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 asset sales
- 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.
2013 SUMMARY:
- 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% increase.
- 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 daily BOE.
- 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 recycle
ratio.
- 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 billion.
SELECTED FINANCIAL
RESULTS |
Three months ended December 31, |
|
Twelve months ended December 31, |
|
2013 |
2012 |
|
2013 |
2012 |
Financial (000's) |
|
|
|
|
|
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 |
Property Divestitures |
168,050 |
220,135 |
|
365,135 |
275,771 |
|
|
|
|
|
|
Debt to Trailing 12 Month Funds
Flow |
1.4x |
1.7x |
|
1.4x |
1.7x |
|
|
|
|
|
|
Financial per Weighted Average
Shares Outstanding |
|
|
|
|
|
Funds Flow |
$0.89 |
$1.01 |
|
$3.76 |
$3.29 |
Net Income |
0.15 |
0.17 |
|
0.24 |
(1.38) |
Weighted Average Number of Shares
Outstanding (000's) |
202,257 |
198,256 |
|
200,567 |
195,633 |
|
|
|
|
|
|
Selected Financial Results per
BOE(1)(2) |
|
|
|
|
|
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) |
Commodity Derivative Instruments |
1.90 |
2.04 |
|
0.81 |
0.61 |
Operating Costs |
(10.46) |
(9.14) |
|
(10.50) |
(10.51) |
General and Administrative |
(2.28) |
(2.34) |
|
(2.54) |
(2.61) |
Share Based 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 RESULTS |
Three months ended December 31, |
|
Twelve months ended December 31, |
|
2013 |
2012 |
|
2013 |
2012 |
Average Daily
Production(2) |
|
|
|
|
|
|
Crude oil (bbls/day) |
37,731 |
38,597 |
|
38,250 |
36,509 |
|
NGLs (bbls/day) |
3,813 |
3,576 |
|
3,472 |
3,627 |
|
Natural gas (Mcf/day) |
315,739 |
259,904 |
|
288,423 |
251,773 |
|
Total (BOE/day) |
94,167 |
85,490 |
|
89,793 |
82,098 |
|
|
|
|
|
|
|
% Crude Oil & Natural Gas Liquids |
44% |
49% |
|
46% |
49% |
|
|
|
|
|
|
Average Selling
Price(2)(3) |
|
|
|
|
|
|
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
31, |
|
Twelve months
ended December 31, |
|
|
2013 |
2012 |
|
2013 |
2012 |
Average Benchmark Pricing |
|
|
|
|
|
|
WTI crude oil (US$/bbl) |
|
$97.46 |
$88.18 |
|
$97.97 |
$94.21 |
AECO- monthly index (CDN$/Mcf) |
|
3.16 |
3.06 |
|
3.16 |
2.40 |
AECO- daily index (CDN$/Mcf) |
|
3.53 |
3.22 |
|
3.17 |
2.39 |
NYMEX- monthly NX3 index (US$/Mcf) |
|
3.63 |
3.36 |
|
3.67 |
2.80 |
USD/CDN exchange rate |
|
1.05 |
0.99 |
|
1.03 |
1.00 |
SHARE TRADING SUMMARY |
|
|
CDN* - ERF |
|
U.S.** - ERF |
For the twelve months ended December 31, 2013 |
|
|
(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 & NGLs
(bbls/day) |
|
Q4
2013
Average
Production |
|
2013
Annual Average
Production |
|
2013
Exit
Production* |
|
2013
Capital
Spending
($million) |
Canada |
|
19,561 |
|
20,663 |
|
18,958 |
|
172.9 |
United States |
|
21,983 |
|
21,059 |
|
21,455 |
|
316.2 |
Total Crude Oil & NGLs
(bbls/day) |
|
41,544 |
|
41,722 |
|
40,413 |
|
$489.1 |
Natural Gas (Mcf/day) |
|
|
|
|
|
|
|
|
Canada |
|
165,114 |
|
175,876 |
|
161,965 |
|
113.7 |
United States |
|
150,625 |
|
112,547 |
|
192,967 |
|
78.7 |
Total Natural Gas
(Mcf/day) |
|
315,739 |
|
288,423 |
|
354,932 |
|
$192.4 |
Company Total
(BOE/day) |
|
94,167 |
|
89,793 |
|
99,569 |
|
$681.4 |
*December month
2013 NET DRILLING
ACTIVITY*** |
Crude Oil |
|
Horizontal
Wells |
|
Vertical
Wells |
|
Total
Wells |
|
Wells
Pending
Completion/
Tie-in * |
|
Wells
On-stream** |
|
Dry &
Abandoned
Wells |
Canada |
|
20.9 |
|
.2 |
|
21.1 |
|
1.8 |
|
18.6 |
|
- |
United States |
|
20.3 |
|
- |
|
20.3 |
|
4.5 |
|
24.7 |
|
- |
Total Crude Oil |
|
41.2 |
|
.2 |
|
41.4 |
|
6.3 |
|
43.3 |
|
- |
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
11.5 |
|
- |
|
11.5 |
|
6.2 |
|
5.6 |
|
- |
United States |
|
9.3 |
|
- |
|
9.3 |
|
5.6 |
|
12.7 |
|
- |
Total Natural Gas |
|
20.8 |
|
- |
|
20.8 |
|
11.8 |
|
18.2 |
|
- |
Company 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 drilled.
*** Table may not add due to rounding.
ASSET ACTIVITY
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 today.
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 2013.
- 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 drilling activity.
- 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.
2014 Outlook
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.
Hedging Update
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 |
Dial-In: |
|
|
647-427-7450
1-888-231-8191 |
Audiocast: |
|
|
http://www.newswire.ca/en/webcast/detail/1298449/1432621 |
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
numbers:
Dial-In: |
|
|
416-849-0833 |
|
|
|
1-855-859-2056 (toll free) |
Passcode: |
|
|
58756618 |
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
investorrelations@enerplus.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.
NON-GAAP MEASURES
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
netback.
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
Enerplus Corporation
SOURCE Enerplus Corporation