All financial information contained within this news release has been prepared
in accordance with U.S. GAAP including comparative figures pertaining to
Enerplus' 2012 results. This news release includes forward-looking statements
and information within the meaning of applicable securities laws. Readers are
advised to review the "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
2013 Financial Statements and MD&A are available 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. 21, 2014 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF)
(NYSE: ERF) is pleased to announce fourth quarter 2013 results as well as 2013
year-end operating and financial results.
2013 KEY TAKEAWAYS:
-- Funds flow per share grew by 14%
-- Production grew by 9%, exceeding guidance in spite of non-core
-- Proved plus probable reserves were up 17% year-over-year,
replacing 284% of 2013 production
-- Capital spending, operating costs and general and
administrative costs were all reduced
-- Debt to funds flow ratio at year-end improved to 1.4x
4th Quarter 2013:
-- Production continued to grow during the fourth quarter of 2013
averaging 94,167 BOE per day, up 7% from the previous quarter
and 10% compared to the same period in 2012. Production during
the month of December averaged 99,569 BOE per day, ahead of our
exit guidance of 95,000 BOE per day. Marcellus production
exceeded our expectations, producing 170 MMcf per day during
the month of December including the additional working
interests acquired in late November. Crude oil and natural gas
liquids volumes were virtually unchanged quarter over quarter,
despite the sale of 900 barrels per day of crude oil in
Canada. As a result of the higher volumes from the Marcellus,
our production weighting to natural gas increased to 56% during
the fourth quarter.
-- We invested $223 million in capital projects during the
quarter, with over two thirds of the spending directed to oil
projects. A total of 18 net wells were drilled, with 19 net
wells brought on-stream.
-- Funds flow totaled $181 million during the fourth quarter, down
8% from the previous quarter. Despite the growth in production
volumes, a widening of crude oil differentials resulted in a
decrease of almost 20% in our average realized crude oil price
compared to the previous quarter.
-- Cash operating costs and general and administrative expenses
per BOE were both down compared to the third quarter, averaging
$10.46 and $2.28 per BOE, respectively.
-- We closed a number of transactions during the fourth quarter
including the acquisition of additional working interests in
our Marcellus natural gas properties for $158 million. Through
this acquisition, we added 17,000 net acres in existing
properties in northeast Pennsylvania with approximately 42 MMcf
per day of natural gas production.
-- We also closed the sale of non-core producing assets in Canada
for proceeds of $104 million. In addition, we entered into an
agreement to sell our undeveloped Montney acreage in British
Columbia for $135 million, after adjustments, of which $66
million closed during the quarter with the remainder closed in
January of 2014.
-- We delivered annual production growth of 9% in 2013, exceeding
both our annual and exit production forecasts for the year.
Daily production averaged 89,800 BOE, ahead of guidance of
89,000 BOE per day. Total oil production increased by 5% in
2013 to average 38,250 barrels per day, despite the sale of
2,700 BOE per day of non-core oil production.
-- Natural gas production increased by 15% to average 288 MMcf per
day for the year, representing 54% of our annual production
volumes. Strong well performance in the Marcellus combined with
the acquisition of additional working interests in December
helped to drive this result.
-- Funds flow grew by 17% year-over-year to $754 million due to
the increase in production volumes, lower costs and an increase
in commodity prices. On a per share basis, this was a 14%
-- Capital spending came in slightly lower than our forecast of
$685 million, totaling $681 million. Approximately 70% of our
spending was directed to our crude oil assets with the majority
invested at Fort Berthold, North Dakota. We invested 82% of our
budget on drilling and completion activities, with 62 net wells
drilled and brought on-stream across our asset base.
-- We continued to concentrate our portfolio throughout 2013. We
sold $365 million of non-core assets, redeploying $245 million
to increase our working interests in our crude oil waterflood
portfolio and in the Marcellus. This also includes additional
acreage acquired in the Wilrich, Marcellus and Bakken/Three
Forks plays. Our net acquisition and divestment activities
realized gross proceeds of $120 million in 2013.
-- Our capital efficiencies improved again in 2013. Based upon
our capital spending and the growth in production volumes from
the fourth quarter of 2012 to the same period in 2013, this
reflects a capital efficiency of approximately $26,000 per
-- With the increase in funds flow, a reduction in capital
spending and improved capital efficiencies, our adjusted payout
ratio improved to 114% in 2013 including participation in our
Stock Dividend Plan ("SDP"). Monthly dividends to shareholders
were maintained throughout the year, totaling $1.08 per share
and represented 23% of funds flow including the SDP.
