented assets in two of the best plays in North America -
the Bakken crude oil play in the Williston Basin and the Marcellus
shale gas play in northeast United States. The proceeds from our
disposition activities have ensured we maintain our strong
financial position while repositioning into higher growth assets
and improving the focus in our portfolio. -- We expanded our
interest in the Marcellus shale gas region with the purchase of
58,500 net acres of high working interest land in West Virginia and
Maryland. We now own and operate a total of 70,000 net acres of
concentrated land in addition to the nearly 130,000 net acres of
non-operated land in the Marcellus which will provide us with
significant future growth potential. -- We also acquired 46,500 net
acres of additional land in the Fort Berthold area of North Dakota
subsequent to the quarter that we believe is prospective for both
Bakken and Three Forks crude oil. This complements our existing
operated position in the region and gives Enerplus over 70,000 net
acres of undeveloped land in North Dakota together with 140,000 net
acres of undeveloped Bakken prospective land in the Freda
Lake/Neptune/Oungre area of southern Saskatchewan that we operate
as well. -- We added 39 sections of land prospective for natural
gas from the Stacked Mannville and Montney formations. We now hold
over 65,000 net acres of undeveloped land in the Deep Basin area.
-- 2,500 BOE/day of oil and gas production located in Alberta and
British Columbia was sold during the quarter for proceeds of $153
million. As well, we expect to close the sale of a further 4,500
BOE/day of non-core assets during the fourth quarter for proceeds
of approximately $140 million. The average operating cost of these
properties ranged from $17.00/BOE to $23.00/BOE. -- We were also
successful in selling our Kirby oil sands lease for $405 million
subsequent to the quarter. OPERATING AND FINANCIAL PERFORMANCE --
Operations continued to meet expectations with production volumes
in line with guidance. Operating costs have continued to decline
throughout the year and our capital program has delivered results
in key growth areas as well as in mature, cash flow generating
assets. -- Production averaged 82,869 BOE/day after adjusting for
the sale of 2,500 BOE/day of production during the third quarter.
To date in 2010, we've sold 6,000 BOE/day of non-core production.
-- We had an active quarter spending $128 million in development
capital, 80% of which was invested in our Bakken/tight oil,
Marcellus and crude oil waterflood resource plays. Year-to-date
capital investment has totaled $314 million, the majority of which
has been funded from cash flow. -- 25 net wells were drilled, 85%
of which were oil wells. All but one of these wells were drilled
horizontally. -- Cash flow from operations totaled $203.6 million
for the third quarter. For the first nine months of 2010, Enerplus
has generated approximately $556.3 million of cash flow from
operating activities, distributing 52% to unitholders through
monthly distributions. -- Development capital spending and
distributions totaled 110% of cash flow for the third quarter and
108% for the first nine months of the year. -- Operating costs
averaged $10.28/BOE for the quarter with year-to-date costs
averaging $10.02/BOE. -- Our balance sheet remains strong with a
debt to cash flow ratio of 0.9x at September 30, 2010 providing us
with ample financial flexibility to pursue our future growth plans.
SELECTED FINANCIAL RESULTS Three months ended Nine months ended
September 30, September 30, (in Canadian dollars) 2010 2009 2010
2009 Financial (000's) Cash Flow from Operating $203,622 $207,211
$556,362 $587,207 Activities Cash Distributions to 96,111 93,504
287,732 272,651 Unitholders((1)) Excess of Cash Flow Over Cash
107,511 113,707 268,630 314,556 Distributions Net Income 16,808
38,182 128,107 86,399 Debt Outstanding - net of cash 680,264
561,218 680,264 561,218 Development Capital Spending( 127,837
42,863 313,650 174,316 (2)) Property and Land Acquisitions( 140,530
195,038 493,731 228,783 (2)) Divestments 150,747 519 333,523 2,255
Actual Cash Distributions paid $0.54 $0.54 $1.62 $1.69 to
Unitholders Financial per Weighted Average Trust Units((3)) Cash
Flow from Operating $1.14 $1.23 $3.13 $3.52 Activities Cash
Distributions per Unit( 0.54 0.55 1.62 1.63 (1)) Excess of Cash
Flow Over Cash 0.60 0.68 1.51 1.89 Distributions Net Income 0.09
