Enerplus (NYSE:ERF)
Historical Stock Chart
From Jul 2019 to Jul 2024
CALGARY, Feb. 25 /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. Readers are
also referred to "Information Regarding Reserves, Resources and
Operational Information", "Notice to U.S. Readers" and "Non-GAAP
Measures" at the end of this news release for information regarding the
presentation of the financial, reserves, contingent resources and
operational information in this news release. A full copy of our 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.
Effective January 1, 2011, Enerplus converted from an income trust
structure with the parent entity being Enerplus Resources Fund (the
"Fund") to a corporate structure with the parent entity being Enerplus
Corporation, as successor issuer to the Fund. As the Fund was the
public entity in existence at December 31, 2010, all financial
information as at and for the year ended December 31, 2010 is presented
with respect to the Fund and its outstanding trust units at that time.
CALGARY, Feb. 25 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF)
(NYSE: ERF) is pleased to announce operating, financial and reserve
results for 2010. Over the past two years, we have been transitioning
our asset base in order to create a portfolio that combines low
decline, cash generating properties together with earlier stage assets
that can provide future production and reserves growth. Throughout this
period, we have sold approximately $1.0 billion of non-core assets,
including the majority of our interests in the oil sands, and replaced
these properties with $1.3 billion of new assets that offer significant
near-term cash flow and organic growth potential. Along with changes to
our asset base, we have also added significantly to our internal
technical expertise in order to effectively manage our existing and
growing portfolios in both Canada and the U.S. These changes have been
essential in advancing our strategy to deliver both income and growth
to our investors and improve our focus, profitability and the overall
competitiveness of our business within the North American oil and gas
industry.
Our 2010 results clearly indicate progress on this strategy. Our
development capital spending program delivered our highest level of
reserve additions in our history. However, our shallow gas assets
continue to be faced with challenging economics due to declining
natural gas prices, reduced capital spending and reservoir
under-performance.
As a result of our activities, we believe Enerplus is now
well-positioned to deliver competitive returns to investors. We have
preserved our financial strength through our transition and expect to
utilize our balance sheet to increase our capital spending over the
next two years. We intend to continue to distribute a portion of the
cash flow generated from our operations to investors through a monthly
dividend and expect to complement this with annual growth in production
and reserves per share.
STRATEGIC EXECUTION
-- Enerplus acquired over $1 billion of prospective land in 2010
representing almost 300,000 net acres in key resource plays in
North America that offer superior economic returns. As a result
of these acquisitions, Enerplus now holds the following
significant land positions in key resource plays:
o Marcellus - ~130,000 net non-operated acres and ~70,000 net
operated acres in Pennsylvania, Maryland and West Virginia
o Bakken - ~75,000 net acres at Fort Berthold in North Dakota and
~155,000 net acres in southeast Saskatchewan
o Deep Basin - ~80,000 net acres in Alberta and British Columbia that
is prospective for the Montney and Mannville
-- Throughout 2010 we actively pursued a strategic portfolio
rationalization, selling approximately 10,400 BOE/day of
non-core conventional oil and gas production in order to
improve our operational focus and profitability. In addition,
we also sold our Kirby oil sands lease. Total proceeds from
these divestment activities amounted to $871.5 million.
-- Our acquisition activities were funded primarily through
disposition proceeds, thereby keeping our balance sheet strong
and providing us with the financial flexibility required to
support our capital spending plans over the next two years.
-- The "best estimate" of contingent resources associated with our
Marcellus interests increased 63% from 2.4 trillion cubic feet
to 3.9 trillion cubic feet of natural gas at December 31, 2010.
The increase in contingent resources is attributable to our
acquisition of additional operated interests in West Virginia
and Maryland (0.9 trillion cubic feet) and an improvement in
performance of wells drilled on our non-operated leases (0.6
trillion cubic feet).
-- The "best estimate" of contingent resources associated with our
North Dakota Bakken crude oil leases was 60 MMBOE at December
31, 2010, 17% higher than our previous estimate, with 90 future
drilling locations identified. This assessment reflects only
the Bakken resource at this time as we do not have enough wells
completed in the Three Forks zone to make an appropriate
estimate.
-- Enerplus now has over 700 million BOE of contingent resources
associated with our North Dakota and Marcellus properties which
provide us with significant growth potential in the coming
years.
-- Enerplus investors realized positive returns in 2010 with
Canadian investors realizing a 35.6% total return and U.S.
investors realizing a 43.4% total return. The return to our
U.S. investors also reflected the appreciation of the Canadian
dollar throughout the year.
OPERATIONS
-- Enerplus produced an average of 83,139 BOE/day in 2010, in line
with our guidance of 83,000 - 84,000 BOE/day. Daily production
volumes were 8,430 BOE/day lower than the average daily volumes
in 2009 due to reduced capital spending in 2009 and the sale of
10,400 BOE/day of non-core production in 2010.
-- Production volumes for the month of December were 77,200
BOE/day, approximately 4% lower than our guidance of 80,000 -
82,000 BOE/day. Exit volume shortfalls were primarily
associated with our Bakken production in North Dakota where
extreme weather conditions in December impacted our ability to
truck production to the sales terminals. Additionally, two long
lateral Bakken wells which were originally slated for
completion in early December were delayed. Both of these wells
are now on stream with initial production rates of 1,500
bbls/day per well.
-- Operating costs averaged $9.54/BOE during 2010, 6% better than
our guidance of $10.20/BOE primarily as a result of the sale of
high-cost non-core production and lower repairs, maintenance
and electricity costs.
-- In 2010, we invested $543 million through our capital program,
an increase of over 80% from our spending levels in 2009. This
was higher than our forecast capital spending of $515 million
due in part to an increase in drilling and completion costs
associated with our Marcellus program. Approximately $424
million was invested in drilling, completions and
recompletions, $85 million in facilities and maintenance, and
$34 million in seismic and lease rentals.
-- Almost 60% of our development spending related to oil projects
where we concentrated our efforts on our Bakken and waterflood
assets. Over half of our natural gas spending occurred in the
Marcellus where we were focused on delineation and lease
retention activities, and drilling in the more prolific
northeast area of Pennsylvania. Spending on our Canadian
natural gas assets declined throughout the year due to low
economic returns in this price environment. Because of long
lead times for well completion and tie-ins in the Bakken and
more particularly in the Marcellus, much of the capital
spending in 2010 will not generate production and cash flow
until 2011.
-- A total of 225.2 net wells were drilled in 2010. Excluding
103.7 net shallow gas wells, the majority of which were drilled
to take advantage of the Alberta Drilling Royalty Credit
program, Enerplus drilled 121.5 net wells, 77% of which were
crude oil wells. Over 80% of these wells were horizontal.
