All financial information contained within this news release
has been prepared in accordance with U.S. GAAP including
comparative figures pertaining to Enerplus' 2013 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 "Non-GAAP Measures" at the end of this news release for
information regarding the presentation of the financial and
operational information in this news release. A full copy of our
Third Quarter 2014 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, Nov. 7, 2014 /CNW/ - Enerplus Corporation
("Enerplus") (TSX: ERF) (NYSE: ERF) continued to deliver
consistent, strong operational and financial performance during the
third quarter of 2014.
OPERATIONAL HIGHLIGHTS:
- Daily production averaged approximately 104,000 BOE,
essentially unchanged from the second quarter. Crude oil and
natural gas liquids production increased again in the third quarter
to average 44,200 barrels per day, up 700 barrels over the second
quarter. We continue to achieve strong performance from our
Bakken/Three Forks properties in North
Dakota with production increasing by approximately 1,600 BOE
per day.
- Natural gas production was maintained quarter over quarter
despite an average of 3,000 - 4,000 BOE per day of Marcellus
production being temporarily curtailed due to pipeline maintenance
and low natural gas prices in the region.
- As a result of strong performance year to date, and despite the
sale of 3,500 BOE per day of non-core production, we are raising
our annual average production guidance again. We are increasing the
low end of our range by 2,000 BOE per day and now expect full year
production to average between 102,000 - 104,000 BOE per day.
The low end of this range largely reflects the risk of additional
curtailment in the Marcellus in the fourth quarter. We have
continued to see crude oil production growth in the fourth quarter
and expect to achieve our annual average liquids target of 44,000
barrels per day.
- We continued to execute on our non-core divestment strategy,
completing two transactions and further strengthening our financial
position. On September 30, 2014, we
closed the sale of approximately 1,900 BOE per day of non-operated
production in Canada, 75% weighted
to natural gas. We also sold an additional 1,200 BOE per day of
Canadian non-operated production (90% weighted to natural gas)
which closed in early November
2014.
- The total proceeds from these transactions are approximately
$91 million reflecting attractive
metrics of approximately $30,000 per
flowing barrel of production that is predominately natural
gas. We intend to continue to look for opportunities to
rationalize non-core production, providing us with the opportunity
to accelerate spending on our core assets while maintaining our
financial strength.
- We continued to execute our capital spending program investing
$208 million on development drilling
activities during the quarter. Our U.S. assets attracted the
majority of our capital spending. Roughly two thirds of the
capital, drilling and on-stream activity was attributable to the
Bakken and the Marcellus in the quarter. In total, we drilled
19.3 net wells and brought 17.3 net wells on-stream across our
portfolio.
- Our non-core divestments have generated proceeds of over
$200 million year-to-date. As a
result of this success, we have redeployed a portion of these
proceeds to advance opportunities within our core properties.
We had accelerated some of our 2015 drilling activity into the
fourth quarter of 2014, particularly in the Wilrich and at Fort
Berthold. We anticipate this will have only a modest
production impact in 2014 but will bring additional volumes
on-stream earlier in 2015. We plan to spend an additional
$30 million this year, and are
adjusting our full year capital spending to $830 million.
FINANCIAL HIGHLIGHTS
- Despite the drop in commodity prices, funds flow was maintained
quarter over quarter at $213 million
or $1.04 per share.
- Dividends paid to shareholders represented 26% of funds flow
during the quarter. As previously announced, with the
strength of our balance sheet and the improved sustainability of
our business, we elected to suspend our reinvestment program (the
Stock Dividend Program), thereby reducing dilution and helping to
improve our per share metrics.
- Our realized commodity prices declined in the third quarter as
both the benchmark price of crude oil and natural gas declined. The
average realized price on our crude oil sales was CDN$86.49 per barrel, down 9% from the second
quarter. The average realized selling price of our natural gas was
CDN$3.22 per Mcf, a 20% reduction
compared to the second quarter.
- Our strong hedge positions are expected to provide a high level
of cash flow protection for the remainder of 2014 and into
2015. For the remainder of 2014, we have approximately 64% of
our forecast net crude oil production, after royalties, swapped at
an average price of US$95.29 per
barrel. For the first and second half of 2015, we have swapped
15,500 barrels per day and 8,000 barrels per day, respectively, of
crude oil at an average price of US$93.58 and US$93.86 per barrel. With respect to natural gas,
we have downside protection on approximately 50% of our forecast
net production after royalties for the remainder of 2014. We also
have downside protection on approximately 80 MMcf per day of
natural gas production in place for 2015.
- Cash general and administrative expenses were consistent with
the second quarter at $1.97 per BOE
and we are maintaining our full year guidance of $2.30 per BOE. We have reduced our guidance on
share based compensation from $0.60
per BOE to $0.45 per BOE as a result
of the decline in our share price.