-- As a result of the growth in funds flow and the net proceeds
from our divestment activities, our financial flexibility
increased in 2013. Approximately 80% of our bank credit
facility was undrawn and our trailing twelve month
debt-to-funds-flow ratio fell to 1.4 times at year-end, down
from 1.7 times at year-end 2012.
-- Our proved plus probable ("2P") company interest reserves
increased by 17% at year-end, replacing 284% of our 2013
average daily production.
-- Finding and development costs including future development
capital ("FDC") were $11.28 per BOE. When divided by our
corporate netback of $27.40 per BOE, this reflects a 2.4x
-- Finding, development and acquisition costs, including FDC, were
$8.36 per BOE.
-- The net present value of our future net revenues discounted at
10% before tax increased by 7% in 2013 to approximately $5
SELECTED FINANCIAL Three months ended December Twelve months ended
RESULTS 31, December 31,
2013 2012 2013 2012
Funds Flow $180,741 $200,411 $754,233 $644,523
Cash and Stock
Dividends 54,665 53,572 216,864 301,560
Net Income 29,626 34,637 47,976 (270,697)
Debt Outstanding -
net of cash 1,022,308 1,064,365 1,022,308 1,064,365
Capital Spending 223,035 160,934 681,437 853,455
Property and Land
Acquisitions 173,387 121,391 244,837 185,337
Divestitures 168,050 220,135 365,135 275,771
Debt to Trailing 12
Month Funds Flow 1.4x 1.7x 1.4x 1.7x
Funds Flow $0.89 $1.01 $3.76 $3.29
Net Income 0.15 0.17 0.24 (1.38)
Number of Shares
Outstanding (000's) 202,257 198,256 200,567 195,633
Results per BOE(1)
Oil & Natural Gas
Sales(3) $43.79 $45.86 $48.11 $44.56
Royalties (7.46) (7.28) (8.06) (7.06)
Production Taxes (2.07) (2.26) (2.15) (1.89)
Instruments 1.90 2.04 0.81 0.61
Operating Costs (10.46) (9.14) (10.50) (10.51)
Administrative (2.28) (2.34) (2.54) (2.61)
Compensation (1.06) (0.03) (0.71) (0.18)
Interest and Other
Expenses (1.51) (1.45) (1.71) (1.42)
Taxes 0.01 0.08 (0.24) (0.05)
Funds Flow $20.86 $25.48 $23.01 $21.45
SELECTED OPERATING Three months ended December Twelve months ended
RESULTS 31, December 31,
2013 2012 2013 2012
(bbls/day) 37,731 38,597 38,250 36,509
NGLs (bbls/day) 3,813 3,576 3,472 3,627
(Mcf/day) 315,739 259,904 288,423 251,773
Total (BOE/day) 94,167 85,490 89,793 82,098
% Crude Oil &
Liquids 44% 49% 46% 49%
Crude oil (per
bbl) $ 77.77 $ 76.75 $ 83.99 $ 78.19
NGLs (per bbl) 54.26 47.31 52.25 53.01
Natural gas (per
Mcf) 3.26 3.01 3.26 2.39
Net Wells drilled 18 11 62 75
(1) Non-cash amounts have been excluded.
(2) Based on Company interest production volumes.
(3) Net of oil and gas transportation costs, but before royalties and
the effects of commodity derivative instruments.
Three months ended December Twelve months ended
31, December 31,
2013 2012 2013 2012
WTI crude oil $97.46 $88.18 $97.97 $94.21
AECO- monthly index 3.16 3.06 3.16 2.40
AECO- daily index 3.53 3.22 3.17 2.39
NYMEX- monthly NX3 3.63 3.36 3.67 2.80
USD/CDN exchange 1.05 0.99 1.03 1.00
SHARE TRADING SUMMARY CDN* - ERF U.S.** - ERF
For the twelve months ended December 31, (CDN$) (US$)
High $19.96 $18.79
Low $12.26 $12.03
Close $19.30 $18.18
* TSX and other Canadian trading data combined.
**NYSE and other U.S. trading data combined.
2013 DIVIDENDS PER SHARE CDN$ US$(1)
First Quarter Total $0.27 $0.27
Second Quarter Total $0.27 $0.26
Third Quarter Total $0.27 $0.26
Fourth Quarter Total $0.27 $0.26
Total $1.08 $1.05
(1) US$ dividends represent CDN$ dividends converted at the relevant
foreign exchange rate on the payment date.
