CALGARY, Dec. 17 /CNW/ -- This news release includes
forward-looking statements and information within the meaning of
applicable securities laws. Readers are advised to review the
"Cautionary Note Regarding Forward-Looking Information and
Statements" at the conclusion of this news release. For
information regarding the presentation of certain information in
this news release, see "Currency, BOE and Operational Information"
at the conclusion of this news release. CALGARY, Dec. 17 /CNW/ -
Enerplus Resources Fund ("Enerplus") (TSX - ERF.un, NYSE - ERF)
today announced capital spending and operational guidance for 2011
and a preliminary outlook for 2012 that is expected to result in
organic growth in production and reserves. Throughout the
past 18 months, Enerplus has captured over 475,000 net acres of
prospective land primarily in two of the most economic plays in
North America - the Bakken light oil play and the Marcellus gas
play. In addition, the sale of over 10,000 BOE/day of
non-core assets as well as our Kirby oil sands lease has helped
finance our acquisition activities and improved our operational
focus and profitability. We have a foundation of mature, low
production decline properties that complement our new growth assets
that we believe provides a stable platform of production and cash
flow from operating activities from which to grow. We believe our
strategy provides a compelling investment opportunity comprised of
yield and growth. Initially a large portion of our total return
will be comprised of dividend yield, but as the development of our
growth plays accelerates, we expect to complement our dividend with
repeatable annual growth in production and reserves per share.
HIGHLIGHTS: -- 2011 capital spending is anticipated to increase by
over 25% to $650 million with 65% projected to be invested in oil
projects. We expect to focus approximately 85% of our spending on
our Bakken, Waterflood and Marcellus resource plays. A minimum
level of capital investment is planned for our natural gas assets
with the majority directed to our non-operated Marcellus interests
to further delineate the resource and preserve our lease positions.
We also expect a similar level and allocation of spending in 2012.
-- Production is expected to grow by 10% - 15% over the next two
years, exiting 2012 in the range of 86,000 - 90,000 BOE/day. Crude
oil volumes are expected to increase more than 20% over the next
two years and will represent approximately 48% of total volumes by
the end of 2012. -- In 2011, we expect annual production to average
78,000 - 80,000 BOE/day, increasing to 80,000 - 84,000 BOE/day by
year end. Given the longer lead time to production associated with
a majority of our capital spending in the Marcellus and the Bakken,
up to 40% of the production associated with our 2011 drilling
program will not come on stream until the remaining completion and
tie-in capital is expended in 2012. -- Light oil production is
expected to grow by over 20% as we exit 2011. Natural gas volumes
are expected to remain essentially flat throughout the year however
we anticipate shallow gas production will decline and be replaced
by more profitable natural gas from the Marcellus. -- Based upon
the current forward commodity price markets, we project cash flow
from operating activities ("cash flow") will grow by approximately
15% by 2012 as a result of increased production, the higher oil
weighting in the portfolio and higher crude oil prices. Cash flow
in 2011 is expected to be relatively unchanged from 2010 levels
despite selling 10,000 BOE/day of production throughout 2010. This
is mainly a result of the increase in crude oil volumes and the
increased price outlook for crude oil. -- We expect rates of return
on our oil projects to range from 35% to over 100% based on current
forward prices. Returns on our natural gas investments, the
majority of which are being made to delineate and retain land
positions, are expected to exceed 15% in today's natural gas price.
We are targeting finding and development costs on our oil
properties of approximately $20/bbl and $2.00/Mcf on our natural
gas assets. -- Approximately $140 million of our 2011 expenditures
are expected to be directed to natural gas delineation activities
in areas such as the Marcellus and the Western Canadian Deep Basin.
We do not expect this spending to result in meaningful production
additions in 2011 but will provide valuable insight into the
viability and opportunity within new play areas. -- We intend to
continue to distribute a significant portion of the cash flow that
is generated from our operations and plan to maintain our monthly
dividend rate of $0.18/share in our forecast for the next two
years. However, we will continue to examine dividend levels as the
results of our capital spending plans unfold and commodity price.
