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 2011 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. CALGARY, Feb. 24, 2012 /CNW/ -
Enerplus Corporation ("Enerplus") is pleased to announce 2011
year-end reserves, operating and financial results.
RESERVES/RESOURCES -- Total proved plus probable reserves ("2P") at
December 31, 2011 increased by 5% to 321.9 MMBOE year-over-year and
4% on a per share basis. -- 2P oil and liquids reserves grew by 14%
to total 184.8 MMBOE and now represent 57% of total 2P reserves, up
from 53% at year-end 2010. -- We replaced 175% of production
through our exploration and development program, adding 48 MMBOE of
2P reserves. Approximately 75% of the additions were oil and
liquids and represented a 300% replacement of our 2011 oil and
liquids production. The largest amount of reserve additions came
from our Fort Berthold crude oil property in North Dakota. -- We
sold 5.2 MMBOE of 2P reserves in 2011, including 23 Bcfe associated
with our Marcellus disposition. After dispositions, we replaced
157% of 2011 production volumes. -- Despite a 30% decrease in the
forecast price for natural gas, the estimated net present value
("NPV") of future net revenues from our reserves (discounted at
10%, before taxes) increased by almost 10% as a result of the
increased weighting of light sweet crude oil reserves in our
portfolio. The NPV of our oil properties in the U.S. rose by nearly
50% primarily as a result of our successful drilling activities. --
Over and above our 2P reserves, our best estimate of contingent
resources associated with our tight oil, waterflood and Marcellus
resource plays at December 31, 2011 totaled 485 MMBOE representing
150% of our booked 2P reserves. -- Our 2P reserve life index was
9.8 years at year-end, down from 10.7 years at December 31, 2010 as
a result of the addition of higher decline production from our new
growth plays and a decrease in shallow gas reserves. -- As a result
of the weak outlook for natural gas prices, approximately 33 Bcfe
of natural gas reserves were removed from our reserve report at
year-end. Total natural gas 2P reserves declined by 5%
year-over-year. -- Our 2P Finding and Development costs ("F&D")
excluding future development capital ("FDC") were $17.22/BOE,
reflecting the significant positive additions delivered from our
new growth plays in North Dakota and in the Marcellus. -- Our 2P
F&D costs including FDC were $26.26/BOE. In 2011, approximately
$150 million of our capital spending related to projects that did
not add reserves in 2011. This amount was disproportionately higher
than normal mainly due to spending in the Marcellus and North
Dakota and the timing of wells coming on-stream. -- Our 2P Finding,
Development and Acquisition costs ("FD&A") without FDC were
$8.57/BOE and $17.89/BOE with FDC, reflecting the significant value
captured in the sale of our Marcellus interests which had minimal
reserves. OPERATIONS -- We made significant progress growing our
production base organically during 2011. We entered the year with
production of 77,200 BOE/day and exited producing approximately
82,000 BOE/day. Our annual average production was 75,332 BOE/day,
slightly less than our guidance of 76,000 BOE/day as we experienced
execution delays during the first half of the year on key projects.
-- Our exploration and development capital spending in 2011 totaled
approximately $866 million, $96 million higher than our guidance of
$770 million. The increase was due to higher fourth quarter
activity levels supported by favourable weather conditions
including accelerated spending on permitting, regulatory work and
equipment inventory along with approximately $35 million of cost
increases related to our U.S. Bakken properties. -- We invested
approximately $720 million on drilling and completions activities
during 2011 with 106.8 net wells drilled, 74% of which were drilled
on our crude oil properties. -- We continued to focus our asset
base during 2011 through our acquisition and divestment activities.
We spent approximately $112.5 million adding 133,000 undeveloped
acres in emerging plays in Canada to support our future growth. We
also sold assets for aggregate proceeds of $641 million, with $568
million coming from our second quarter Marcellus disposition where
we recognized a gain of $272 million. -- At December 31, 2011, we
held a portfolio of approximately 380,000 net acres of strategic
land comprised of 75,000 net acres at Fort Berthold targeting the
Bakken and Three Forks, 65,000 net acres in the Duvernay, 33,000
net acres in the Montney, 67,000 net acres in the Stacked
Mannville, 30,000 net acres in the Cardium and other emerging oil
plays in Canada and 110,000 net acres in the Marcellus. --
Favourable weather conditions during the fourth quarter drove high
levels of activity in our field operations. As a result, we
experienced increased costs related to well servicing, repairs and
maintenance and higher than expected Alberta power costs. Our
annual operating costs were $10.23/BOE for the year compared to
guidance of $9.60/BOE. FINANCIAL -- Cash flow from operating
activities for 2011 totaled $623 million, down from $696 million in
2010. Stronger oil prices in 2011 were offset by lower natural gas
prices and lower average production levels due to the full year
impact of 2010 dispositions along with approximately $60 million of
taxes related to gains on our dispositions in our U.S. subsidiary.