2013 PRODUCTION & CAPITAL SPENDING
Crude Oil & 2013 2013 2013 Capital
NGLs Average Annual Average Exit Spending
(bbls/day) Production Production Production* ($million)
Canada 19,561 20,663 18,958 172.9
United States 21,983 21,059 21,455 316.2
Oil & NGLs
(bbls/day) 41,544 41,722 40,413 $489.1
Canada 165,114 175,876 161,965 113.7
United States 150,625 112,547 192,967 78.7
Gas (Mcf/day) 315,739 288,423 354,932 $192.4
(BOE/day) 94,167 89,793 99,569 $681.4
2013 NET DRILLING ACTIVITY***
Pending Dry &
Crude Horizontal Vertical Total Completion/ Wells Abandoned
Oil Wells Wells Wells Tie-in * On-stream** Wells
Canada 20.9 .2 21.1 1.8 18.6 -
States 20.3 - 20.3 4.5 24.7 -
Oil 41.2 .2 41.4 6.3 43.3 -
Canada 11.5 - 11.5 6.2 5.6 -
States 9.3 - 9.3 5.6 12.7 -
Gas 20.8 - 20.8 11.8 18.2 -
Total 62.0 .2 62.2 18.1 61.5 -
* Wells drilled during the year that are pending potential completion/tie-in
or abandonment as at December 31, 2013.
** Total wells brought on-stream during the year regardless of when they were
*** Table may not add due to rounding.
Our 2013 capital program was focused in our four core areas - the U.S.
Bakken/Three Forks, the Marcellus, our Canadian crude oil waterfloods and our
deep gas opportunities within the Deep Basin region of Alberta. Our single
largest capital investment was once again in North Dakota where we allocated
45% of our capital budget to continue development of the Bakken and Three
Forks zones. Our program was focused on improving capital efficiencies through
a reduction in well costs and increased productivity. We continued to evolve
our well completion design in North Dakota throughout 2013 and through these
changes and focused cost management; we were able to deliver a 50% increase in
the average 30 day initial production rate while still reducing total well
costs by 8% on average in 2013. The changes have driven a 40% improvement in
capital efficiencies year-over-year. We grew production from this region by
over 30% in 2013. We also added 25 MMBOE of 2P reserves at a cost of $19.74
per BOE including future development capital. With an average netback of
approximately $53 per BOE in 2013, this delivered a 2.7x recycle ratio.
We continued to invest in the Marcellus throughout 2013, concentrating our
drilling activity within the most economic areas in northeastern Pennsylvania.
Well costs improved year-over-year decreasing by approximately 20% through a
combination of pad drilling and lower costs. As well, production rates
continued to exceed our expectations throughout the year. A total of 9 net
wells were drilled in 2013, with 13 net wells tied in and brought on-stream.
Despite a widening of the basis differentials in the region given constrained
take-away capacity, we continue to see robust economics from our drilling
program. The majority of our drilling activity was focused in Bradford,
Susquehanna and Sullivan counties with average 30 day initial production rates
increasing by approximately 60% year-over-year to almost 10 MMcf per day in
these counties. Production during the month of December averaged 170 MMcf per
day of natural gas, driven by the acquisition of additional working interests
and the tie-in of 6 net wells in the fourth quarter. Through our development
and acquisition activities, we added 411 Bcf of 2P reserves at a cost of $0.91
per Mcf including future development capital. This reflects a 2.2x recycle
ratio based upon our average netback of $2.00 per Mcf from the Marcellus in
2013. Our Marcellus production represents approximately 50% of both our
corporate natural gas volumes and our 2P natural gas reserves.
Our activities in Canada were predominately directed to our crude oil
waterflood projects where we advanced our enhanced oil recovery project at
Medicine Hat and continued with our drilling and optimization programs at our
Freda Lake, Pembina, and Giltedge properties. We also drilled 4 net wells in
the Wilrich and in the Duvernay, we drilled two vertical wells, one horizontal
re-entry and spud one horizontal well in 2013 to advance our understanding of
these emerging plays.
RESERVES AND CONTINGENT RESOURCE ASSESSMENT:
Our total 2P reserves increased by over 17% year-over-year, driven by
significant reserve additions in the Marcellus and also in our Bakken/Three
Forks properties in North Dakota. At December 31, 2013, Enerplus' independent
reserve evaluators had assessed 406 million BOE of 2P company interest
reserves attributable to our asset base. Additional information on our 2013
reserves can be found in our news release dated February 3, 2014.