-- We expect our capital spending and dividends to exceed our cash
flow in both 2011 and 2012 however our balance sheet provides us
with the financial flexibility to support our plans. In order to
maintain our financial strength beyond 2011, we have assumed the
sale of non-cash flow generating assets within our private equity
portfolio or a portion of our non-operated working interests in the
Marcellus in 2012. Thereafter, our debt-to-cash flow levels are
expected to decline as production from our growth plays
accelerates. We have not assumed any equity issuance beyond normal
dividend reinvestment participation in our modeling. We expect our
2011 exit debt-to-cash flow ratio to be 1.7 times and 2 times by
the end of 2012 based upon the current forward commodity markets.
2011 & 2012 Estimates*
____________________________________________________________________
| | 2011| 2012|
|________________________________|_________________|_________________|
|Capital Expenditures ($millions)| $650| $675|
|________________________________|_________________|_________________|
|Oil & Liquids Weighting | 65%| 65%|
|________________________________|_________________|_________________|
| | | |
|________________________________|_________________|_________________|
|Annual Average Daily Production:| | |
|________________________________|_________________|_________________|
| Oil & Natural Gas Liquids | 36,000 - 37,500| 39,000 - 41,000|
|(bbls/day) | | |
|________________________________|_________________|_________________|
| Natural Gas (Mcf/day) |250,000 - 256,000|260,000 - 265,000|
|________________________________|_________________|_________________|
| Total (BOE/day) | 78,000 - 80,000| 83,000 - 85,000|
|________________________________|_________________|_________________|
|Oil & Liquids Weighting | 47%| 48%|
|________________________________|_________________|_________________|
| | | |
|________________________________|_________________|_________________|
|Exit Production (BOE/day) | | |
|________________________________|_________________|_________________|
| Oil & Natural Gas Liquids | 39,000 - 41,500| 43,000 - 45,000|
|(bbls/day) | | |
|________________________________|_________________|_________________|
| Natural Gas (Mcf/day) |247,000 - 257,000|255,000 - 270,000|
|________________________________|_________________|_________________|
| Total (BOE/day) | 80,000 - 84,000| 86,000 - 90,000|
|________________________________|_________________|_________________|
|Exit Change Year-over-Year | 5%| 8%|
|________________________________|_________________|_________________|
|Oil & Liquids Weighting | 48%| 50%|
|________________________________|_________________|_________________|
| | | |
|________________________________|_________________|_________________|
|Cash Flow From Operating | $700| $800| |Activities ($millions) | |
|
|________________________________|_________________|_________________|
|Oil & Liquids Weighting | ~70%| 70%|
|________________________________|_________________|_________________|
| | | |
|________________________________|_________________|_________________|
|Simple Payout Ratio ((1)) | 55%| 50%|
|________________________________|_________________|_________________|
|Adjusted Payout Ratio ((1)) | 150%| 135%|
|________________________________|_________________|_________________|
| | | |
|________________________________|_________________|_________________|
|Debt/Cash Flow at Year-End* | 1.7x| 2.0x|
|________________________________|_________________|_________________|
| | | |
|________________________________|_________________|_________________|
*Assumptions: Based upon the forward commodity prices and forecast
costs as of December 8, 2010 including the impact of hedging. Based
upon our current capital spending plans for Q42010, forecast YE2010
debt is approximately $750 million. (1) Payout ratio is calculated
as dividends paid to shareholders divided by cash flow from
operating activities. Adjusted payout ratio is calculated as the
sum of dividends paid to shareholders plus development capital and
office expenditures divided by cash flow from operating activities.