-- We maintained our monthly dividend at $0.18/share throughout
2011, paying $2.16/share in total and representing a payout ratio
of approximately 68% of funds flow. -- Our adjusted payout ratio,
which calculates dividends plus capital spending divided by funds
flow, was 221% for 2011. However, after including our net
acquisition and disposition activity, our adjusted payout ratio was
153%. Our payout ratio has increased year-over-year as a result of
our significant investment in early stage growth assets that are
not generating immediate production or cash flow. This has been
compounded due to the decline in natural gas prices. -- Despite the
reduction in cash flow we continued to maintain our balance sheet
strength with a trailing twelve month debt-to-funds flow ratio of
1.6x at year-end. At December 31, 2011 we had $554 million of
available credit under our bank credit facility. We believe we also
have the ability to increase the size of our bank facility should
we choose. -- During 2011 our price risk management program
generated cash gains of $13 million on natural gas contracts and
cash losses of $47 million on crude oil contracts. We have
continued to add crude oil hedge positions and approximately 62% of
our projected crude oil production in 2012 has downside protection
at an average floor price of US$96.22 . In addition, we have
approximately 10% of our 2013 crude oil production hedged at an
average price of US$101.20. We have no natural gas hedge positions
in place at this time. -- As a result of lower natural gas prices,
we recorded a $334 million non-cash impairment on our Canadian
natural gas operations in 2011. Under International Financial
Reporting Standards ("IFRS") impairment charges related to capital
assets are reversed in future periods if conditions causing the
impairment change, such as a recovery in natural gas prices. -- On
February 8, 2012 we closed a $345 million equity financing to help
fund our 2012 capital program and maintain our financial
flexibility. SELECTED FINANCIAL Three months ended December Twelve
months ended RESULTS 31, December31, 2011 2010(1) 2011 2010(1)
Financial (000's) Funds Flow(2) $156,682 $162,606 $573,609 $728,968
Cash Flow from 696,183 Operating Activities 242,192 142,033 623,440
Dividends to 384,127 Shareholders 97,725 96,396 388,904 Net
Income/(Loss) (299,415) 64,500 109,437 (179,282) Debt Outstanding -
724,031 net of cash 901,465 724,031 901,465 Exploration and 536,436
Development Capital Spending 344,837 225,926 865,712 Property and
Land 1,012,272 Acquisitions 45,263 522,847 255,209 Divestments
3,082 537,935 641,190 871,458 Financial per Weighted Average Shares
Outstanding Funds Flow(2) $0.87 $0.92 $3.19 $4.15 Dividends 0.54
0.55 2.16 2.19 Net Income/(Loss) (1.66) 0.37 0.61 (1.02) Weighted
Average 175,736 Number of Shares Outstanding 180,845 176,648
179,889 Debt to Trailing 12 1.0x Month Funds Flow(2) 1.6x 1.0x 1.6x
Payout Ratio(2) 62% 59% 68% 53% Adjusted Payout 127% Ratio(2) 284%
234% 221% Selected Financial Results per BOE(3) Oil & Gas
Sales(4) $50.29 $42.49 $48.85 $42.85 Royalties (9.62) (6.20) (8.92)
(7.36) Commodity 1.64 Derivative Instruments (1.54) 1.02 (1.21)
Operating Costs (11.64) (8.42) (10.33) (9.66) General and (2.76)
Administrative (3.05) (3.48) (2.99) Interest and Other (1.69)
Expenses (1.70) (2.95) (1.59) Taxes (0.68) (0.40) (2.95) 1.00 Funds
Flow(2) $22.06 $22.06 $20.86 $24.02 SELECTED OPERATING Three months
ended December Twelve months ended RESULTS 31, December31, 2011
2010 2011 2010 Average Daily Production Crude oil 31,715 30,368
30,181 31,135 (bbls/day) NGLs (bbls/day) 3,256 4,027 3,306 3,889
Natural gas 253,500 274,314 251,068 288,692 (Mcf/day) Total
(BOE/day) 77,221 80,114 75,332 83,139 % Crude Oil & 45% 43% 44%
42% Natural Gas Liquids Average Selling Price (4) Crude oil (per
bbl) $87.56 $72.18 $83.48 $70.38 NGLs (per bbl) 68.32 53.66 64.99
51.41 Natural gas (per 3.41 3.63 3.72 4.05 Mcf) US$/CDN$ exchange
0.98 0.99 1.01 0.97 rate Net Wells drilled 36 40 107 225 (1) 2010
comparative amounts have been restated and are presented in
accordance with International Financial Reporting Standards
("IFRS") and represent the results of Enerplus Resources Fund which
converted into Enerplus Corporation on January 1, 2011. (2) See
"Non-GAAP Measures" in the accompanying MD&A. (3) Non-cash
amounts have been excluded. (4) Net of oil and gas transportation
costs, but before the effects of commodity derivative instruments.
SHARE TRADING SUMMARY CDN* U.S.** For the twelve months ended
December 31, 2011 (CDN$) (US$) High $32.83 $33.29 Low $23.00 $21.65
Close $25.85 $25.32 * TSX and other Canadian trading data combined.