In addition to the 2P reserves, an assessment of the additional resource
potential within a portion of our asset base has identified 363 MMBOE of
economic, best estimate contingent resources ("contingent resources") as of
December 31, 2013. This quantity of contingent resources is essentially
unchanged from year-end 2012, despite converting approximately 70 MMBOE of
contingent resources to reserves. Based upon our forecast production volumes
for 2014, this would represent approximately 10 years of organic reserve
replacement potential currently existing within a portion of our portfolio
Our contingent resource assessment includes:
-- 39 MMBOE of contingent resources attributable to both the
Bakken and Three Forks at Fort Berthold. 18 MMBOE of previously
assessed contingent resources were converted to reserves in
2013 and 23 MMBOE of new contingent resources were added
primarily associated with the Three Forks formation. This
assessment assumes a well density of two wells per drilling
spacing unit within the Bakken and two wells per spacing unit
within the first bench of the Three Forks formation only. We
believe further upside potential may exist through both
increased drilling density and also drilling into the lower
benches in the Three Forks.
-- 59 MMBOE of contingent resources attributable to improved oil
recovery ("IOR") and enhanced oil recovery ("EOR") in our
Canadian waterflood assets. Approximately 4 MMBOE of previously
assessed contingent resources were converted to reserves in
-- 1.3 Tcf of contingent resources associated with our Marcellus
natural gas assets. We added approximately 290 Bcf of
contingent resources associated with the acquisition of
additional working interests and reclassified 258 Bcf of
contingent resources to reserves as a result of our successful
-- 253 Bcf of contingent resources associated with our Wilrich
deep gas assets in Canada. Approximately 30 Bcf of contingent
resources were reclassified to reserves in 2013 as a result of
our successful drilling activities.
At this time, there has been no assessment of the resource potential within
our Duvernay land position.
We expect to produce an average of 96,000 - 100,000 BOE/day in 2014, an
increase of 9% year-over-year or 8% per share using the mid-point of this
range. We expect continued growth from our U.S. oil properties at Fort
Berthold where we anticipate that average annual production will increase by
approximately 30% in 2014, driving our light crude oil volumes to 67% of our
total oil production. Total crude oil and natural gas liquids production is
expected to increase by approximately 12%. Natural gas production is expected
to increase by 7% averaging over 300 MMcf per day with the majority of the
growth attributable to the Marcellus. Our U.S. assets are anticipated to
account for over 50% of our corporate production volumes in 2014. The
production mix is expected to remain at approximately 48% crude oil and
natural gas liquids and 52% natural gas although continued outperformance in
the Marcellus could push the natural gas share higher.
The improvement in asset quality and operational performance along with our
focus on cost reductions and productivity enhancements has resulted in a
significant improvement in capital efficiencies across our portfolio. We plan
to build on these improvements in 2014 to deliver another year of profitable
growth complemented by a meaningful dividend to our investors. Our plans
include investing $760 million in capital projects in 2014 with two thirds of
our budget directed to oil projects in North Dakota and in our Canadian
waterfloods. The remainder of our budget will be directed to our core natural
gas assets in the Marcellus and in the Deep Basin region as we move into
development in the Wilrich and continue to evaluate the Duvernay. Given that
approximately 55% of our planned capital spending is in the U.S., continued
weakness in the Canadian dollar could put upward pressure on our 2013 spending
which is reported in Canadian dollars, although it would also have a positive
effect on reported revenues.
We continue to hedge a portion of our crude oil and natural gas production in
order to provide downside protection to our funds flow estimates. As of
February 4, 2014, we have swapped approximately 59% of our net crude oil
production for 2014, after royalties, at an average price of US$94.02 per
barrel. We also have downside protection on approximately 40% of our
forecasted natural gas production after royalties for 2014. Full details on
our hedging contracts are contained within our 2013 Annual MD&A & Financial
Statements which have been filed on SEDAR and EDGAR.
Changes to Board of Directors
We are pleased to announce that Ms. Hilary Foulkes has joined the Board of
Directors of Enerplus. Ms. Foulkes has over 30 years of experience within the
Canadian oil and gas industry focused in the areas of exploration, development
and investment banking. She is a professional geologist and earned a Bachelor
of Science (Honours, Earth Sciences) from the University of Waterloo.
Live Conference Call
Ian C. Dundas, President and CEO, will host a conference call today, February
21, 2014 at 9:00 a.m. MT (11:00 a.m. ET) to discuss these results. Details of
the conference call are as follows:
Date: Friday, February 21, 2014
Time: 9:00 am MT/11:00 am ET
To ensure timely participation in the conference call, callers are encouraged
to dial in 15 minutes prior to the start time to register for the event. A
podcast of the conference call will also be available on our website for
downloading following the event. A telephone replay will be available for 30
days following the conference call and can be accessed at the following
1-855-859-2056 (toll free)
Electronic copies of our 2013 year-end MD&A and Financial Statements, along
with other public information including investor presentations, are available
on our website at www.enerplus.com. For further information, please contact
Investor Relations at 1-800-319-6462 or email email@example.com.
Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.
INFORMATION REGARDING RESERVES, RESOURCES AND OPERATIONAL INFORMATION
Currency and Accounting Principles
All amounts in this news release are stated in Canadian dollars unless
otherwise specified. All financial information in this news release has been
prepared and presented in accordance with U.S. GAAP, except as noted below
under "Non-GAAP Measures".
Barrels of Oil Equivalent
This news release also contains references to "BOE" (barrels of oil
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.
BOEs 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
Under U.S. GAAP oil and gas sales are generally presented net of royalties and
U.S. industry protocol is to present production volumes net of royalties.
Under IFRS and Canadian industry protocol oil and gas sales and production
volumes are presented on a gross basis before deduction of royalties. In
order to continue to be comparable with our Canadian peer companies, the
summary results contained within this news release presents our production and
BOE measures on a before royalty company interest basis.
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 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, 2013, which will include complete disclosure
of our oil and gas reserves and other oil and gas information in accordance
with NI 51-101, is contained within our Annual Information Form for the year
ended December 31, 2013 ("our AIF") which is available on our website at
www.enerplus.com and under our SEDAR profile at www.sedar.com. Additionally,
our AIF forms part of our Form 40-F that is filed with the U.S. Securities and
Exchange Commission and is available on EDGAR at www.sec.gov. Readers are also
urged to review the Management's Discussion & Analysis and financial
statements filed on SEDAR and as part of our Form 40-F on 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, 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. All of our contingent resource estimates are economic
using established technologies and under current commodity price assumptions
used by our independent reserve evaluators. 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.
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, 2013.
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 properties, our Fort Berthold properties, our
Wilrich natural gas properties and a portion of our Canadian crude oil
properties as reserves and the positive and negative factors relevant to the
"contingent resource" estimates, see our AIF, a copy of which is available
under our SEDAR profile at www.sedar.com, and our Form 40-F, a copy of which
is available under our EDGAR profile at www.sec.gov.
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 in SEC filings, whereas
Canadian issuers may disclose oil and gas resources. Resources are different
than, and should not be construed as reserves. For a description of the
definition of, and the risks and uncertainties surrounding the disclosure of,
contingent resources, see "Information Regarding 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' asset
portfolio; future capital and development expenditures and the allocation
thereof among our 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; future funds flow and debt-to-funds flow levels; potential asset
acquisitions and dispositions; rates of return 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 reflects
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 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 realized prices for Enerplus'
products; 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 our AIF and Form 40-F described above).
The purpose of certain financial outlook information included in this news
release, including with respect to our 2014 guidance for funds flow, is to
communicate our current expectations as to our performance in 2014. Readers
are cautioned that it may not be appropriate for other purposes. The
forward-looking information contained in this news release speaks only as of
the date of this news release, and none of Enerplus or its subsidiaries assume
any obligation to publicly update or revise them to reflect new events or
circumstances, except as may be required pursuant to applicable laws.
In this news release, we use the terms "funds flow", "adjusted payout ratio",
"capital efficiency", "recycle ratio" and "netback" as measures to analyze
operating performance, leverage and liquidity. "Funds flow" is calculated as
net cash generated from operating activities but before changes in non-cash
operating working capital and asset retirement obligation expenditures.
"Adjusted payout ratio" is calculated as cash dividends to shareholders, net
of our stock dividends and DRIP proceeds, plus capital spending (including
office capital) divided by funds flow. "Capital efficiency" is calculated as
the change in production from the fourth quarter of the previous year to the
fourth quarter of the current year divided by total capital expenditures from
the fourth quarter of the previous year up to and including the third quarter
of the current year. "Netback" is calculated as oil and gas revenues after
deducting royalties, operating costs and transportation expenses. A "recycle
ratio" is calculated as finding and development costs divided by operating
Enerplus believes that, in addition to net earnings and other measures
prescribed by U.S. GAAP, the terms "funds flow", "adjusted payout ratio",
"capital efficiency", "netback" and "recycle ratio" 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 U.S. GAAP and do not have a standardized meaning prescribed by
U.S.GAAP. Therefore, these measures, as defined by Enerplus, may not be
comparable to similar measures presented by other issuers.
Ian C. Dundas
President & Chief Executive Officer
SOURCE Enerplus Corporation
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CO: Enerplus Corporation
NI: OIL ERN
-0- Feb/21/2014 11:00 GMT
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