FINANCIAL
-- Cash flow from operations totaled $703.1 million, down 9% from
2009 due to lower production volumes.
-- We distributed $384.1 million to Unitholders through monthly
distributions in 2010, representing 55% of cash flow from
operating activities. When distributions and development
capital spending are combined, our adjusted payout ratio for
2010 was 132%.
-- We realized cash hedging gains of $49.7 million in 2010. Our
natural gas contracts generated gains of $67.3 million while
our crude oil contracts experienced losses of $17.6 million.
-- General and administrative costs were $2.60/BOE, slightly
higher than our guidance of $2.55/BOE and similar to 2009
levels.
-- Our trailing 12 month debt-to-cash flow ratio was 1.0x at
December 31, 2010.
RESERVES
-- Total proved plus probable ("P+P") company interest reserves at
December 31, 2010 were 306.2 MMBOE, down approximately 11% from
year-end 2009 approximately 60% of this decline attributable to
the sale of non-core properties net of acquisitions. Proved
reserves totaled 219.4 MMBOE, representing approximately 72% of
total proved plus probable reserves. 53% of P+P reserves are
weighted to crude oil and natural gas liquids. Our P+P reserve
life index was 10.7 years.
-- 34.0 MMBOE of P+P reserves were sold during 2010 of which 23.4
MMBOE were attributable to oil properties and 63.9 Bcfe were
related to natural gas properties.
-- 11.8 MMBOE of P+P reserves were acquired in 2010, primarily in
our Fort Berthold, North Dakota Bakken oil property. The
majority of our acquisitions in 2010 were of undeveloped land
with nominal proved or probable reserves.
-- Our development capital spending replaced 114% of 2010
production before revisions. 34.7 MMBOE of P+P reserves were
added from our delineation and development activities comprised
of 16.8 MMBOE from our oil properties and 107.3 Bcfe from our
natural gas properties.
-- The majority of the additions were attributable to our North
Dakota Bakken and Marcellus resource plays at 11.0 MMBOE and
87.6 Bcfe respectively. Our Finding & Development costs ("F&D")
were $10.74/BOE at Fort Berthold and $1.64/Mcfe in the
Marcellus. Booked drilling locations for these areas in our
reserve report represent less than one year's drilling activity
based upon current plans. We also added 5.7 MMBOE in Canada
across various oil properties, including our waterfloods, and
9.0 Bcfe from our deep tight gas plays.
-- A decrease in the outlook for natural gas prices and
underperformance in a few properties resulted in negative
revisions to our natural gas properties of 108.5 Bcfe of P+P
reserves and 2.6 MMBOE of P+P reserves associated with our oil
properties for a total of 20.7 MMBOE of P+P reserves. The
majority of the negative revisions were associated with our
shallow gas assets. Roughly 40% or 45 Bcfe of our natural gas
revisions related to the decline in natural gas price
forecasts, while 63.5 Bcfe related to performance mainly in our
Shackleton shallow gas property where well interference has
changed our view on long-term performance and economics. The
net present value of the performance revisions at Shackleton
discounted at 10% was approximately $100 million or 2% of our
2010 year-end proved plus probable reserve value discounted at
10%. Approximately 567 natural gas locations were removed from
our reserve report along with $95.6 million of associated
future development capital. Of the total 20.7 MMBOE in
revisions, 6.9 MMBOE or roughly one third were in the proved
category. After these revisions, approximately 150 shallow gas
drilling locations associated with our Shackleton property
remain in our reserve report.
-- The net present value of our P+P reserves (future prices
discounted at 10%) was approximately $4.8 billion at December
31, 2010, down from $5.6 billion at December 31, 2009 primarily
due to the sale of booked reserves and lower forecast natural
gas prices.
-- Our F&D cost per BOE of P+P reserves including future
development costs, before reserve revisions, was $17.46 with a
recycle ratio of 1.6x. This was primarily a result of the
reserve additions from our new growth properties in the Bakken
and the Marcellus.
-- After accounting for the negative revisions attributable
primarily to our shallow natural gas assets, our F&D cost was
$36.71/BOE with a recycle ratio of 0.75x.
-- As we acquired predominantly undeveloped land in early stage
growth properties in 2010 with significant potential but few
reserves, and sold non-core properties with proved plus
probable reserves, the calculation of our Finding, Development
& Acquisition costs resulted in a negative amount for the year.
SELECTED FINANCIAL AND OPERATING HIGHLIGHTS
SELECTED FINANCIAL Three months ended Twelve months ended
RESULTS December 31, December 31,
(in Canadian
dollars) 2010 2009 2010 2009
Financial (000's)
Cash Flow from
Operating
Activities $146,787 $188,579 $703,148 $775,786
Cash Distributions
to Unitholders(
(1)) 96,396 95,550 384,128 368,201
Excess of Cash
Flow Over Cash
Distributions 50,391 93,029 319,020 407,585
Net Income/(Loss) (995) 2,718 127,112 89,117
Debt Outstanding -
net of cash 724,031 485,349 724,031 485,349
Development
Capital Spending 229,029 118,889 542,679 299,111
Acquisitions 524,338 49,100 1,018,069 271,977
Divestments 537,935 102,070 871,458 104,325
Actual Cash
Distributions to
Unitholders per
Trust Unit $0.54 $0.54 $2.16 $2.23
Financial per
Weighted Average
Trust Unit((2))
Cash Flow from
Operating
Activities $0.82 $1.07 $3.96 $4.58
Cash Distributions
((1)) 0.54 0.54 2.16 2.17
Excess of Cash
Flow Over Cash
Distributions 0.28 0.53 1.80 2.41
Net Income (0.01) 0.02 0.72 0.53
Payout Ratio((3)) 66% 51% 55% 47%
Adjusted Payout
Ratio((3)) 223% 114% 132% 87%
Selected Financial
Results per BOE((4))
Oil & Gas Sales(
(5)) $ 42.49 $ 41.75 $ 42.85 $ 36.89
Royalties (6.21) (6.56) (7.37) (6.21)
Commodity
Derivative
Instruments 1.02 3.34 1.64 4.66
Operating Costs (8.29) (9.27) (9.61) (9.71)
General and
Administrative
Expenses (2.97) (3.30) (2.40) (2.44)
Interest, Foreign
Exchange and Other
Expenses (2.95) (0.72) (1.85) (0.34)
Taxes (0.40) 0.66 1.00 (0.01)
Asset Retirement
Obligations
Settled (0.96) (0.63) (0.57) (0.41)
Cash Flow from
Operating
Activities before
changes
in non-cash
working capital $ 21.73 $ 25.26 $ 23.69 $ 22.43
Weighted Average
Number of Trust
Units Outstanding(
(2)) 178,368 176,872 177,737 169,280
Debt to Trailing
12 Month Cash Flow
Ratio 1.0x 0.6x 1.0x 0.6x
SELECTED OPERATING Three months ended Twelve months ended
RESULTS December 31, December 31,
2010 2009 2010 2009
Average Daily
Production
Natural Gas
(Mcf/day) 274,314 305,691 288,692 326,570
Crude Oil
(bbls/day) 30,368 31,590 31,135 32,984
NGLs (bbls/day) 4,027 4,238 3,889 4,157
Total (BOE/day) 80,114 86,777 83,139 91,569
% Crude Oil &
Natural Gas
Liquids 43% 41% 42% 41%
Average Selling
Price ((5))
Natural Gas (per
Mcf) $ 3.63 $ 4.06 $ 4.05 $ 3.91
Crude Oil (per
bbl) 72.18 67.90 70.38 58.54
NGLs (per bbl) 53.66 56.96 51.41 41.54
US$/CDN$ exchange
rate 0.99 0.95 0.97 0.88
Net Wells drilled 40 156 225 313
((1) ) Calculated based on distributions paid or payable.