**NYSE and other U.S. trading data combined. 2011 CASH DIVIDENDSPER
SHARE Payment Month CDN$ US$ First Quarter Total $0.54 $0.55 Second
Quarter Total $0.54 $0.55 Third Quarter Total $0.54 $0.55 Fourth
Quarter Total $0.54 $0.53 Total Year-to-Date $2.16 $2.18 US$
dividends represent CDN$ dividends converted at the relevant
foreign exchange rate on the payment date 2011 PRODUCTION &
CAPITAL SPENDING 2011 2011 Exit 2011 Annual 2011 vs Capital Play
Type Average Exit 2010Exit ($million) Tight Oil (BOE/day) 13,616
16,703 26% 375 Crude Oil Waterfloods 164 (BOE/day) 15,127 16,760
22% Conventional Oil (BOE/day) 4,661 4,761 -20% 19 Total Oil
(BOE/day) 33,404 38,224 16% $558 Marcellus Shale Gas 210 (Mcfe/day)
20,524 25,213 43% Other Natural Gas (Mcfe/day) 231,040 237,798 -4%
98 Total Gas (Mcfe/day) 251,564 263,011 -1% $308 Company Total
75,332 82,059 6% $866 2011 NET DRILLING ACTIVITY* Wells Pending Dry
& Horizontal Vertical Total Completion/ Wells Abandoned Play
Type Wells Wells Wells Tie-in * On-stream** Wells Tight Oil 34.0 -
34.0 4.8 30.8 - Crude Oil Waterfloods 33.8 0.3 34.1 9.0 31.9 0.5
Conventional Oil 11.2 0.1 11.3 4.9 8.6 - Total Oil 79.0 0.4 79.4
18.7 71.3 0.5 Marcellus Shale Gas 16.0 - 16.0 13.9 5.3 - Other
Natural Gas 9.0 2.4 11.4 3.7 52.8 - Total Gas 25.0 2.4 27.4 17.6
58.1 - Company Total 104.0 2.8 106.8 36.3 129.4 0.5 *Wells drilled
during the year that are pending potential completion/tie-in or
abandonment as at December 31, 2011 ** Total wells brought
on-stream during the year regardless of when they were drilled KEY
RESOURCE PLAY ACTIVITY Tight Oil - Fort Berthold We invested
approximately $290 million at Fort Berthold during 2011 targeting
both the Bakken and Three Forks light crude oil formations,
representing the single largest capital investment area in our
portfolio. A total of 25 net operated wells were drilled (18 short
lateral wells and 7 long lateral wells) with approximately 21 net
wells brought on stream during the year. As a result of our
successful drilling activities, we more than doubled the reserves
in this property adding 33 MMBOE of 2P reserves plus an additional
3 MMBOE added due to technical revisions for a total of 36 MMBOE of
2P reserve additions at a cost of $19.16/BOE. We converted 30 MMBOE
of our Bakken contingent resources to reserves, leaving 30 MMBOE of
contingent resources attributable to the Bakken. We also added 19
MMBOE of contingent resources attributable to the Three Forks for a
total of 49 MMBOE of independently assessed contingent resources at
Fort Berthold at December 31, 2011. These contingent resources
represent 78 future drilling locations over and above the 52 booked
drilling locations in our 2P reserve report based primarily upon a
drilling density of two wells per drilling spacing unit in both the
Bakken and Three Forks formations. Given the drilling density to
date, we assumed a land utilization of 90% for the Bakken and only
35% for the Three Forks given the limited well control at this
time. Enerplus has approximately 115 net sections of land in the
Fort Berthold region with less than 50 wells currently on
production. Our Bakken well results have typically outperformed our
expectations throughout 2011. As a result, we have increased
our expected ultimate recovery ("EUR") estimates for Bakken wells
in this area to 800,000 bbls/long lateral well and 400,000
bbls/short lateral well which is at the high end of our previous
expectations. These estimates are based upon drilling two wells per
spacing unit. Five Three Forks wells (one long and four short) were
brought on-stream in 2011. The long lateral well averaged 800
BOE/day during the first 30 days of production and the four short
lateral wells averaged 450 BOE/day during the first 30 days. These
results essentially met our expectations which assumed Three Forks
wells would produce approximately 70% of a Bakken well. Two
multi-well pads were drilled to test various well densities and
communication between the Bakken and Three Forks formations however
further production run time is needed in order to determine the
optimal development scenario. Production at Fort Berthold increased
from 4,000 BOE/day at the start of 2011 to approximately 9,000
BOE/day as we exited the year. Our plans are to grow
production to 20,000 to 25,000 BOE/day from this region over the
next two to three years. We plan to spend approximately $300
million in 2012 at Fort Berthold running three to four drilling
rigs in the play with the majority of wells expected to be long
horizontal wells. Through the latter part of 2011, we
experienced an escalation in our drilling and completion costs in
large part due to the high activity levels in the region. We are
making several changes to our well design and execution procedures
and are targeting a long horizontal well cost of approximately $10
million as we exit spring break-up. Despite this cost
escalation, with our increased estimate of recoveries, the net
present value of a long horizontal well is approximately $15
million. We anticipate rates of return in this region of over
60% based upon current commodity prices. Crude Oil Waterfloods We
continued to focus our efforts on enhancing the value of our crude
oil waterflood portfolio through both drilling activity and
enhanced oil recovery techniques. We invested $164 million with
approximately 60% directed to drilling and completions and the
remainder on plant and facility enhancements to support future
activities. We drilled 34.1 net wells with the majority of
our drilling in the Ratcliffe, Viking and Cardium plays. We
advanced work on our two enhanced oil recovery projects at Giltedge
and Medicine Hat in 2011. To date, production results from the
project area are better than anticipated and we expect to expand
the polymer flood by adding three injection wells in 2012. Our
activities at Medicine Hat included facilities improvements in
preparation for polymer injection in the first quarter of
2012. We replaced 100% of production, adding 5.6 MMBOE of 2P
reserves, including the conversion of 800,000 BOE of contingent
resources associated with our polymer project at Giltedge and 3.4
MMBOE of contingent resources associated with our incremental oil
recovery projects. In addition to the 89.9 MMBOE of 2P reserves
booked to our waterflood properties at year-end, our internal best
estimate of contingent resources (associated with only a portion of
our waterflood portfolio) was 56 MMBOE at December 31, 2011.