See "Non-GAAP Measures" below. 2011 and 2012 debt calculations
include Marcellus carry commitments of $116 million and $66 million
respectively. Monthly dividends held constant at CDN$0.18/share
through 2011 and 2012. Recover in 2012 of $40 million in U.S. tax
previously paid. Assumes $80 million of disposition proceeds in
2012 from equity investment portfolio or portion of operated
Marcellus interest. 2011 Capital Spending & Production Outlook
We are targeting a capital spending program of $650 million in
2011, with approximately 70% of our spending directed to our Bakken
and Marcellus properties where we expect to see significant growth
in production and 15% to our waterflood assets where we expect to
maintain production volumes. We plan to spend over $435 million on
development drilling, recompletions and facilities, $140 million on
delineation activities, $29 million on maintenance activities and
$44 million on seismic. In total, approximately 113 net wells
are planned, two thirds of which we would operate and 95% of which
would be horizontal wells. As a result of this spending, we expect
annual 2011 production to average 78,000 - 80,000 BOE/day,
essentially unchanged from exit 2010, and to increase to 80,000 -
84,000 BOE/day by year-end. Oil and liquids production is
expected to grow 15% by year-end and should represent 48% of total
volumes at that time. Shallow gas and other conventional oil
and gas production is expected to decline throughout the year due
to reduced capital investment and marginal economic returns in the
current natural gas price environment. As a result of our
divestment activities in 2010 and our increased focus on growth
plays in 2011, we expect our decline rate will increase from 18% to
approximately 22% - 23% in 2011. We intend to spend our capital
budget relatively evenly throughout 2011 and have not assumed any
material acquisitions or divestments. We will review our 2011
capital investment plans regularly throughout the year in the
context of prevailing economic conditions and potential
acquisitions, and make adjustments when necessary. Key
2011 Capital Spending Plans & Estimated Production
____________________________________________________________________
| | | #|2010E Exit| 2011E | | | |Capital|of net|Production|Exit
Production| +/-% | |Resource Play| ($MM)| wells| (BOE/d)|
(BOE/d)|Exit to Exit|
|_____________|_______|______|__________|_______________|____________|
| | | | | | |
|_____________|_______|______|__________|_______________|____________|
|Bakken/Tight | | 48| 13,000|18,000 - 21,000| 50| |Oil | 300| | | |
|
|_____________|_______|______|__________|_______________|____________|
|Waterfloods | 110| 26| 14,500|13,500 - 15,000| -|
|_____________|_______|______|__________|_______________|____________|
|Marcellus | | 27| 3,000| 7,000 - 8,000| 150| |Shale Gas | 160| | |
| |
|_____________|_______|______|__________|_______________|____________|
| | | | | | |
|_____________|_______|______|__________|_______________|____________|
|Resource Play| | 101| 30,500|38,500 - 44,000| 35| |Total | $570| |
| | |
|_____________|_______|______|__________|_______________|____________|
Crude Oil Investment Bakken We expect to direct approximately 65%
of our 2011 development spending toward oil projects, with the
Bakken portfolio attracting $300 million of this spending.
The majority of our Bakken activity will be focused at Fort
Berthold, North Dakota where we hold over 70,000 net acres (110
sections) of undeveloped land that is prospective for both the
Bakken and Three Forks formations. To date in Fort Berthold, we've
drilled four short horizontal wells and three long horizontal wells
into the play targeting the Bakken and results have exceeded our
expectations. As we move into the development stage, we
expect production to grow from 4,000 bbls/day currently to over
20,000 BOE/day over the next four years. We are currently planning
a drilling density at Fort Berthold for the Bakken of two short
horizontal wells (~4,300 feet with 12 frac stages) per 640 acre
spacing or two long horizontal wells (~9,000 feet with 24 frac
stages) per 1,280 acre spacing. Assuming 85% of the
land is prospective, this would result in 95 - 185 future Bakken
horizontal drilling locations, depending upon the number of long
versus short wells. Based upon current commodity prices and our
type curves, we estimate short lateral wells have a net present
value (before income taxes discounted at 12%) of $2.2 million to $5
million and are expected to achieve payout in two to three years.