((2) ) Weighted average trust units outstanding for the period,
includes the equivalent exchangeable limited partnership units.
((3)) 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.
((4)) Non-cash amounts have been excluded.
((5) ) Net of oil and gas transportation costs, but before the effects
of commodity derivative instruments.
TRUST UNIT TRADING SUMMARY CDN* - ERF.un U.S.** - ERF
For the twelve months ended December
31, 2010 (CDN$) (US$)
High $31.85 $31.83
Low $18.22 $13.76
Close $30.67 $30.84
*TSX and other Canadian trading data
combined
** NYSE and other U.S. trading data
combined
2010 CASH DISTRIBUTIONS PER TRUST
UNIT CDN$ US$
First Quarter Total $0.54 $0.52
Second Quarter Total $0.54 $0.53
Third Quarter Total $0.54 $0.52
Fourth Quarter Total $0.54 $0.52
Total $2.16 $2.09
2010
PRODUCTION
AND CAPITAL
SPENDING
2010 2010 2010
Average Exit 2010 Capital Incremental
Daily Production Expenditures* Initial
Play Type Production (Dec. mth) ($ millions) Production**
Bakken/Tight
Oil
(BOE/day) 11,305 13,300 $172 11,445
Crude Oil
Waterflood
(BOE/day) 14,688 13,790 127 2,087
Conventional
Oil
(bbls/day) 8,535 5,969 22 865
Total Crude
Oil
(BOE/day) 34,528 33,060 $321 14,397
Marcellus
Shale Gas
(Mcfe/day) 9,338 17,662 $123 22,140
Shallow Gas
(Mcfe/day) 117,598 103,921 26 62,046
Tight Gas
(Mcfe/day) 85,084 86,661 65 21,258
Conventional
Gas
(Mcfe/day) 79,649 56,579 8 32,964
Total Gas
(Mcfe/day) 291,669 264,823 $222 138,408
Company
Total
(BOE/day) 83,139 77,197 $543 18,242
*Net of $18.3 million in Alberta Drilling Royalty Credits
**Based upon first full calendar month of sales
2010 NET DRILLING ACTIVITY*
Wells
Pending Dry &
Horizontal Vertical Total Completion/ Wells Abandoned
Play Type Wells Wells Wells Tie-in** On-stream Wells
Bakken/Tight
Oil 28.5 0.9 29.4 5.5 23.8 -
Crude Oil
Waterfloods 38.9 8.4 47.3 16.5 30.1 0.6
Conventional
Oil 16.6 0.0 16.6 4.7 11.9 -
Total Oil 83.9 9.3 93.2 26.8 65.8 0.6
Marcellus
Shale Gas 12.2 1.5 13.6 10.2 3.1 0.3
Shallow Gas - 103.7 103.7 63.4 40.4 -
Tight Gas 4.2 2.1 6.3 5.1 1.2 -
Conventional
Gas 1.7 6.6 8.3 3.1 5.3 -
Total Gas 18.1 113.9 132.0 81.8 49.9 0.3
Company
Total 102.0 123.2 225.2 108.5 115.7 0.9
*Totals may not add due to rounding
**Pending potential completion/tie-in or abandonment and on-stream wells
measured as at December 31, 2010
KEY RESOURCE PLAY ACTIVITY
Bakken/Tight Oil
Our Bakken/Tight Oil resource play grew significantly in 2010 through
the acquisition of undeveloped acreage in North Dakota and
Saskatchewan. Through a series of acquisitions, we now hold over
230,000 net acres of undeveloped land that is prospective for the
Bakken and the Three Forks in certain areas. Total production from this
resource play grew by 12% year-over-year with the increase in
production coming primarily from our drilling activity in North Dakota.
In total, over 12.1 MMBOE of reserves were added through our
development activities, with another 11.3 MMBOE added through
acquisitions. We also added 60.0 MMBOE of "best estimate" contingent
resource at Fort Berthold attributable to the Bakken only which
represents approximately 90 future drilling locations. We believe this
provides us with significant future growth potential in the coming
years.
In 2010, the majority of our drilling activity occurred in our U.S.
Bakken assets where we drilled 6.4 net horizontal wells at Sleeping
Giant and another 14.8 net horizontal wells at Fort Berthold. Our
drilling results to date in the Fort Berthold area have generally
exceeded our expectations and are the basis for our increase in capital
spending planned in 2011. We also drilled a number of wells in
Saskatchewan targeting the Bakken on both our operated leases and
through our non-operated working interest at Taylorton. The drilling
results on our operated leases have been disappointing. While we've
discovered oil in this area, the limited quantity does not meet current
economic thresholds. We are continuing to evaluate seismic data from
the area to assess the potential of the Bakken and other zones.
We expect to spend approximately $300 million, almost half of our 2011
capital budget, on our Bakken oil properties. Based upon the success of
our drilling activities in Fort Berthold, $230 million has been
targeted for this area as we move into the development phase. We plan
to drill 32 net operated wells at Fort Berthold with at least 75% of
these wells planned as long lateral horizontal wells. Our primary
target will be the Bakken formation however we also plan to test the
Three Forks formation underlying the Bakken to evaluate the potential
and future prospectivity of this zone. We have secured service
agreements for frac crews, proppant and a drilling rig to support the
successful execution of our program. We're also working to have
mid-stream agreements in place by mid-year that will allow us to tie in
our production and capture the associated natural gas. The remaining
$70 million will be invested at Sleeping Giant in Montana and in our
Canadian tight oil properties.