Approximately 34 MMBOE of contingent resources are attributable to
the enhanced oil recovery projects at Giltedge and Medicine Hat. As
work proceeds and assessed results support the economic viability
of these projects, we would expect that contingent resources will
be reclassified as reserves. In 2012, we intend to invest
approximately $150 million, or approximately half of the cash flow
generated by these properties, to maintain production. We
plan to direct $85 million to drilling/completions/injector
conversion activities, $58 million on plant/facilities/maintenance,
and $7 million on our enhanced oil recovery projects at Giltedge
and Medicine Hat. With a low base decline rate of
approximately 12%, these properties provide a complement to our new
growth properties that have higher initial decline rates. Marcellus
Shale In 2011, under a strategy of reducing our inventory of
non-operated dry gas, we successfully sold approximately 45% of our
non-operated acreage position in the Marcellus for $568
million. We realized a net gain of $272 million on the sale
and have essentially recovered all of our initial investment in
this region while retaining ownership of approximately 110,000 net
acres, 60% of which is operated. Marcellus activities during 2011
were focused on delineation drilling to determine the viability of
the Marcellus in new areas, to retain leases and to add production
and reserves in developing areas. Approximately $210 million was
invested on delineation and development drilling activities
(including $36 million that was spent on properties that were part
of the disposition) with roughly three quarters of this amount
invested with our non-operated partners in the northeast region of
Pennsylvania. We drilled a total of 16 net wells (12 non-operated
and 4 operated) during the year. However due to delays in pipeline
infrastructure, only 5.3 net non-operated wells were brought
on-stream in 2011. Despite these delays and the sale of 5.4 MMcfe
of production, we were able to increase production by approximately
120% year-over-year and exited 2011 producing approximately 25.2
MMcf/day. Through our successful drilling activities, we added 67.2
Bcf of 2P reserves. Total 2P reserves booked in the Marcellus
are now 154 Bcf, up 64% from our 2P reserves booking at December
31, 2010 of 94 Bcf adjusted for the disposition. An independent
best estimate of contingent resources in the Marcellus is 2.3 Tcf
of natural gas, essentially unchanged from our 2010 estimate of
contingent resources net of the disposition. As a result of the
success of our drilling program, our independent reserve evaluators
have increased the estimated average EUR per well to 6.6 Bcf from
the previous estimate of 5.4 Bcf. We believe that our 2P F&D
costs including FDC of $3.84/Mcf are not a true reflection of
long-term F&D in this area as almost 50% of the capital spent
this year related to wells and facilities which did not come
on-stream in 2011 and had no associated reserve bookings at year
end. We currently have 13 net producing wells (120 gross wells) and
16 net wells (246 gross wells) waiting on completions and/or
tie-in. We plan to spend approximately $190 million in the
Marcellus region in 2012, with approximately 80% allocated to our
non-operated interests in the northeast area of Pennsylvania. With
the low natural gas price environment, we plan to prudently invest
with our partners to retain this valuable acreage. Well results in
northeast Pennsylvania have continued to surpass our expectations
in terms of both initial production rates and declines. Well costs
in this region are currently averaging $7 to $8 million per
well. We plan to direct approximately $30 to $40 million to
drill appraisal wells on our operated leases in Pennsylvania where
we are focused on demonstrating the potential in these areas and
retaining our lease interests. In total we expect to participate in
drilling approximately 19 net wells in the Marcellus with
approximately 18 net wells on-stream in 2012. We expect our total
Marcellus production to grow from 25 MMcf/day at the end of 2011 to
close to 70 MMcf/day as we exit 2012. Liquids Rich Natural Gas In
2011, we spent $91 million on our liquids rich natural gas
prospects in Alberta and British Columbia. We continued to
delineate our Stacked Mannville position in the
Ansell/Minehead/Hanlan areas drilling three Wilrich wells and one
Bluesky operated well. As previously mentioned, we added to our
Montney land position throughout 2011, acquiring approximately
17,000 net acres in the Cameron area taking our total Montney land
position to approximately 33,000 net acres. We drilled our
first vertical Montney delineation well at the end of 2011 and
expect to complete this well in early 2012. Results from our 2011
drilling activities were positive as we grew production from 13,800
BOE/day to 16,800 BOE/day as we exited the year. In addition,
4.9 MMBOE of 2P reserves (before economic and technical revisions)
were added replacing 100% of production. As a result of continued
weak natural gas prices, we plan to take a measured approach to
spending in this area in 2012. We expect to invest $80 million on
both our operated and non-operated leases. Our operated drilling
will target the Stacked Mannville as well as delineation of our
Montney and Duvernay acreage positions. RESERVES AND CONTINGENT
RESOURCES All of our reserves, including our U.S. reserves, were
evaluated using Canadian National Instrument 51-101 ("NI 51-101")
standards. Independent reserve evaluations have been
conducted on approximately 86% of the total proved plus probable
value (discounted at 10%) of our reserves at December 31, 2011.