Under the same assumptions, long horizontal wells would have an
estimated net present value of $8.4 million to $14 million and are
expected to achieve payout in less than 1.7 years. Given the
more attractive economics associated with the long lateral wells,
we expect that at least 75% of our drilling activity will be long
lateral wells. The Three Forks formation underlies the Bakken
throughout our entire acreage position at Fort Berthold. We plan to
drill a number of Three Forks wells in 2011 to evaluate the
potential and future prospectivity of this zone. In 2011, we plan
to have three to four rigs working in the play and expect to drill
approximately 32 net operated wells (~90% working interest) and
participate in another two net non-operated wells. We
recently entered into agreements to secure rigs and access to frac
services and proppant which will help to ensure the timely
execution of our plans. We also expect to have mid-stream
arrangements in place by the middle of 2011 which will allow us to
capture the associated natural gas volumes. Due to the high initial
production rates associated with these wells, it will be
challenging to predict exit production rates. As such, exit rates
may vary considerably based upon when new wells come on stream.
_____________________________________________________________________
| | Fort Berthold Bakken Wells |
|_____________|_______________________________________________________|
| | Type Curve Estimate | Actual Results to Date |
|_____________|_________________________|_____________________________|
| | | Average |Long Laterals |Short Laterals| | | Average | Short |
(2 well | (4 well | | |Long Laterals| Laterals | average) |
average) |
|_____________|_____________|___________|______________|______________|
| | | | | |
|_____________|_____________|___________|______________|______________|
|Average 30 | | | | | |Day Initial |1,100 - 1,200| 550 - 650| | |
|Production | bbls/day| bbls/day|1,190 bbls/day| 800 bbls/day|
|_____________|_____________|___________|______________|______________|
|Expected | | | | | |Ultimate | 600 - 800| 300 - 400| | | |Recovery
| Mbbls| Mbbls| | |
|_____________|_____________|___________|______________|______________|
|Cost/Well | $8 million| $6 million| $8 million| $6 million|
|_____________|_____________|___________|______________|______________|
|120 Day | | | | | |Cumulative | | | | | |Production ( | | | | |
|(1)) | 81 Mbbls| 40 Mbbls| 108 Mbbls| 59 Mbbls|
|_____________|_____________|___________|______________|______________|
| | | | | |
|_____________|_____________|___________|______________|______________|
|Net Present | | | | | |Value ( | $8.4 - $14.0|$2.2 - $5.0| | |
|(2))/well | million| million| | |
|_____________|_____________|___________|______________|______________|
|Netback ((3))| ~$48/bbl| ~$48/bbl| | |
|_____________|_____________|___________|______________|______________|
|Payout Period| 1 to 1.7| 2 to 3.0| | | |(years) | years| years| |
|
|_____________|_____________|___________|______________|______________|
(1) Net present value before income taxes discounted at 12% using
forward commodity price assumptions at December 8, 2010 (2) Only 2
long lateral wells have been on production for 120 days. Average 30
day initial production rates for 3 long lateral wells is 1,175
bbls/day (3) Netback is used to measure operating performance and
is calculated by subtracting Enerplus' expected royalties and
operating costs from the anticipated revenues in respect of the
relevant properties. See "Non-GAAP Measures" below. In our other
Bakken prospects, six gross wells (four net) expected to be drilled
at Sleeping Giant in Montana, three of which will be long laterals.