We expect production at Fort Berthold will more than double as we exit
2011 with total production from our Bakken/Tight Oil resource play
growing by 50% throughout 2011, exiting in the range of 18,000 - 21,000
BOE/day. Given the high initial productivity of these wells and the
competition for services in this region, exit production volumes and
capital spending could vary from guidance depending upon when new wells
are drilled, completed and tied in.
Waterfloods
Our crude oil waterflood assets are a core part of our business
contributing low decline, stable production and free cash flow to
support investment in our new growth plays. This portfolio includes a
variety of properties producing from formations such as the Cardium,
Viking, Ratcliffe, Lloydminster and Glauconitic that offer new drilling
opportunities, optimization and enhanced oil recovery potential.
Through horizontal drilling technology and reservoir depletion
analysis, we have identified new opportunities in a number of these
mature fields that we believe will help offset declines and, in some
areas, provide a modest level of growth. Our activities in 2010 were
focused on drilling and recompletion activities and facility upgrades.
As a result of our land acquisitions in Saskatchewan, we expanded the
potential at Freda Ratcliffe. We've drilled nine horizontal wells into
the existing unit and expect that we have an additional 16 locations.
We are also turning our attention to other lands on the Ratcliffe trend
and believe that they provide significant additional opportunities. We
also started work on our first polymer pilot at Giltedge which will
continue through 2011. Approximately 53% of our waterflood capital
spending was directed toward drilling both producing and injector wells
including completion activities.
We expect to spend approximately $110 million on our waterflood assets
in 2011 maintaining production volumes throughout the year at
approximately 14,000 BOE/day. We will also continue to advance the work
on our enhanced oil recovery pilot projects. A significant portion of
this capital is being directed to activities that we believe will
position us for future production and reserve growth.
Marcellus Shale Gas
We continued to add to our Marcellus interests in 2010 through the
acquisition of operated interests in Pennsylvania, West Virginia and
Maryland. Through three transactions, we acquired 70,000 net acres of
land, taking our total interests in the Marcellus to approximately
200,000 net acres. As a result of our acquisition activities as well as
improved well performance, the contingent resource estimate associated
with our Marcellus leases increased by 63% to 3.9 Tcfe of natural gas,
more than 4.5 times our total corporate natural gas proved plus
probable reserves. We also booked approximately 96 Bcfe of proved plus
probable reserves at year end. Our finding and development costs for
the Marcellus were $1.64/Mcfe.
A majority of the activity in 2010 was with our operating partner, Chief
Oil & Gas, where we participated in the drilling of 60 gross wells
(11.7 net wells) during the year. We also participated in another 62
gross wells (1.9 net wells) during 2010 with other operators. We
planned to have 67 gross wells tied-in during 2010, however, due to the
timing of pipeline infrastructure and the availability of frac crews,
only 38 gross wells were tied in. Despite these delays, we exited 2010
on track with production of approximately 91 MMcf/day gross of natural
gas (18 MMcf/day net to Enerplus) as actual well results are exceeding
our original expectations. We estimate there is currently 120 - 140
MMcf/day of natural gas waiting on completion or tie-in, in which we
have a 20% working interest. We also began drilling our first operated
well in Centre County in 2010. The well was completed in January of
this year but we do not expect tie-in until late 2011 due to current
infrastructure and gathering limitations.
Approximately $160 million of capital expenditures are planned for the
Marcellus in 2011, with the majority being spent on our non-operated
interests. With our joint venture partners, 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 plan to have 94 new wells on stream by the end of the
year. We also plan to drill five gross operated delineation wells (4
net) on our new Marcellus leases. Due to the timing of infrastructure,
access to 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. As well, with
the high activity levels in this region, well costs could come under
pressure throughout the year. Despite these delays, production in 2011
is expected to grow by 150% to approximately 45 MMcf/day by year-end.
RESERVES
All reserves are presented on a "company interest" basis. See
"Information Regarding Reserves, Resources and Operational Information"
at the end of this news release for information regarding the
presentation of company interest reserves.
All of our reserves, including our U.S. reserves, were evaluated using
Canadian National Instrument 51-101 ("NI 51-101") standards. McDaniel &
Associates Consultants Ltd. ("McDaniel") evaluated or reviewed all of
our Canadian assets, and in August 2010, Enerplus contracted McDaniel
to replace Netherland, Sewell & Associates, Inc. as our independent
reserve evaluator for our western United States assets. Haas Petroleum
Engineering Services Inc. ("Haas") has evaluated our Marcellus shale
gas assets again this year.
McDaniel has evaluated 86% of the total proved plus probable value
(discounted at 10%) of our Canadian conventional year-end reserves and
reviewed the internal evaluation completed by Enerplus on the remaining
14% of reserves. McDaniel also evaluated substantially all of the
reserves associated with our western U.S. assets with the exception of
some minor royalty interest properties which were evaluated internally
and reviewed by McDaniel. The evaluation of contingent resources
associated with our Bakken leases at Fort Berthold was conducted by
Enerplus and reviewed by McDaniel. Haas evaluated 100% of our Marcellus
shale gas assets in the U.S. and provided both the reserve and
contingent resource estimates.
Reserves & Contingent Resources by Resource Play
Incremental
Future
Contingent
Proved Proved plus "Best Resource
plus Probable Booked Estimate" Net
Probable Net Drilling Contingent Drilling
Play Types Proved Reserves Locations Resources* Locations
Bakken/Tight
Oil (MMBOE) 38.0 57.5 39 60 90
Crude Oil
Waterfloods
(MMBOE) 65.2 83.7 45 - -
Other
Conventional
Oil (MMBOE) 20.8 27.7 23 - -
Total Oil
(MMBOE) 124.0 168.9 107 60 90
Marcellus
Shale Gas
(Bcfe) 52.4 117.2 13 3,904 926
Tight Gas
(Bcfe) 228.7 320.8 40 - -
Shallow Gas
(Bcfe) 164.8 220.5 152 - -
Other
Conventional
Gas (Bcfe) 126.3 165.0 1 - -
Total Gas
(Bcfe) 572.2 823.5 206 3,904 926
Total
Company
(MMBOE) 219.4 306.2 313 710.7 1,016
*Contingent resources net to Enerplus. No contingent resource assessment
has been conducted on our waterflood, tight gas, shallow gas or other
conventional oil and gas assets at this time.
Reserves Summary
The following table sets out our company interest volumes at December
31, 2010 by production type and reserve category under McDaniel's
forecast price scenario set forth below in this news release. Under
different price scenarios, these reserves could vary as a change in
price can affect the economic limit and reserves associated with a
property.