McDaniel & Associates Consultants Ltd. ("McDaniel") evaluated
86% of our Canadian reserves as well as the reserves associated
with our western U.S. assets and reviewed the internal evaluation
completed by Enerplus on the remaining portion. The evaluation of
contingent resources associated with our leases at Fort Berthold
was conducted by Enerplus and audited by McDaniel. Haas Petroleum
Engineering Services Inc. ("Haas") evaluated 100% of our Marcellus
shale gas assets in the U.S. and provided both the reserves and
contingent resource estimates. The contingent resource assessments
associated with our waterflood properties was completed internally
by Enerplus. See "Information Regarding Reserves, Resources and
Operational Information" at the end of this news release for
information regarding the presentation of company interest reserves
and contingent resources. Reserves & Contingent Resources by
Resource Play Incremental Proved plus Future Proved Probable "Best
Contingent plus Booked Estimate" Resource Net Proved Probable Net
Drilling Contingent Drilling Play Types Reserves Reserves Locations
Resources* Locations Tight Oil (MMBOE) 48.6 84.1 63 49 78 Crude Oil
Waterfloods (MMBOE) 69.1 89.9 50 56 TBD Conventional Oil (MMBOE)
13.7 18.4 12 - - Total Oil (MMBOE) 131.4 192.4 125 105 78 Marcellus
Shale Gas (Bcf) 92.7 153.5 14 2,279 430 Conventional Gas (Bcfe)
443.2 624.1 134 - - Total Gas (Bcfe) 535.8 777.6 148 2,279 430
Total Company (MMBOE) 220.8 321.9 273 485 508 * No contingent
resource assessment has been conducted on our tight gas, shallow
gas or other conventional oil and gas assets at this time. Only a
portion of our crude oil waterflood portfolio has been assessed for
contingent resources at this time. Waterflood contingent resources
include resources added through enhanced oil recovery and
incremental oil recovery activities. Numbers may not add due to
rounding. Reserves Summary The following table sets out our company
interest, gross and net reserve volumes at December 31, 2011 by
production type and reserve category under McDaniel's forecast
price scenarios as 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. Company interest reserves consist of gross reserves,
which are before the deduction of any royalties, plus Enerplus'
royalty interests in reserves. Light & Natural Medium Heavy
Total Gas Natural Shale Reserves Oil Oil Oil Liquids Gas Gas Total
Summary (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
CompanyInterest Proved Producing 66,595 25,560 92,155 7,854 432,013
43,738 179,300 Proved Developed Non-Producing 2,415 376 2,791 115
9,004 16,317 7,127 Proved Undeveloped 18,350 3,368 21,718 1,246
35,870 32,627 34,380 Total Proved 87,360 29,304 116,664 9,215
476,887 92,682 220,807 Total Probable 44,407 10,090 54,497 4,411
192,363 60,861 101,112 Proved plus Probable 131,767 39,394 171,161
13,626 669,250 153,543 321,919 Gross Proved Producing 65,817 25,546
91,363 7,717 415,541 43,738 175,627 Proved Developed Non-Producing
2,406 376 2,782 116 8,969 16,317 7,112 Proved Undeveloped 18,345
3,368 21,713 1,224 33,776 32,627 34,004 Total Proved 86,568 29,290
115,858 9,057 458,286 92,682 216,743 Total Probable 44,178 10,086
54,264 4,303 181,185 60,861 98,908 Proved plus Probable 130,746
39,376 170,122 13,360 639,471 153,543 315,651 Net Proved Producing
57,162 20,962 78,124 5,452 371,957 30,593 150,668 Proved Developed
Non-Producing 2,034 326 2,360 90 7,588 13,271 5,925 Proved
Undeveloped 14,731 2,695 17,426 978 31,198 26,474 28,016 Total
Proved 73,927 23,983 97,910 6,520 410,743 70,338 184,609 Total
Probable 36,197 7,995 44,192 3,279 165,476 48,183 83,081 Proved
plus Probable 110,124 31,978 142,102 9,799 576,219 118,521 267,690
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, 2010 to December 31,
2011. 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, 2010 49,608 29,177
78,785 8,515 510,049 - 172,308 Acquisitions 125 - 125 - - - 125
Dispositions (779) - (779) (7) (917) - (939) Discoveries - - - - -
- - Extensions & Improved Recovery 3,115 1,080 4,195 332 21,959
- 8,187 Economic Factors 52 28 80 (133) (16,059) - (2,730)
Technical Revisions (1,706) 2,022 316 234 2,571 - 978 Production
(3,978) (3,003) (6,981) (1,160) (79,981) - (21,471) Proved Reserves
at Dec. 31, 2011 46,437 29,304 75,741 7,781 437,622 - 156,458 Light
& Natural Medium Heavy Total Gas Natural UNITED Oil Oil Oil
Liquids Gas Shale Gas Total STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls)
(MMcf) (MMcf) (MBOE) Proved Reserves at Dec. 31, 2010 30,921 -
30,921 95 44,041 52,225 47,061 Acquisitions - - - - - - -
Dispositions - - - (11) - (10,299) (1,728) Discoveries - - - - - -