We continue to evaluate options regarding enhanced oil recovery
opportunities as the number of drilling locations remaining within
this property becomes limited. At Oungre, Saskatchewan, we are
currently evaluating the results of two horizontal wells recently
completed. We are also currently shooting seismic to further
evaluate the Bakken and Ratcliffe potential in the
Freda/Neptune/Oungre area. As a result of our capital
spending across our entire Bakken/tight oil resource play in 2011,
we expect production volumes will grow by 50%, exiting the year in
the range of 18,000 - 20,000 BOE/day. Waterfloods Our waterflood
portfolio is comprised of a variety of crude oil properties in
various plays, such as the Glauconitic, Viking, Cardium, and
Ratcliffe. These mature assets have significant amounts of
original oil in place ("OOIP") with recovery to date of
approximately 22%. The average quality of oil in these play
areas is approximately 30 degree API. Our plans for 2011 include
drilling production and injection wells at our Medicine Hat, Freda
Ratcliffe, Gleneath and Pembina 5-Way properties to increase oil
production and maintain and/or improve reservoir pressures. In
addition, we expect to invest in facility improvements to support
future development plans and plan to continue work on two polymer
pilots at Giltedge and Medicine Hat to increase ultimate
recoveries. The base production decline rate from these
properties is approximately 16%. We plan to invest over $100
million, maintaining production volumes throughout the year at
approximately 14,000 BOE/day. A significant portion of this
capital is being directed to activities that we believe will
position us for future production and reserve growth. Our
waterflood properties are an important part of our future strategy
as they generate a significant amount of free cash flow (cash flow
after capital expenditures) to support our dividend and growth
strategy. At December 31, 2009, we had 77 million BOE of
proved plus probable reserves booked to our waterfloods,
representing an estimated recovery factor of 27%. We believe that
through continued drilling and optimization as well as the
application of enhanced oil recovery schemes, we could improve the
ultimate recovery of oil from these pools to between 30% and 37%.
This could add 50 - 150 million barrels of crude oil and associated
natural gas to Enerplus' booked reserves. Natural Gas Investment
With the current natural gas price outlook we plan to minimize our
spending on our natural gas assets in 2011. Our efforts will be
focused on delineating lease positions in new areas.
Approximately $230 million is expected to be invested into our
natural gas assets in 2011, $160 million of which is planned for
our Marcellus interests. The majority of the remainder of our
natural gas spending is planned in the Deep Basin area where we
hold over 65,000 net acres of undeveloped land. We plan to
drill four delineation wells targeting the Stacked Mannville in the
South Ansell area where other producers have had recent
success. Our shallow gas activities will consist of
recompletion activities at Shackleton. As a result of the decrease
in spending in our tight and shallow gas resource plays, we expect
production volumes from these plays will decline throughout 2011.
Marcellus Approximately $160 million is planned for the Marcellus,
the majority of which is anticipated to be spent on our
non-operated interests. With our joint venture partner, we
plan to have eight to ten rigs working throughout the play in 2011
and expect to drill 150 gross wells (22.4 net). We also
expect to complete approximately 121 wells and we plan to have 94
new wells on stream by the end of the year. Due to the timing
of infrastructure, accessing frac crews and permitting, the
estimated cycle time from commencement of drilling to production
tie-in is approximately nine months. As a result of this timeframe,
close to 75% of the wells that we plan to drill in 2011 will not be
tied-in until 2012. Production in 2011 is expected to grow by
150% to 45 MMcf/day by year-end. There are currently 42 gross wells
on stream producing approximately 100 MMcf/day gross of natural
gas. A further 45 MMcf/day of production is currently awaiting
infrastructure, completion or tie-in. Well results over the
past 18 months have either met or exceeded our expectations.