0.23 0.72 0.52 Payout Ratio((4)) 47% 45% 52% 46% Adjusted Payout
Ratio((2)(4)) 110% 68% 108% 78% Selected Financial Results per BOE
((5)) Oil & Gas Sales((6)) $40.08 $35.23 $42.96 $35.36
Royalties (7.29) (5.56) (7.74) (6.10) Commodity Derivative 2.76
4.89 1.84 5.08 Instruments Operating Costs (10.09) (10.00) (10.03)
(9.84) General and Administrative (2.55) (2.21) (2.22) (2.18)
Interest and Other Expenses (1.88) (0.79) (1.51) (0.22) Taxes
Recovery/(Expense) 4.43 (0.35) 1.45 (0.22) Asset Retirement
Obligations (0.30) (0.31) (0.44) (0.34) Settled Cash Flow from
Operating Activities before changes in non-cash working capital
$25.16 $20.90 $24.31 $21.54 Weighted Average Number of Trust
177,871 168,521 177,526 166,724 Units Outstanding((3)) Debt to
Trailing Twelve Month 0.9x 0.7x 0.9x 0.7x Cash Flow Ratio SELECTED
OPERATING RESULTS Three months ended Nine months ended September
30, September 30, 2010 2009 2010 2009 Average Daily Production
Natural gas (Mcf/day) 285,292 323,884 293,543 333,606 Crude oil
(bbls/day) 31,639 32,218 31,393 33,454 Natural gas liquids
(bbls/day) 3,681 3,912 3,842 4,129 Total daily sales (BOE/day)
82,869 90,111 84,159 93,184 % Natural gas 57% 60% 58% 60% Average
Selling Price ((6)) Natural gas (per Mcf) $3.67 $2.95 $4.19 $3.86
Crude oil (per bbl) 66.97 64.94 69.80 55.57 NGLs (per bbl) 46.69
32.59 50.61 36.21 CDN$/US$ exchange rate 0.96 0.91 0.97 0.85 Net
Wells drilled 25.0 27.6 183.8 156.6 ((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. TRUST UNIT TRADING
SUMMARY TSX - ERF.un U.S.* - ERF For the three months ended
September 30, 2010 (CDN$) (US$) High $26.57 $25.84 Low $22.53
$20.90 Close $26.50 $25.75 * U.S. Composite Exchange Data including
NYSE. 2010 CASH DISTRIBUTIONS PER TRUST UNIT Payment Month CDN$ US$
First Quarter Total $0.54 $0.52 Second Quarter Total $0.54 $0.53
July $0.18 $0.17 August 0.18 0.18 September 0.18 0.17 Third Quarter
Total $0.54 $0.52 Total Year-to-Date $1.62 $1.57 PRODUCTION AND
DEVELOPMENT CAPITAL SPENDING
____________________________________________________________________
| |Three months ended Sept.|Nine months ended Sept. 30,| | | 30,
2010 | 2010 |
|_______________|________________________|___________________________|
| | Average | Capital | Average | Capital | | |Production |
Spending |Production | Spending | |Play Type | Volumes|($
millions)| Volumes| ($ millions)|
|_______________|___________|____________|___________|_______________|
|Bakken/Tight | 13,039| 51| 10,722| 115| |Oil (BOE/day) | 13,979|
28| 15,209| 64| |Crude Oil | 8,029| 3| 9,068| 9| |Waterfloods | | |
| | |(BOE/day) | | | | | |Conventional | | | | | |Oil (BOE/day) | |
| | |
|_______________|___________|____________|___________|_______________|
|Total Oil | 35,047| 82| 34,999| 188| |(BOE/day) | | | | | | |
11,230| 26| 6,783| 61| |Marcellus Shale| 116,313| 6| 121,805| 14|
|Gas (Mcfe/day) | 82,647| 12| 86,437| 41| |Shallow Gas | 76,741| 2|
79,935| 10| |(Mcfe/day) | | | | | |Tight Gas | | | | | |(Mcfe/day)
| | | | | |Conventional | | | | | |Gas (Mcfe/day) | | | | |
|_______________|___________|____________|___________|_______________|
|Total Gas | 286,931| 46| 294,960| 126| |(Mcfe/day) | | | | |
|_______________|___________|____________|___________|_______________|
|Company Total | 82,869| 128| 84,159| 314|
|_______________|___________|____________|___________|_______________|
DRILLING ACTIVITY Net wells drilled for the three months ended
Sept. 30, 2010
____________________________________________________________________
| | | | | Wells | | | | | | | | Pending | | Dry & | | | | |
|Completion/| Wells|Abandoned| | |Horizontal|Vertical|Total | | On-
| | |Play Type | Wells| Wells| Wells| Tie-in*|stream| Wells|
|____________|__________|________|______|___________|______|_________|
|Bakken/Tight| 11.7| -| 11.7| 10.7| 1.0| -| |oil | 6.2| -| 6.2|
3.1| 3.1| -| |Crude Oil | 2.6| -| 2.6| 2.6| -| -| |Waterfloods | |
| | | | | |Conventional| | | | | | | |Oil | | | | | | |
|____________|__________|________|______|___________|______|_________|
|Total Oil | 20.5 | -| 20.5| 16.4| 4.1| -| | | | | | | | |
|Marcellus | 2.4| 1.0| 3.4| 3.4| -| -| |Shale Gas | -| -| -| -| -|
-| |Shallow Gas | 0.9| -| 0.9| 0.9| -| -| |Tight Gas | 0.2| -| 0.2|
0.2| -| -| |Conventional| | | | | | | |Gas | | | | | | |
|____________|__________|________|______|___________|______|_________|
|Total Gas | 3.5| 1.0| 4.5| 4.5| -| -|
|____________|__________|________|______|___________|______|_________|
|Company | 24.0| 1.0| 25.0| 20.9| 4.1| -| |Total | | | | | | |