- Extensions & Improved Recovery 12,236 - 12,236 668 4,456
55,435 22,886 Economic Factors - - - - - (3,824) (637) Technical
Revisions 1,801 - 1,801 729 (4,936) 6,507 2,792 Production (4,035)
- (4,035) (47) (4,296) (7,362) (6,025) Proved Reserves at Dec. 31,
2011 40,923 - 40,923 1,434 39,265 92,682 64,349 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, 2010 80,529 29,177 109,706 8,610
554,090 52,225 219,369 Acquisitions 125 - 125 - - - 125
Dispositions (779) - (779) (18) (917) (10,299) (2,667) Discoveries
- - - - - - - Extensions & Improved Recovery 15,351 1,080
16,431 1,000 26,415 55,435 31,073 Economic Factors 52 28 80 (133)
(16,059) (3,824) (3,367) Technical Revisions 95 2,022 2,117 963
(2,365) 6,507 3,770 Production (8,013) (3,003) (11,016) (1,207)
(84,277) (7,362) (27,496) Proved Reserves at Dec. 31, 2011 87,360
29,304 116,664 9,215 476,887 92,682 220,807 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, 2010 14,098 9,783 23,881 2,825
173,983 - 55,703 Acquisitions 34 - 34 - - - 34 Dispositions (331) -
(331) (3) (321) - (387) Discoveries - - - - - - - Extensions &
Improved Recovery 1,268 1,050 2,318 175 10,595 - 4,259 Economic
Factors (13) 7 (6) (140) (10,294) - (1,861) Technical Revisions
(1,502) (750) (2,252) 98 (6,617) - (3,257) Production - - - - - - -
Probable Reserves at Dec. 31, 2011 13,554 10,090 23,644 2,955
167,346 - 54,491 Light & Natural Medium Heavy Total Gas Natural
UNITED Oil Oil Oil Liquids Gas Shale Gas Total STATES (Mbbls)
(Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE) Probable Reserves at
Dec. 31, 2010 16,266 - 16,266 141 24,114 64,437 31,165 Acquisitions
- - - - - - - Dispositions - - - (60) - (12,693) (2,175)
Discoveries - - - - - - - Extensions & Improved Recovery 17,319
- 17,319 937 6,302 28,993 24,138 Economic Factors - - - - - (1,819)
(304) Technical Revisions (2,732) - (2,732) 438 (5,399) (18,057)
(6,203) Production - - - - - - - Probable Reserves at Dec. 31, 2011
30,853 - 30,853 1,456 25,017 60,861 46,621 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, 2010 30,364 9,783 40,147 2,966
198,097 64,437 86,868 Acquisitions 34 - 34 - - - 34 Dispositions
(331) - (331) (63) (321) (12,693) (2,562) Discoveries - - - - - - -
Extensions & Improved Recovery 18,587 1,050 19,637 1,112 16,897
28,993 28,397 Economic Factors (13) 7 (6) (140) (10,294) (1,819)
(2,165) Technical Revisions (4,234) (750) (4,984) 536 (12,016)
(18,057) (9,460) Production - - - - - - - Probable Reserves at Dec.
31, 2011 44,407 10,090 54,497 4,411 192,363 60,861 101,112 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, 2010
63,706 38,960 102,666 11,340 684,032 - 228,011 Acquisitions 159 -
159 - - - 159 Dispositions (1,110) - (1,110) (10) (1,238) - (1,326)
Discoveries - - - - - - - Extensions & Improved Recovery 4,383
2,130 6,513 507 32,554 - 12,446 Economic Factors 39 35 74 (273)
(26,353) - (4,591) Technical Revisions (3,208) 1,272 (1,936) 332
(4,046) - (2,279) Production (3,978) (3,003) (6,981) (1,160)
(79,981) - (21,471) Proved Plus Probable Reserves at Dec. 31, 2011
59,991 39,394 99,385 10,736 604,968 - 210,949 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, 2010 47,187 -
47,187 236 68,155 116,662 78,226 Acquisitions - - - - - - -
Dispositions - - - (71) - (22,992) (3,903) Discoveries - - - - - -
- Extensions & Improved Recovery 29,555 - 29,555 1,605 10,758
84,428 47,024 Economic Factors - - - - - (5,643) (941) Technical
Revisions (931) - (931) 1,167 (10,335) (11,550) (3,411) Production
(4,035) - (4,035) (47) (4,296) (7,362) (6,025) Proved Plus Probable
Reserves at Dec. 31, 2011 71,776 - 71,776 2,890 64,282 153,543
110,970 Light & Natural Medium Heavy Gas Natural Shale TOTAL
Oil Oil TotalOil Liquids Gas Gas Total ENERPLUS (Mbbls) (Mbbls)
(Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE) Proved Plus Probable Reserves
at Dec. 31, 2010 110,893 38,960 149,853 11,576 752,187 116,662
306,237 Acquisitions 159 - 159 - - - 159 Dispositions (1,110) -
(1,110) (81) (1,238) (22,992) (5,229) Discoveries - - - - - - -
Extensions & Improved Recovery 33,938 2,130 36,068 2,112 43,312
84,428 59,470 Economic Factors 39 35 74 (273) (26,353) (5,643)
(5,532) Technical Revisions (4,139) 1,272 (2,867) 1,499 (14,381)
(11,550) (5,690) Production (8,013) (3,003) (11,016) (1,207)
(84,277) (7,362) (27,496) Proved Plus Probable Reserves at Dec. 31,
2011 131,767 39,394 171,161 13,626 669,250 153,543 321,919 NET
PRESENT VALUE OF FUTURE PRODUCTION REVENUE The estimated reserve
volumes and net present values of all future net revenues at
December 31, 2011 were based upon forecast crude oil and natural
gas pricing assumptions prepared by McDaniel as of January 1, 2012.