2010 Reserves Summary - Company Interest Volumes (Forecast Prices)
Light & Natural
Medium Heavy Total Gas Natural Shale
Reserves Oil Oil Oil Liquids Gas Gas Total
Category (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
Proved
Developed
Producing
Canada 46,028 25,955 71,983 7,627 456,777 - 155,739
United
States 21,880 - 21,880 67 34,566 32,014 33,044
Total Proved
Developed
Producing 67,908 25,955 93,863 7,694 491,343 32,014 188,783
Proved
Developed
Non-Producing
Canada 347 687 1,034 175 12,883 - 3,357
United
States 1,193 - 1,193 1 1,115 2,508 1,798
Total Proved
Developed
Non-Producing 1,540 687 2,227 176 13,998 2,508 5,155
Proved
Undeveloped -
Canada 3,233 2,535 5,768 713 40,389 - 13,212
United
States 7,848 - 7,848 27 8,360 17,703 12,219
Total Proved
Undeveloped 11,081 2,535 13,616 740 48,749 17,703 25,431
Proved -
Canada 49,608 29,177 78,785 8,515 510,049 - 172,308
United
States 30,921 - 30,921 95 44,041 52,225 47,061
Total Proved 80,529 29,177 109,706 8,610 554,090 52,225 219,369
Probable
Canada 14,098 9,783 23,881 2,825 173,983 - 55,703
United
States 16,266 - 16,266 141 24,114 64,437 31,165
Total
Probable 30,364 9,783 40,147 2,966 198,097 64,437 86,868
Proved Plus
Probable -
Canada 63,706 38,960 102,666 11,340 684,032 - 228,011
United
States 47,187 - 47,187 236 68,155 116,662 78,226
Total Proved
Plus Probable 110,893 38,960 149,853 11,576 752,187 116,662 306,237
Reserve Reconciliation
The following tables outline the changes in Enerplus' proved, probable
and proved plus probable reserves, on a company interest basis, from
December 31, 2009 to December 31, 2010.
Proved Reserves - Company Interest Volumes (Forecast Prices)
Light & Natural
Medium Heavy Total Gas Natural Shale
Oil Oil Oil Liquids Gas Gas Total
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
Proved
Reserves at
Dec. 31,
2009 61,053 34,431 95,484 10,633 696,585 - 222,214
Acquisitions 249 - 249 30 2,235 - 652
Dispositions (11,001) (4,207) (15,208) (1,346) (50,085) - (24,902)
Discoveries - - - - - - -
Extensions
& Improved
Recovery 3,505 15 3,520 138 12,431 - 5,730
Economic
Factors (86) (17) (103) (230) (33,414) - (5,902)
Technical
Revisions 866 1,902 2,768 709 (20,366) - 83
Production (4,978) (2,947) (7,925) (1,419) (97,337) - (25,567)
Proved
Reserves at
Dec. 31,
2010 49,608 29,177 78,785 8,515 510,049 - 172,308
Light & Natural
Medium Heavy Total Gas Natural Shale
UNITED Oil Oil Oil Liquids Gas Gas Total
STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
Proved
Reserves at
Dec. 31,
2009 25,452 - 25,452 120 49,449 8,127 35,168
Acquisitions 4,799 - 4,799 - 1,191 - 4,998
Dispositions - - - - - - -
Discoveries - - - - - - -
Extensions &
Improved
Recovery 6,379 - 6,379 27 2,096 35,767 12,717
Economic
Factors 40 - 40 - 12 - 42
Technical
Revisions (2,329) - (2,329) (33) (4,035) 11,696 (1,085)
Production (3,420) - (3,420) (19) (4,672) (3,365) (4,779)
Proved
Reserves at
Dec. 31,
2010 30,921 - 30,921 95 44,041 52,225 47,061
Light & Natural
Medium Heavy Total Gas Natural Shale
TOTAL Oil Oil Oil Liquids Gas Gas Total
ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
Proved
Reserves at
Dec. 31,
2009 86,505 34,431 120,936 10,753 746,034 8,127 257,382
Acquisitions 5,048 - 5,048 30 3,426 - 5,650
Dispositions (11,001) (4,207) (15,208) (1,346) (50,085) - (24,902)
Discoveries - - - - - - -
Extensions &
Improved
Recovery 9,884 15 9,899 165 14,527 35,767 18,447
Economic
Factors (46) (17) (63) (230) (33,402) - (5,860)
Technical
Revisions (1,463) 1,902 439 676 (24,401) 11,696 (1,002)
Production (8,398) (2,947) (11,345) (1,438) (102,009) (3,365) (30,346)
Proved
Reserves at
Dec. 31,
2010 80,529 29,177 109,706 8,610 554,090 52,225 219,369
Probable Reserves - Company Interest Volumes (Forecast Prices)
Light & Natural
Medium Heavy Total Gas Natural Shale
Oil Oil Oil Liquids Gas Gas Total
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
Probable
Reserves at
Dec. 31,
2009 16,776 12,347 29,123 3,718 250,061 - 74,518
Acquisitions 56 - 56 17 (1,004) - (95)
Dispositions (4,060) (1,650) (5,710) (447) (17,930) - (9,145)
Discoveries - - - - - - -
Extensions
& Improved
Recovery 1,699 10 1,709 84 6,991 - 2,958
Economic
Factors (34) (16) (50) (21) (15,150) - (2,596)
Technical
Revisions (339) (908) (1,247) (526) (48,985) - (9,937)
Production - - - - - - -
Probable
Reserves at
Dec. 31,
2010 14,098 9,783 23,881 2,825 173,983 - 55,703
Light & Natural
Medium Heavy Total Gas Natural Shale
UNITED Oil Oil Oil Liquids Gas Gas Total
STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
Probable
Reserves at
Dec. 31,
2009 7,287 - 7,287 36 17,085 16,763 12,964
Acquisitions 5,890 - 5,890 - 2,359 - 6,283
Dispositions - - - - - - -
Discoveries - - - - - - -
Extensions &
Improved
Recovery 4,129 - 4,129 70 3,016 51,325 13,255
Economic
Factors 38 - 38 - 33 - 44
Technical
Revisions (1,078) - (1,078) 35 1,621 (3,651) (1,381)
Production - - - - - - -
Probable
Reserves at
Dec. 31,
2010 16,266 - 16,266 141 24,114 64,437 31,165
Light & Natural
Medium Heavy Total Gas Natural Shale
TOTAL Oil Oil Oil Liquids Gas Gas Total
ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
Probable
Reserves at
Dec. 31,
2009 24,063 12,347 36,410 3,754 267,146 16,763 87,482
Acquisitions 5,946 - 5,946 17 1,355 - 6,188
Dispositions (4,060) (1,650) (5,710) (447) (17,930) - (9,145)
Discoveries - - - - - - -
Extensions &
Improved
Recovery 5,828 10 5,838 154 10,007 51,325 16,213