|____________|__________|________|______|___________|______|_________|
* includes wells that are pending evaluation BAKKEN/TIGHT OIL The
Bakken/tight oil resource play continues to be a key growth driver
within Enerplus. Production from this play has increased by
approximately 50% this year as a result of our successful
development program and our acquisition activities. We expect
significant growth in production and reserves from this resource
play in the future. Overall we are very encouraged by the results
of our drilling program in North Dakota. At Fort Berthold, five
horizontal wells were drilled during the quarter - three operated
long horizontal wells and two short horizontal wells associated
with our recent acquisition. In addition, two wells drilled in the
second quarter were brought on stream. We now have nine wells
drilled into this play, six of which have been completed to
date. The lateral length of these wells has ranged from 4,300
feet with 12 frac stages for the short lateral wells to 9,000 feet
with 24 frac stages for the long lateral wells. Actual
production results shown in the table below continue to either meet
or materially exceed our type curve estimates. Production
from the long lateral wells was limited due to fluid handling
capacity.
__________________________________________________________________
| |Expected 30 Day |Actual 30 Day | Actual 60 Day | | | Average |
Average |Average Production| | | Production | Production | | | |
Rate/Well | Rate/Well | Rate/Well |
|_______________|________________|______________|__________________|
|Short Lateral | 650 bbls/day| 800 bbls/day| 650 bbls/day| |Wells
(4 wells)| | | |
|_______________|________________|______________|__________________|
|Long Lateral | 1,200 bbls/day|1,190 bbls/day| 1,100 bbls/day|
|Wells (2 wells)| | | |
|_______________|________________|______________|__________________|
First 100 day cumulative production from our two long Bakken
lateral wells totaled 101,000 and 91,000 barrels of oil
respectively. We continue working on our frac design and
procedures, but have been very encouraged to date with rates and
flowing pressures. Gathering infrastructure work is underway both
on and off the Fort Berthold Indian Reservation with midstream
companies to build the necessary infrastructure to allow us to
capture produced gas and additional crude oil volumes. We
anticipate the first well tie-ins will occur late in the fourth
quarter and continue into 2011. Current production from
Enerplus' Fort Berthold area is approximately 4,000 bbls/day. We
currently have two rigs active in Fort Berthold, both drilling
multi-well pads. We plan to add an additional rig at our
Sleeping Giant property in Montana in December which will move
to Fort Berthold after drilling one to two development wells.
Access to service crews continues to be a challenge due to the high
activity levels in the Williston Basin. Given our sizeable
land position as a result of our recent acquisitions, we believe we
can mitigate this issue given our anticipated increase in spending
over the next three to five years. We expect to have long term
service agreements in place by year end that will help us execute
our plans going forward. Production from this area is expected to
grow to over 20,000 BOE/day over the next five years. In Canada,
our activities have been focused on conducting an appraisal of the
lands acquired earlier this year through the drilling of a number
of delineation wells and shooting 3-D seismic. We haven't been able
to drill and complete as many wells as originally planned on our
Saskatchewan Bakken lands and the results to date have been
mixed. Weather has proved to be a significant challenge over
the summer as extremely wet conditions made well sites difficult to
access. Three horizontal wells were drilled during the quarter,
however completion activities were delayed. We are currently
in the process of completing these wells. The completion results
and the seismic information will help us evaluate the potential of
the Saskatchewan land and define future plans for the play.
MARCELLUS SHALE GAS Activity in our Marcellus shale gas play during
the third quarter increased from the second quarter with 14 gross
wells drilled (3.4 net wells) and development spending of $26
million. Production volumes have also increased
significantly, averaging over 11 MMcf/day during the quarter,
almost double the levels we realized in the second quarter.