These prices were applied to the reserves evaluated by McDaniel and
Haas, along with those evaluated internally by Enerplus and
reviewed by McDaniel. The base reference prices and exchange rates
used by McDaniel are detailed below: McDaniel January 2012 Forecast
Price Assumptions Light Crude Oil Hardisty Natural Gas WTI Crude
(1) Heavy Oil Henry Hub 30 day spot Exchange Oil Edmonton 12oAPI
Gas Price @ AECO Rate US$/bbl CDN$/bbl CDN$/bbl US$/MMBtu
CDN$/MMBtu US$/CDN$ 2012 97.50 99.00 74.00 3.75 3.50 0.975 2013
97.50 99.00 74.00 4.50 4.20 0.975 2014 100.00 101.50 75.90 5.05
4.70 0.975 2015 100.80 102.30 76.50 5.50 5.10 0.975 2016 101.70
103.20 77.10 5.95 5.55 0.975 Thereafter ** ** ** ** ** 0.975 (1)
Edmonton Light Sweet 40 degree API, 0.5% sulphur content crude **
Escalation varies after 2016 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 and after 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. The after tax net present value of future
production revenues reflects the tax burden on properties on a
stand-alone basis and does not consider the business-entity level
tax situation or any tax planning. Net Present Value of Future
Production Revenue - Forecast Prices and Costs (Before Tax)
Reserves at December 31, 2011, ($ millions, 0% 5% 10% 15%
discounted at) Proved developed producing 5,958 4,080 3,155 2,606
Proved developed non-producing 232 174 141 118 Proved undeveloped
1,006 623 408 274 Total Proved 7,196 4,877 3,704 2,998 Probable
4,449 2,377 1,550 1,125 Total Proved Plus Probable Reserves 11,645
7,254 5,254 4,123 Total Proved Plus Probable Reserves (after 8,550
5,428 3,994 3,175 tax) NET ASSET VALUE Enerplus' estimated net
asset value is based on 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
plus the estimated value of our undeveloped acreage and other
equity investments, less decommissioning liabilities , long-term
debt and net working capital. 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, 2011, the estimate of
contingent resources contained within our leases was 485 million
BOE, more than 1.5 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, 2011) ($ millions except per share
amounts, discounted at) 0% 5% 10% 15% Total net present value of
proved plus probable reserves (before tax) $11,645 $7,254 $5,254
$4,123 Undeveloped acreage (2011 Year End) (1) Canada (845,849
Acres) 224 224 224 224 U.S. West (98,742 Acres) 218 218 218 218
U.S. Marcellus Shale (106,985 Acres) 264 264 264 264
Decommissioning liability (2) (309) (155) (30) (2) Long-term debt,
including current portion (net of cash) (901) (901) (901) (901) Net
working capital including deferred financial assets and credits
(349) (349) (349) (349) Marcellus carry commitment (37) (37) (37)
(37) Other equity investments (3) 208 208 208 208 Net Asset Value
ofAssets $10,963 $6,726 $4,851 $3,748 Net Asset Valueper Share(4)
$60.52 $37.13 $26.78 $20.69 (1) Acreage acquired in 2009, 2010 and
2011 valued at acquisition cost. Acreage acquired prior to 2009
valued at $100/acre. (2) Decommissioning liability does not equal
the amount on the balance sheet ($563.8 million) as the balance
sheet amount uses a 2.49% discount rate and a portion of the
decommissioning liability costs are already reflected in the
estimated net present value of future net revenues from our
reserves computed by the independent reserve evaluators. (3) Other
equity investment portfolio is valued at the estimated fair value.
(4) Based on 181,159,000 shares outstanding as at December 31,
2011. F&D AND FD&A COSTS F&D and FD&A costs have
been calculated both including and excluding future development
capital. The aggregate of the exploration and development costs
incurred in the most recent financial year and the change during
that year in estimated future development costs generally will not
reflect total finding and development costs related to reserve
additions for that year. The significant increase in FDC reported
at year-end is primarily related to higher well cost assumptions in
both the Fort Berthold and Marcellus regions. 2011 F&D and
FD&A Costs Excluding Future Including Future ($ millions except
for per BOE Development Development amounts) Capital Capital Proved
Plus Probable Reserves Finding & Development Costs Capital
Expenditures (1) $ 829.8 $ 829.8 Net change in Future Development
Capital - $ 435.9 Company Interest reserve additions (MMBOE) 48.2
48.2 F&D costs ($/BOE) $ 17.22 $ 26.26 Finding, Development
& Acquisition Costs Capital expenditures and net acquisitions $
370.2 $ 370.2 Net change in Future Development Capital - $ 402.7
Company Interest reserve additions (MMBOE) 43.2 43.2 FD&A costs
($/BOE) $ 8.57 $ 17.89 Proved Reserves Finding & Development
Costs Capital Expenditures (1) $ 829.8 $ 829.8 Net change in Future
Development Capital - $ 230.7 Company Interest reserve additions
(MMBOE) 31.5 31.5 F&D costs ($/BOE) $ 26.34 $ 33.67 Finding,
Development & Acquisition Costs Capital expenditures and net
acquisitions $ 370.2 $ 370.2 Net change in Future Development
Capital - $ 213.0 Company Interest reserve additions (MMBOE) 28.9
28.9 FD&A costs ($/BOE) $ 12.81 $ 20.18 (1) 2011 E&D
capital - excludes $35.9 million of spending associated with sold
Marcellus properties (2) Net acquisition capital is exclusive of
$109.6 million associated with the Marcellus carry commitment
2012 OUTLOOK We plan to spend $800 million on exploration and
development projects in 2012 delivering annual production growth of
over 10%. We are forecasting average production of
approximately 83,000 BOE/day during 2012 growing to approximately
88,000 BOE/day as we exit the year. Over 70% of our spending is
expected to be focused on oil and liquids rich natural gas projects
with 40% of our capital directed to light crude oil development at
Fort Berthold, North Dakota. As a result, we expect annual
oil production to grow by approximately 7,000 BOE in 2012 and we
expect our average crude oil and liquids production will increase
from 45% of total production to approximately 50% in 2012. We
expect production will grow throughout 2012 ranging from
approximately 77,200 BOE/day in the last quarter of 2011 to 88,000
BOE/day as we exit 2012. Based upon current forward commodity
prices, we expect cash flow to increase in 2012 as a result of the
growth in our total production volumes and in particular, the
expected increase in crude oil and liquids volumes. We plan to
minimize spending on our operated dry gas projects given the
current outlook for natural gas prices. We intend to continue to
invest alongside our partners in the Marcellus as they drill to
delineate and retain leases and have allocated approximately $190
million on both our operated and non-operated leases. We expect
production to grow from 25 MMcf/day currently to close to 70
MMcf/day as we exit 2012. Canadian conventional dry gas production
is expected to decline throughout the year with Marcellus gas
production increasing to represent approximately 30% of our total
corporate natural gas volumes by year-end. Although natural gas
prices are under pressure today, the Marcellus continues to be one
of the lowest cost dry gas developments in North America and we
believe this asset will play an important part in our future growth
strategy. Through a disciplined exploration program, we plan to
invest close to $100 million to unlock the value in our undeveloped
land base in the Duvernay, Montney, and Cardium plays and in our
operated acreage in the Marcellus as well as advancing our enhanced
oil recovery projects. This spending is not expected to contribute
significant new production in 2012 although we expect it will set
the stage for future production and reserve additions. Despite
anticipated cash flow growth in 2012 as a result of increases in
production, we anticipate our capital spending and dividends will
exceed cash flow. We plan to fund the shortfall through debt
financing, the proceeds of our recent $345 million equity financing
and expected proceeds from an expanded dividend reinvestment plan.