Economic
Factors 4 (16) (12) (21) (15,117) - (2,552)
Technical
Revisions (1,417) (908) (2,325) (491) (47,364) (3,651) (11,318)
Production - - - - - - -
Probable
Reserves at
Dec. 31,
2010 30,364 9,783 40,147 2,966 198,097 64,437 86,868
Proved Plus Probable Reserves - Company Interest Volumes (Forecast
Prices)
Light & Natural
Medium Heavy Total Gas Natural Shale
Oil Oil Oil Liquids Gas Gas Total
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
Proved Plus
Probable
Reserves at
Dec. 31,
2009 77,829 46,778 124,607 14,351 946,646 - 296,732
Acquisitions 305 - 305 47 1,231 - 557
Dispositions (15,061) (5,857) (20,918) (1,793) (68,015) - (34,047)
Discoveries - - - - - - -
Extensions
& Improved
Recovery 5,204 25 5,229 222 19,422 - 8,688
Economic
Factors (120) (33) (153) (251) (48,564) - (8,498)
Technical
Revisions 527 994 1,521 183 (69,351) - (9,854)
Production (4,978) (2,947) (7,925) (1,419) (97,337) - (25,567)
Proved Plus
Probable
Reserves at
Dec. 31,
2010 63,706 38,960 102,666 11,340 684,032 - 228,011
Light & Natural
Medium Heavy Total Gas Natural Shale
UNITED Oil Oil Oil Liquids Gas Gas Total
STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
Proved Plus
Probable
Reserves at
Dec. 31,
2009 32,739 - 32,739 156 66,534 24,890 48,132
Acquisitions 10,689 - 10,689 - 3,550 - 11,281
Dispositions - - - - - - -
Discoveries - - - - - - -
Extensions &
Improved
Recovery 10,508 - 10,508 97 5,112 87,092 25,972
Economic
Factors 78 - 78 - 45 - 86
Technical
Revisions (3,407) - (3,407) 2 (2,414) 8,045 (2,466)
Production (3,420) - (3,420) (19) (4,672) (3,365) (4,779)
Proved Plus
Probable
Reserves at
Dec. 31,
2010 47,187 - 47,187 236 68,155 116,662 78,226
Light & Natural
Medium Heavy Total Gas Natural Shale
TOTAL Oil Oil Oil Liquids Gas Gas Total
ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
Proved Plus
Probable
Reserves at
Dec. 31,
2009 110,568 46,778 157,346 14,507 1,013,180 24,890 344,864
Acquisitions 10,994 - 10,994 47 4,781 - 11,838
Dispositions (15,061) (5,857) (20,918) (1,793) (68,015) - (34,047)
Discoveries - - - - - - -
Extensions &
Improved
Recovery 15,712 25 15,737 319 24,534 87,092 34,660
Economic
Factors (42) (33) (75) (251) (48,519) - (8,412)
Technical
Revisions (2,880) 994 (1,886) 185 (71,765) 8,045 (12,320)
Production (8,398) (2,947) (11,345) (1,438) (102,009) (3,365) (30,346)
Proved Plus
Probable
Reserves at
Dec. 31,
2010 110,893 38,960 149,853 11,576 752,187 116,662 306,237
NET PRESENT VALUE OF FUTURE PRODUCTION REVENUE
The estimated reserve volumes and net present values of all future net
revenues at December 31, 2010 were based upon forecast crude oil and
natural gas pricing assumptions prepared by McDaniel as of December 31,
2010. These prices were applied to the reserves evaluated by McDaniel
and Haas, along with those evaluated internally by Enerplus and audited
by McDaniel. The base reference prices and exchange rates used by
McDaniel are detailed below:
McDaniel January 2011 Forecast Price Assumptions
Natural
Light Hardisty Gas
WTI Crude Heavy 30 day
Crude Oil((1)) Oil Henry Hub spot Exchange
Oil Edmonton 12º API Gas Price @ AECO Rate
US$/bbl CDN$/bbl CDN$/bbl US$/MMBtu CDN$/MMBtu US$/CDN$
2011 85.00 84.20 66.70 4.55 4.25 0.975
2012 87.70 88.40 68.70 5.30 4.90 0.975
2013 90.50 91.80 68.60 5.75 5.40 0.975
2014 93.40 94.80 70.80 6.30 5.90 0.975
2015 96.30 97.70 73.00 6.80 6.35 0.975
Thereafter ** ** ** ** ** 0.975
((1)) Edmonton Light Sweet 40 degree API, 0.3% sulphur content crude
** Escalation varies after 2015
The following table provides an estimate of the net present value of
Enerplus' future production revenue after deduction of royalties,
estimated future capital and operating expenditures, and before income
taxes. It should not be assumed that the present value of estimated
future cash flows shown below is representative of the fair market
value of the reserves.
Net Present Value of Future Production Revenue - Forecast Prices and
Costs (Before Tax)
Reserves at December 31, 2010, 0% 5% 10% 15%
($ millions, discounted at)
Proved developed producing 6,370 4,230 3,222 2,635
Proved developed non-producing 158 116 90 74
Proved undeveloped 754 456 297 200
Total Proved 7,282 4,802 3,609 2,909
Probable 3,940 1,931 1,181 816
Total Proved Plus Probable 11,222 6,733 4,790 3,725
Reserves
NET ASSET VALUE
Enerplus' estimated net asset value is the estimated net present value
of all future net revenue from our reserves, before taxes, as estimated
by our independent reserve engineers (McDaniel and Haas) at year-end.
This calculation can vary significantly depending on the oil and
natural gas price assumptions used by the independent reserve
engineers.
In addition, this calculation ignores "going concern" value and assumes
only the reserves identified in the reserve reports with no further
acquisitions or incremental development, including development of
contingent resources. At December 31, 2010, the estimate of contingent
resources contained within our leases was in excess of 700 million BOE,
more than 2.3 times our proved plus probable reserves. As we execute
our capital programs, we expect to convert contingent resources to
reserves and significantly increase the value of these assets.
The land values described in the Net Asset Value table below do not
necessarily reflect the full value of the contingent resources
associated with these lands.