The majority of our joint venture activities were concentrated in
Lycoming and Susquehanna counties this quarter. In addition to the
14 gross wells that were drilled and awaiting tie in, six gross
wells drilled earlier in the year were also tied in. Early results
indicate these six wells are meeting our performance expectations
with peak 24 hour test rates averaging over 6.2 MMcf/day. Another
seven gross wells were completed and are currently awaiting tie-in.
To date, 93 wells have been drilled across nine counties in
Pennsylvania (Lycoming, Bradford, Susquehanna, Wyoming, Clearfield,
Blair, Somerset, Greene and Fayette) as well as Marshall County in
West Virginia. Expected ultimate recoveries range from 3.75 Bcf to
7 Bcf per well, varying by county, Marcellus thickness and lateral
length. As discussed earlier this year, lateral lengths and the
number of frac stages are increasing with the most recent wells
ranging from 4,300 to 5,800 foot lateral lengths with 10 to 15 frac
stages. As a result of the longer lateral length and increased frac
stages, well costs are trending higher, however initial production
rates and expected ultimate recoveries are increasing as
well. There are currently 42 wells on production, 15 wells
waiting on pipeline and 36 wells waiting on completion.
Another 20 wells are being drilled or remain to be drilled in 2010,
with activity planned for northeast Pennsylvania, south central
Pennsylvania, and Marshall County, West Virginia. Similar to our
experience in the Bakken play, high activity levels have strained
service company availability and impacted our completions
activity. A number of wells were only partially completed
during the quarter due to crew availability and will now be
completed in the fourth quarter of 2010 or the early part of 2011.
As a result, some volumes anticipated at year end may now come on
production in early 2011. We currently have eight rigs running in
the play and expect an additional rig may be added before the end
of the year. Production volumes in early November were
approximately 16 MMcf/day. Enerplus operated activity commenced
with construction on the pad site of our first operated horizontal
well in Clinton County, Pennsylvania during the quarter.
Drilling is currently underway with a planned horizontal length of
4,500 feet. WATERFLOODS Our waterflood projects continue to
be a core focus area within Enerplus' portfolio, representing
approximately 18% of our daily production volumes. Approximately
$64 million has been spent year to date drilling 26 net wells and
improving/expanding facilities to support our future plans. As a
result of our 2010 capital investment activities, we expect
production volumes will be maintained year-over-year excluding
production volumes sold through our disposition program. During the
third quarter, the majority of our activities occurred at our Freda
Lake Ratcliffe property in Saskatchewan. Six horizontal wells
have been drilled in the last year (three in the third quarter)
resulting in a 140% increase in production from approximately 500
bbls/day at the start of 2010 to 1,200 bbls/day currently. Three
dual lateral wells and three single lateral wells have been drilled
with 30 day initial production rates of 200 to 300 bbls/day from
the dual lateral wells. We are in the process of completing the
single lateral wells and expect initial production rates of over
100 bbls/day. To date, the decline rates have also been better than
expected. Our activities have also included facility upgrades and
increased production and water handling capacity in order to
accommodate the current and future increases in production volumes.
We plan to drill another five single lateral wells in the fourth
quarter in addition to 11 injector well conversions. Our
Saskatchewan land acquisitions earlier this year also added acreage
with rights to the Ratcliffe formation which will enhance our
future development plans in this area. Based upon our current
acreage, we see two to three years of drilling potential similar to
this year's activity that will maintain production volumes. We also
commenced a horizontal drilling program at our Gleneath waterflood
property. This waterflood has been producing exclusively from
vertical wells drilled into the Viking light crude oil
formation. We drilled and completed two horizontal wells
during the third quarter. Initial flowing test rates indicate these
wells could produce approximately 100 bbls/day per well once they
are placed on pump, in line with our 30 day type curve. We plan to
drill another four wells during the fourth quarter. Depending upon
the success of this activity, we believe there are 20 to 30 future
drilling locations at Gleneath. OUTLOOK FOR THE REMAINDER OF 2010
As we announced in September, we expect annual production to
average 83,000 to 84,000 BOE/day, with an exit rate of 80,000 to
82,000 BOE/day taking into account the impact of the assets we sold
or expect to sell this year. Service crew availability
remains a challenge and could pose a potential for delays in
completing a number of high impact wells in the Bakken and
Marcellus regions. Should we experience delays in obtaining
services and also given the level of capital spending planned for
the fourth quarter of this year we may be challenged to spend our
entire capital budget in 2010. If this occurs, exit
production rates would be impacted but with the expectation that
the planned activities would be completed early in 2011. We
continue to expect to invest $515 million in development capital in
2010 with operating cost and G&A cost guidance of $10.20/BOE
and $2.45/BOE respectively. CORPORATE CONVERSION On September 30,
2010, we formally announced our plans to convert to a dividend
paying corporation January 1, 2011. We plan to hold a Special
Meeting of Unitholders on December 9, 2010 in Calgary, Alberta to
vote on the conversion and, subject to Unitholder approval and
obtaining all of the necessary Court and regulatory approvals, we
would convert to a corporation effective January 1, 2011. We have
proposed a straight forward conversion to our Unitholders. We will
exchange one trust unit of Enerplus Resources Fund for one share in
Enerplus Corporation. This exchange will be tax-deferred and will
not result in a capital gain or loss to our Unitholders. Our ticker
symbols will remain the same as will our corporate brand. Further,
the conversion will not result in the acceleration or vesting of
any compensation or incentive based awards to any employees or
Directors of Enerplus. We intend to continue to pay monthly
dividends to investors after the conversion and expect to maintain
the current rate of $0.18/share through the conversion. This
dividend level is based upon commodity prices, debt levels, capital
spending and other factors and may fluctuate in the future.