In addition, we continue to hold a portfolio of equity investments
that we may sell to help fund capital spending or acquisitions. As
always, we will continue to evaluate dividend levels with respect
to cash flow, debt levels, capital spending, commodity prices and
market conditions. Summary 2012 Guidance Target Average annual
production: Crude Oil (bbls/day) 37,200 Natural Gas Liquids
(bbls/day) 3,800 Natural Gas (Mcf/day) 252,000 Total 83,000 BOE/day
Exit rate 2012 production: Crude Oil (bbls/day) 40,500 Natural Gas
Liquids (bbls/day) 4,100 Natural Gas (Mcf/day) 260,000 Total 88,000
BOE/day 2012 production mix 50% oil & NGLs, 50% gas Development
capital: Development Drilling & Completions $600 million
Plant/Facilities $70 million Maintenance $30 million Exploration
& Seismic $100 million Total $800 million Planned Drilling
Activity 108 net wells Planned On-streams 95 net wells
Acquisitions: Marcellus carry commitment $37 million Undeveloped
land & lease extensions $40 million Average royalty rate 21%
Operating costs $10.40/BOE G&A costs $3.55/BOE Average interest
and financing costs 6% 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. Given that the value ratio based on the current price of
oil as compared to natural gas is significantly different from the
energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may
be misleading. "MBOE" and "MMBOE" mean "thousand barrels of oil
equivalent" and "million barrels of oil equivalent", respectively.
Presentation of Production and Reserves Information All production
volumes and revenues presented herein 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, 2011, 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, 2011 ("our AIF")
which will be available in mid-March 2012 on our website at
www.enerplus.com and under 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 ultimate recovery rates,
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.
Enerplus expects to develop these contingent resources in the
coming years however it is too early in their development for these
resources to be classified as reserves at this time. All of our
contingent resource estimates are economic using established
technologies and under current commodity price assumptions used by
our independent reserve evaluators. 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, 2011. 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 additional information regarding the
primary contingencies which currently prevent the classification of
our disclosed "contingent resources" associated with our Marcellus
shale gas assets, our North Dakota Bakken properties and our crude
oil waterflood properties as reserves and the positive and negative
factors relevant to the "contingent resource" estimates, see our
Annual Information Form for the year ended December 31, 2010 (and
corresponding Form 40-F) dated March 11, 2011, a copy of which is
available under our SEDAR profile at www.sedar.com and a copy of
the Form 40-F which is available under our EDGAR profile at
www.sec.gov. F&D and FD&A Costs 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. FD&A costs presented in this news release are
calculated (i) in the case of FD&A costs for proved reserves,
by dividing the sum of exploration and development costs and the
cost of net acquisitions incurred in the year plus the change in
estimated future development costs in the year, by the additions to
proved reserves including net acquisitions in the year, and (ii) in
the case of FD&A costs for proved plus probable reserves, by
dividing the sum of exploration and development costs and the cost
of net acquisitions incurred in the year plus the change in
estimated future development costs in the year, by the additions to
proved plus probable reserves including net acquisitions 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, development and acquisition costs related to
its reserves additions for that year. 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, plans and
costs; the performance of and future results from Enerplus' assets
and operations, including anticipated production levels, expected
ultimate recoveries 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; sources of funding of Enerplus'
capital program; 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, cash flow and other sources 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 reserves and resources 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 "funds flow", "payout ratio" and "adjusted payout ratio" to
analyze operating performance, leverage and liquidity, and the
terms "F&D costs" and "FD&A costs" as measures of operating
performance. We calculate funds flow based on cash flow from
operating activities before changes in non-cash operating working
capital and decommissioning expenditures, all of which are measures
prescribed by Canadian generally accepted accounting principles
("GAAP") which were revised effective January 1, 2011 to converge
with International Financial Reporting Standards ("IFRS") and which
appear in our Consolidated Statements of Cash Flows. We calculate
"payout ratio" by dividing dividends to shareholders by funds
flow. "Adjusted payout ratio" is calculated as cash dividends
to shareholders plus development capital and office expenditures,
divided by funds flow from operating activities. Enerplus believes
that, in addition to net earnings and other measures prescribed by
GAAP, the terms "funds flow", "payout ratio", "adjusted payout
ratio", "F&D costs" and "FD&A costs" 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. Enerplus Corporation
CONTACT: please contact our Investor Relations Department
at1-800-319-6462 oremail investorrelations@enerplus.com.
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Enerplus (NYSE:ERF)
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