Cumulative production on eight wells that have been on production
for six months have ranged from 450 MMcf to 1.5 Bcf of natural gas
per well with average 180 day cumulative production of 785
MMcf. We have increased our type curve expectations in the
Marcellus from 3.0 - 3.5 Bcf/well originally to 3.5 - 6.0
Bcf/well. Well costs have also increased due to the drilling
of longer lateral lengths with more frac stages. In 2011 we
estimate average well costs to range from $4.5 million to $6.0
million per well based upon drilling 3,500 - 5,000 foot lateral
lengths with 8 - 12 frac stages. As a greater percentage of our
drilling program moves into the development stage, we would expect
well costs to decrease due to established water infrastructure and
pad drilling. The table below illustrates the economics associated
with a range of type wells under different natural gas price
scenarios. We have assumed a $6 million cost per well under
each scenario. Marcellus Dry Gas Economics
________________________________________________________________ |
| 4.0 Bcf well | 5.0 Bcf well | 6.0 Bcf well |
|_______|__________________|__________________|__________________|
| NYMEX | |Payout|NPV 12%| |Payout|NPV 12%| |Payout|NPV 12%|
|$/MMbtu|IRR|years | ($MM) |IRR|years | ($MM) |IRR|years | ($MM) |
|_______|___|______|_______|___|______|_______|___|______|_______|
| $6.00 |27%| 3.4 | $2.51 |41%| 2.5 | $4.57 |57%| 2.0 | $6.62 |
|_______|___|______|_______|___|______|_______|___|______|_______|
| $5.00 |16%| 4.9 | $0.75 |26%| 3.4 | $2.37 |37%| 2.6 | $3.99 |
|_______|___|______|_______|___|______|_______|___|______|_______|
| $4.00 |7% | 8.6 |($1.02)|13%| 5.7 | $0.17 |20%| 4.2 | $1.35 |
|_______|___|______|_______|___|______|_______|___|______|_______|
We expect approximately 25% of our spending in 2011 will be focused
on drilling in the liquids rich area of southwest Pennsylvania and
northern West Virginia where the associated natural gas liquids
provide better economics and the well costs are closer to $5
million. This improves the internal rate of return on a
typical 4.0 Bcf well from 7% to 21% in a $4 NYMEX gas price
environment and improves the net present value before income taxes
discounted at 12% from -$1.02 million to $1.34 million. These
liquids rich wells are expected to have a breakeven supply cost of
approximately $3.70/Mcf. Approximately 30% of our spending is
expected to be directed to delineation activity to preserve our
lease positions and identify future potential. We plan to
spend the remaining 45% of our capital budget on development
drilling in counties where we expect ultimate recoveries in the 4.5
- 5.5 Bcf range. We also expect to drill five gross operated
delineation wells (4 net) on our new Marcellus leases in 2011.
Costs As a result of the sale of non-core, lower margin properties,
operating costs in 2010 have decreased by 6% to approximately
$10.20/BOE from our original guidance of $10.90/BOE. We
expect to see a further reduction in operating costs in 2011 to
approximately $9.20/BOE due to a full year impact of the
dispositions and the addition of lower cost production associated
with our Bakken and Marcellus plays. In order to improve our
operational effectiveness, Enerplus has been actively working to
improve not only our underlying asset base, but also our internal
technical capabilities. We have increased our staffing levels
within our U.S. operations by 50% in order to effectively manage
our growing portfolio in the Bakken and the Marcellus and have also
increased our technical capabilities within our Canadian
operations. These changes have resulted in an increase in our
general and administrative costs ("G&A"). The adoption of
International Financial Reporting Standards ("IFRS") will also
impact our G&A expenses going forward. Previously staff costs
associated with our acquisition and divestment activities were
capitalized however under IFRS, these costs will now be expensed.
They are expected to contribute approximately $0.20/BOE of
incremental cost to our G&A expense. As a result of these
changes and lower annual average production volumes expected in
2011 due to asset sales in 2010, we expect G&A costs will
average approximately $3.30/BOE for the year. As our capital
plans are executed and production volumes increase throughout 2011
and into 2012, we expect to see a reduction in per BOE G&A
expenses. In the context of current forward commodity prices, we
expect Crown and freehold royalties to be approximately 20% of our
gross oil and gas sales in 2011 up from 18% in 2010 due to the
increase in oil weighting within our portfolio and a stronger
outlook for oil prices in 2011 compared to 2010. Taxes Enerplus has
received Unitholder and court approval to convert to a corporation
effective January 1, 2011. As such, we will be subject to taxation
at the same level as other Canadian corporations. Enerplus
currently has approximately $3 billion in tax pools that we plan to
utilize to meet our tax obligations in Canada and therefore do not
expect to pay cash taxes in Canada for three to five years.