Net Asset Value (Forecast Prices and Costs at December
31, 2010)
($ millions
except
trust unit
amounts,
discounted
at) 0% 5% 10% 15%
Total net
present
value of
proved plus
probable
reserves
(before
tax) $11,222 $6,733 $4,790 $3,725
Undeveloped
acreage
(2010 Year
End)((1))
Canada
(770,000
Acres) 266 266 266 266
U.S. West
(127,446
Acres) 387 387 387 387
U.S.
Marcellus
Shale
(196,589
Acres) 565 565 565 565
Asset
retirement
obligations
((2)) (238) (129) (29) (10)
Long-term
debt (net
of cash)( ) (724) (724) (724) (724)
Net working
capital
excluding
deferred
financial
assets and
credits and
future
income
taxes (207) (207) (207) (207)
Marcellus
carry
commitment (146) (146) (146) (146)
Other
equity
investments
((3)) 155 155 155 155
Net Asset
Value of
Assets $11,280 $6,900 $5,057 $4,011
Net Asset
Value per
Trust Unit(
(4) ) $63.14 $38.62 $28.31 $22.45
((1) ) Acreage acquired in 2009 and 2010 valued at acquisition
cost. Acreage acquired prior to 2009 valued at $100/acre.
((2)) Asset retirement obligations ("ARO") do not equal the amount
on the balance sheet ($208.7 million) as the balance sheet
amount uses a 6.4% discount rate and a portion of the ARO
costs are already reflected in the present value of reserves
computed by the independent engineers.
((3) ) Other equity investment value based on cost, except value of
Laricina equity valued based on last offering price of
$30/share.
((4)) Based on 178,648,000 Trust Units and equivalent Exchangeable
Partnership Units outstanding as at December 31, 2010.
2011 OUTLOOK
2011 capital spending is anticipated to increase by 20% 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. Approximately $420 million is planned for our
oil projects with our Bakken portfolio attracting $300 million. With
the current natural gas price outlook we plan to limit our spending on
our natural gas assets in 2011 spending approximately $230 million,
$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 approximately 80,000 net acres of
land. We plan to drill up to four delineation wells targeting the
Mannville in the South Ansell area where other producers have had
recent success. Our shallow gas activities will consist only of
recompletions at Shackleton targeting the multi-zone potential of the
area. 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. We also expect a similar level and allocation
of spending in 2012.
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 spent in
2012. We plan to spend approximately $450 million on development
drilling, recompletions and facilities, $140 million on delineation
activities, $30 million on seismic and $30 million on maintenance
activities. 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. Shallow gas
and other conventional oil and gas production are expected to decline
throughout the year due to reduced capital. 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
approximately 20% over the next two years and crude oil and natural gas
liquids are expected to represent just under 50% of total volumes by
the end of 2012.
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 and may 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 $116 million on our capital carry commitment
associated with the Marcellus in 2011.
We expect our debt-to-cash flow ratio to increase to approximately 2.0
times in 2012 based upon the current forward commodity markets.
Key 2011 Capital Spending Plans & Estimated Production
# 2011E
Resource Capital of net Exit Exit to Exit
Play ($MM) wells Production Variance
Bakken/Tight
Oil 18,000 -
(BOE/day) 300 48 21,000 35-55%
Waterfloods 13,500 -
(BOE/day) 110 26 15,000 0-10%
Marcellus
Shale Gas 7,000 -
(Mcfe/day) 160 27 8,000 140-170%
Resource
Play Total 38,500 -
(BOE/day) $570 101 44,000 30-45%
Total 80,000 -
(BOE/day) $650 113 84,000 5-10%
SUMMARY
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 cash generating assets combined with a strong balance
sheet that will help support our growth and income strategy.
Gordon J. Kerr
President & Chief Executive Officer
Enerplus Corporation
INFORMATION REGARDING RESERVES, RESOURCES AND OPERATIONAL INFORMATION
Currency
All amounts in this news release are stated in Canadian dollars unless
otherwise specified.
Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent
This news release also contains references to "BOE" (barrels of oil
equivalent), "Mcfe" (thousand cubic feet of gas equivalent), "Bcfe"
(billion cubic feet of gas equivalent) and "Tcfe" (trillion cubic feet of gas equivalent). Enerplus has adopted the standard of six thousand
cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting
natural gas to BOEs, and one barrel of oil to six thousand cubic feet
of gas (1 bbl: 6 Mcf) when converting oil to Mcfes, Bcfes and
Tcfes. BOEs, Mcfes, Bcfes and Tcfes may be misleading, particularly if
used in isolation. The foregoing conversion ratios are based on an
energy equivalency conversion method primarily applicable at the burner
tip and do not represent a value equivalency at the wellhead. "MBOE"
and "MMBOE" mean "thousand barrels of oil equivalent" and "million
barrels of oil equivalent", respectively.
Presentation of Production and Reserves Information
In accordance with Canadian practice, production volumes and revenues
are reported on a "Company interest" basis, before deduction of Crown
and other royalties, plus Enerplus' royalty interest. 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"), being Enerplus' working interest before deduction of any royalties,
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, 2010, which will include complete disclosure of our oil
and gas reserves and other oil and gas information in accordance with
NI 51-101, will be contained within our Annual Information Form for the
year ended December 31, 2010 ("our AIF") which will be available in mid-March 2011 on our website at www.enerplus.com and on our SEDAR profile at www.sedar.com. Additionally, the Annual Information Form will form part of our Form
40-F that will be filed with the U.S. Securities and Exchange
Commission and will 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.
Contingent Resource Estimates
This news release contains estimates of "contingent resources".
"Contingent resources" are not, and should not be confused with, oil
and gas reserves. "Contingent resources" are defined in the Canadian
Oil and Gas Evaluation Handbook (the "COGE Handbook") as "those quantities of petroleum estimated, as of a given date, to
be potentially recoverable from known accumulations using established
technology or technology under development, but which are not currently
considered to be commercially recoverable due to one or more
contingencies. Contingencies may include factors such as economic,
legal, environmental, political and regulatory matters or a lack of
markets. It is also appropriate to classify as "contingent resources"
the estimated discovered recoverable quantities associated with a
project in the early evaluation stage." There is no certainty that we
will produce any portion of the volumes currently classified as
"contingent resources". The "contingent resource" estimates contained
herein are presented as the "best estimate" of the quantity that will
actually be recovered, effective as of December 31, 2010. A "best
estimate" of contingent resources means that it is equally likely that
the actual remaining quantities recovered will be greater or less than
the best estimate, and if probabilistic methods are used, there should
be at least a 50% probability that the quantities actually recovered
will equal or exceed the best estimate.