We will also utilize our available tax pools to mitigate our
Canadian cash tax obligations and do not expect to incur cash taxes
in Canada for three to five years after conversion. For more
information on the conversion and how to cast your vote, details
can be found at www.enerplus.com. We look forward to your
support on December 9(th). CONSOLIDATED FINANCIAL STATEMENTS AND
MD&A Third 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. "Mcfe" means
thousand 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 Mcfes. Mcfes may be
misleading, particularly if used in isolation. An Mcfe 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. Under Canadian
disclosure requirements and industry practice, production is
reported using gross volumes, which are volumes prior to deduction
of royalty and similar payments. The practice in the United States
is to report production using net volumes, after deduction of
applicable royalties and similar payments. Readers are
also urged to review the Management's Discussion & Analysis and
financial statements for the three and nine months ended September
30, 2010 filed on SEDAR and EDGAR concurrently with this news
release for more complete disclosure on our operations.
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: Enerplus' strategy and future growth potential in
production and reserves; the expected disposition of certain
non-core assets in the fourth quarter of 2010; future drilling
plans and prospects and well tie-ins; our ability to mitigate
shortages in service crews; future production levels and increases,
including average 2010 and year-end 2010 exit production levels;
capital expenditure levels and the timing thereof; operating and
G&A costs; the conversion of Enerplus from an income trust to a
corporation, the timing thereof and the tax treatment to
unitholders; the amount and timing of cash dividends to
Enerplus shareholders; and the Fund's income taxes, tax liabilities
and tax pools. 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 Enerplus including, without limitation: that
Enerplus 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 Enerplus' capital and operating requirements as
needed; the continuance of existing and, in certain circumstances,
proposed tax and royalty regimes; that there will be willing buyers
of certain of Enerplus' oil and gas assets on terms acceptable to
Enerplus; that all required conditions to complete the conversion
of Enerplus from a trust to a corporation will be obtained or
satisfied; the accuracy of the estimates of Enerplus' reserve and
resource volumes; acquisition and disposition activity and certain
commodity price 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
results or production declines; changes in tax or environmental
laws or royalty rates; increased debt levels or debt service
requirements; failure to complete anticipated asset sales; failure
to obtain all necessary approvals and satisfy all conditions for
the conversion of Enerplus from an income trust to a corporation;
inaccurate estimates of tax pools and future income tax
liabilities; inaccurate estimation of Enerplus' 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 including
a continued shortage of service crews; and certain other risks
detailed from time to time in the Fund's public disclosure
documents including, without limitation, those risks identified in
our MD&A for the three and nine months ended September 30,
2010, 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 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. 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. Refer to the Liquidity and Capital Resources section of
our Management's Discussion and Analysis for the three and nine
months ended September 30, 2010 for further information.
Gordon J. Kerr President & Chief Executive Officer Enerplus
Resources Fund %CIK: 0001126874 pregarding this news release or a
copy of our 2010 third quarter interim report, please contact our
investor relations department at 1-800-319-6462 or email a
href="mailto:investorrelations@enerplus.com"investorrelations@enerplus.com/a./p
Copyright
Enerplus (NYSE:ERF)
Historical Stock Chart
From Jun 2024 to Jul 2024
Enerplus (NYSE:ERF)
Historical Stock Chart
From Jul 2023 to Jul 2024