As a result of the higher capital spending in our U.S. operations,
we expect cash taxes in the U.S. will be less than 5% of U.S. cash
flow in 2011. Hedging Our hedging program is designed to protect a
portion of our cash flow to support our capital spending plans, the
economics of our acquisitions and the dividend component of our
business model. Typically we will hedge forward with a view
to providing downside protection in the event commodity prices fall
while attempting to maintain some of the upside of future price
improvements. Based upon the current forward market, Enerplus has
floor protection on approximately 56% of our forecast 2011 crude
oil production net of royalties at an effective price of
US$87.10/bbl. For the first quarter of 2011, we have approximately
32% of our projected 2011 natural gas production volumes, net of
royalties, hedged at an effective price of $6.14/Mcf. For 2012, we
have approximately 7% of our projected crude oil production net of
royalties hedged at an effective price of $90.29/bbl. We
expect to continue our price risk management program by adding to
our crude oil hedge positions however we are reluctant to hedge any
significant natural gas volumes in the current low price
environment. Acquisitions & Divestments As part of our on-going
business, we expect to acquire additional assets in key areas that
fit with our business strategies and also divest of assets that are
no longer part of our future plans. We do not have any specific
plans to package and sell any significant producing non-core
properties in 2011. As previously stated we expect to sell non-cash
flow generating assets from our portfolio of equity investments or
sell part of our non-operated Marcellus interests in 2012 in order
to preserve our financial flexibility. As part of our
original acquisition agreement, we expect to spend $116 million on
our capital carry commitments associated with the Marcellus in
2011. Outlook We are positioning Enerplus to deliver competitive
long-term returns that include a balance between growth and income
to investors. We've made significant strides in repositioning our
asset base and now have meaningful growth opportunities in our
portfolio. We also have a strong foundation of mature, cash
generating assets that can support our growth and income
strategy. We have maintained our financial flexibility
throughout the past 18 months and our strong balance sheet will
assist us in executing our strategy. Initially, a large portion of
our total return will be comprised of dividend yield but as the
development of our growth plays accelerates, we expect to
supplement our dividend with sustainable growth in production and
reserves per share. Gordon J. Kerr President & Chief Executive
Officer Enerplus Resources Fund Currency, BOE and Operational
Information All dollar amounts or references to "$" in this news
release are in Canadian dollars unless specified otherwise.
Enerplus has adopted the standard of 6 Mcf:1 BOE when converting
natural gas to BOEs. BOEs may be misleading, particularly if used
in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an
energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the
wellhead. Unless otherwise stated, all oil and gas production
information and estimates are presented on a gross basis, before
deducting royalty interests. Cautionary Note Regarding
Forward-Looking Information and Statements This news release
contains certain forward-looking information and statements within
the meaning of applicable securities laws. The use of any of the
words "expect", "anticipate", "continue", "estimate", "budget",
"guidance", "objective", "ongoing", "may", "will", "project",
"should", "believe", "plans", "intends", "strategy" and similar
expressions are intended to identify forward-looking information or
statements. In particular, but without limiting the foregoing, this
news release contains forward-looking information and statements
pertaining to the following: future capital spending amounts
(including capital carry commitments), the timing thereof and the
types of projects on which such capital will be spent; future
growth opportunities; future oil, natural gas liquids and natural
gas production levels, the product mix of such production and
production decline rates; future cash flow levels; rates of return
on our expenditures, investments and projects; the expected
ultimate recovery of oil or gas from a particular well; finding and
development costs, operating costs, general and administrative
expenses and royalty expenses; sales of our equity portfolio and
our non-operated working interests in the Marcellus play and the
redeployment of proceeds realized there from; dividend payments
made by Enerplus and the related payout and adjusted payout ratios;
returns to our securityholders; debt levels and debt to cash flow
ratios; drilling plans and results, including production rates,
recovery factors, the cost, netback and net present value per well
and well payout periods; the potential impact of IFRS on our