For information regarding the primary contingencies which currently prevent the
classification of our disclosed "contingent resources" associated with
our Marcellus shale gas assets as reserves and the positive and
negative factors relevant to the "contingent resource" estimate, see
our Annual Information Form for the year ended December 31, 2009 (and
corresponding Form 40-F) dated March 12, 2010, a copy of which is
available on our SEDAR profile at www.sedar.com and a copy of the Form 40-F which is available on our EDGAR profile at www.sec.gov. With respect to the "contingent resource" estimate for our North Dakota
Bakken properties, the primary contingencies which currently prevent
the classification of our disclosed "contingent resources" associated
with the properties as "reserves" consist of additional delineation drilling to establish economic productivity in
the development areas and limitations to development based on adverse topography or other
surface restrictions. Significant positive factors related to the
estimate include: continued advancement of drilling and completion
technology and early performance of producing wells that are above
forecast. A significant negative factor related to the estimate is the
limited performance history in the immediate area of the "contingent
resource". There are a number of inherent risks and contingencies
associated with the development of our interests in these properties
including commodity price fluctuations, project costs, our ability to
make the necessary capital expenditures to develop the properties,
reliance on our industry partners in project development, acquisitions,
funding and provisions of services and those other risks and
contingencies described above, and that apply generally to oil and gas
operations as described above, and under "Risk Factors" in our Annual
Information Form referred to above.
F&D Costs and Recycle Ratio
F&D costs presented in this news release are calculated (i) in the case
of F&D costs for proved reserves, by dividing the sum of exploration
and development costs incurred in the year plus the change in estimated
future development costs in the year, by the additions to proved
reserves in the year, and (ii) in the case of F&D costs for proved plus
probable reserves, by dividing the sum of exploration and development
costs incurred in the year plus the change in estimated future
development costs in the year, by the additions to proved plus probable
reserves in the year. The aggregate of the exploration and development
costs incurred in the most recent financial year and the change during
that year in estimated future development costs generally will not
reflect total finding and development costs related to its reserves
additions for that year.
Recycle ratio is calculated by dividing operating netback per BOE
(calculated by subtracting our royalties, state severance taxes and
operating and gathering costs from its revenues) by the F&D cost per
BOE.
See "Non-GAAP Measures" below.
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 construed
as reserves. For a description of the definition of, and the risks and
uncertainties surrounding the disclosure of, contingent resources, see
"Information Regarding Reserves, Resources and Operational Information"
above.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking information and
statements ("forward-looking information") 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", "budget", "strategy" and similar expressions are
intended to identify forward-looking information. In particular, but
without limiting the foregoing, this news release contains
forward-looking information pertaining to the following: Enerplus'
strategy to deliver both income and growth to investors and Enerplus'
related asset portfolio; future returns to shareholders from both
dividends and from growth in per share production and reserves; future
capital and development expenditures and the allocation thereof among
our resource plays and assets; future development and drilling
locations and plans; the performance of and future results from
Enerplus' assets and operations, including anticipated production
levels and decline rates; future growth prospects, acquisitions and
dispositions; the volumes and estimated value of Enerplus' oil and gas
reserves and contingent resource volumes and future commodity price and
foreign exchange rate assumptions related thereto; the life of
Enerplus' reserves; the volume and product mix of Enerplus' oil and gas
production; securing necessary infrastructure and third party services;
the amount of future asset retirement obligations; future cash flows
and debt-to-cash flow levels; potential asset sales; returns on
Enerplus' capital program; Enerplus' tax position; and future costs,
expenses and royalty rates.
The forward-looking information contained in this news release reflect
several material factors and expectations and assumptions of Enerplus
including, without limitation: that Enerplus will conduct its
operations and achieve results of operations as anticipated; that
Enerplus' development plans will achieve the expected results; the
general continuance of current or, where applicable, assumed industry
conditions; the continuation of assumed tax, royalty and regulatory
regimes; the accuracy of the estimates of Enerplus' reserve and
resource volumes; commodity price and cost assumptions; the continued
availability of adequate debt and/or equity financing and cash flow to
fund Enerplus' capital and operating requirements as needed; and the
extent of its liabilities. Enerplus believes the material factors,
expectations and assumptions reflected in the forward-looking
information are reasonable but no assurance can be given that these
factors, expectations and assumptions will prove to be correct.
The forward-looking information included in this news release is not a
guarantee of future performance and should not be unduly relied upon.
Such information and involves 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
including, without limitation: changes in commodity prices; changes in
the demand for or supply of Enerplus' products; unanticipated operating
results, results from development plans or production declines; changes
in tax or environmental laws, royalty rates or other regulatory
matters; changes in development plans by Enerplus or by third party
operators of Enerplus' properties, increased debt levels or debt
service requirements; inaccurate estimation of Enerplus' oil and gas
reserve and resource volumes; limited, unfavourable or a lack of access
to capital markets; increased costs; a lack of adequate insurance
coverage; the impact of competitors; reliance on industry partners; and
certain other risks detailed from time to time in Enerplus' public
disclosure documents (including, without limitation, those risks
identified in Enerplus' Annual Information Form and Form 40-F described
above).
The forward-looking information contained in this news release speak
only as of the date of this news release, and none of Enerplus 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
In this news release, we use the terms "payout ratio" and "adjusted
payout ratio" to analyze operating performance, leverage and liquidity,
and the terms "recycle ratio" and "F&D costs" as measures of operating
performance. We calculate "payout ratio" by dividing cash distributions to
unitholders by cash flow from operating activities, both of which are
measures prescribed by Canadian generally accepted accounting
principles ("GAAP") and which appear on our consolidated statements of cash
flow. "Adjusted payout ratio" is calculated as cash distributions to
unitholders plus development capital and office expenditures, divided
by cash flow from operating activities. "Recycle ratio" is calculated
by dividing operating netback per BOE (calculated by subtracting
Enerplus' royalties, state severance taxes and operating and gathering
costs from its revenues) by the F&D cost per BOE. We also use the term
"netback", which 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.
Enerplus believes that, in addition to net earnings and other measures
prescribed by GAAP, the terms "payout ratio", "adjusted payout ratio",
"recycle ratio", "F&D costs" and "netback" are useful supplemental
measures as they provide an indication of the results generated by
Enerplus' principal business activities. However, these measures are
not measures recognized by GAAP and do not have a standardized meaning
prescribed by GAAP. Therefore, these measures, as defined by Enerplus,
may not be comparable to similar measures presented by other issuers.
To view this news release in HTML formatting, please use the following URL: http://www.newswire.ca/en/releases/archive/February2011/25/c5579.html
pplease contact our Investor Relations Department at 1-800-319-6462 or email a href="mailto:investorrelations@enerplus.com"investorrelations@enerplus.com/a/p