financial and operating results; our conversion from an income
trust to a corporation and the timing and payment of future taxes
as a result; our planned commodity risk management program; and
future liquidity, debt levels and financial capacity and
resources. The forward-looking information and statements
contained in this news release reflect several material factors and
expectations and assumptions of Enerplus including, without
limitation: that Enerplus will achieve operational, production and
drilling results as anticipated; the general continuance of current
or, where applicable, assumed industry conditions; commodity prices
will remain within Enerplus' expected range of forecast prices;
availability of adequate cash flow, debt and/or equity sources to
fund Enerplus' capital and operating requirements as needed and to
pay dividends to shareholders as anticipated; the continuance of
existing and, in certain circumstances, proposed tax and royalty
regimes; availability of willing buyers for the properties proposed
to be disposed of; that capital, operating and financing costs will
not exceed Enerplus' current expectations; availability of third
party service providers (including drilling rigs and service crews)
and cooperation of industry partners; and certain foreign exchange
rate and other cost assumptions. Enerplus believes the material
factors, expectations and assumptions reflected in the
forward-looking information and statements are reasonable at this
time but no assurance can be given that these factors, expectations
and assumptions will prove to be correct. The
forward-looking information and statements included in this news
release are not guarantees of future performance and should not be
unduly relied upon. Such information and statements involve known
and unknown risks, uncertainties and other factors that may cause
actual results or events to differ materially from those
anticipated in such forward-looking information or statements
including, without limitation: changes in commodity prices;
unanticipated operating or drilling results or production declines;
changes in tax or environmental laws or royalty rates; failure to
receive required third party approvals; increased debt levels or
debt service requirements; insufficient available cash to pay
dividends as currently anticipated; inaccurate estimation of or
changes to estimates of Enerplus' oil and gas reserves and
resources volumes and the assumptions relating thereto; limited,
unfavourable or no access to debt or equity capital markets;
increased costs and expenses; a shortage of third party service
providers; the impact of competitors; reliance on industry
partners; an inability to agree to terms with potential buyers of
assets that may be disposed of; and certain other risks detailed
from time to time in Enerplus' public disclosure documents
including, without limitation, those risks identified in our
MD&A for the year ended December 31, 2009 and in
Enerplus' Annual Information Form dated March 13, 2010 for
the year ended December 31, 2009, copies of which are available on
Enerplus' SEDAR profile at www.sedar.com and which also form part
of Enerplus' annual report on Form 40-F for the year ended December
31, 2009 filed with the United States Securities and Exchange
Commission, a copy of which is available at www.sec.gov. The
forward-looking information and statements contained in this news
release speak only as of the date of this news release, and
Enerplus assumes no obligation to publicly update or revise them to
reflect new events or circumstances, except as may be required
pursuant to applicable laws. Non-GAAP Measures Throughout this news
release we use the term "payout ratio" and "adjusted payout ratio"
to measure operating performance, leverage and liquidity. We
calculate payout ratio by dividing dividends paid to shareholders
by cash flow. "Adjusted payout ratio" is calculated as dividends
paid to shareholders plus development capital and office
expenditures divided by cash flow. The terms "payout ratio" and
"adjusted payout ratio" do not have a standardized meaning or
definition as prescribed by GAAP and therefore may not be
comparable with the calculation of similar measures by other
entities. Netback is used to measure operating performance and is
calculated by subtracting Enerplus' expected royalties and
operating costs from the anticipated revenues in respect of the
relevant properties. The term "netback" does not have a
standardized meaning or definition as prescribed by GAAP and
therefore may not be comparable with the calculation of similar
measures by other entities. To view this news release in HTML
formatting, please use the following URL:
http://www.newswire.ca/en/releases/archive/December2010/17/c6102.html
pplease contact our Investor Relations Department at 1-800-319-6462
or email a href="mailto:investorrelations@enerplus.com"
cr="true"investorrelations@enerplus.com/a/p
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