- Operating costs increased to $10.67 per BOE, up 6% from the second quarter due
to production curtailments on our lower operating cost Marcellus
properties, seasonal well servicing and repairs and maintenance
costs. Based on continued production curtailments expected in the
Marcellus in the fourth quarter, we are revising our operating cost
guidance back to our original estimate for 2014 of $10.25 per BOE.
- We closed our US$200 million
private placement of 3.79%, 10 year average life, senior notes
which we announced in the second quarter. The proceeds were
used to repay outstanding bank debt. At September 30, 2014 only 5% of our $1 billion credit facility was drawn and our
debt-to-trailing 12 month funds flow ratio was 1.3x.
|
|
|
|
|
|
|
|
|
|
SELECTED FINANCIAL RESULTS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months
ended September 30, |
|
Nine months ended September 30, |
|
2014 |
2013 |
|
2014 |
2013 |
Financial (000's) |
|
|
|
|
|
|
|
|
|
Funds Flow |
$ |
212,779 |
$ |
196,187 |
|
$ |
646,502 |
$ |
573,492 |
Cash and Stock Dividends |
|
55,438 |
|
54,405 |
|
|
165,587 |
|
162,199 |
Net Income |
|
67,430 |
|
(3,720) |
|
|
147,424 |
|
18,350 |
Debt Outstanding - net of cash |
|
1,091,110 |
|
964,577 |
|
|
1,091,110 |
|
964,577 |
Capital Spending |
|
207,838 |
|
145,811 |
|
|
630,027 |
|
458,402 |
Property and Land Acquisitions |
|
3,986 |
|
15,792 |
|
|
17,186 |
|
71,451 |
Property Dispositions |
|
68,931 |
|
124,462 |
|
|
185,631 |
|
197,086 |
Debt to Trailing 12-Month Funds Flow |
|
1.3x |
|
1.2x |
|
|
1.3x |
|
1.2x |
|
|
|
|
|
|
|
|
|
|
Financial per Weighted Average Shares
Outstanding |
|
|
|
|
|
|
|
|
|
Funds Flow |
$ |
1.04 |
$ |
0.98 |
|
$ |
3.17 |
$ |
2.87 |
Net Income (Basic) |
|
0.33 |
|
(0.02) |
|
|
0.72 |
|
0.09 |
Weighted Average Number of Shares Outstanding
(000's) |
|
205,164 |
|
201,117 |
|
|
204,174 |
|
200,002 |
|
|
|
|
|
|
|
|
|
|
Selected Financial Results per
BOE(1)(2) |
|
|
|
|
|
|
|
|
|
Oil & Natural Gas
Sales(3) |
$ |
46.13 |
$ |
53.61 |
|
$ |
50.66 |
$ |
49.67 |
Royalties and Production Taxes |
|
(10.36) |
|
(11.91) |
|
|
(11.31) |
|
(10.46) |
Commodity Derivative Instruments |
|
(0.26) |
|
(1.30) |
|
|
(1.52) |
|
0.42 |
Operating Costs |
|
(10.67) |
|
(10.58) |
|
|
(10.28) |
|
(10.52) |
General and Administrative |
|
(1.97) |
|
(2.48) |
|
|
(2.08) |
|
(2.63) |
Share-Based Compensation |
|
0.54 |
|
(0.60) |
|
|
(0.44) |
|
(0.58) |
Interest, Foreign Exchange and Other Expenses |
|
(1.18) |
|
(1.78) |
|
|
(1.48) |
|
(1.78) |
Taxes |
|
- |
|
(0.65) |
|
|
(0.40) |
|
(0.33) |
Funds Flow |
$ |
22.23 |
$ |
24.31 |
|
$ |
23.15 |
$ |
23.79 |
|
|
|
|
|
|
|
SELECTED OPERATING
RESULTS |
|
|
|
|
|
|
|
|
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|
|
|
Three months ended
September 30, |
|
Nine months ended
September 30, |
|
2014 |
2013 |
|
2014 |
2013 |
Average Daily
Production(2) |
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/day) |
|
40,332 |
|
38,883 |
|
|
39,328 |
|
38,426 |
|
NGLs (bbls/day) |
|
3,869 |
|
2,985 |
|
|
3,591 |
|
3,357 |
|
Natural gas (Mcf/day) |
|
359,007 |
|
275,164 |
|
|
356,288 |
|
279,212 |
|
Total (BOE/day) |
|
104,035 |
|
87,729 |
|
|
102,300 |
|
88,318 |
|
% Natural Gas |
|
58% |
|
52% |
|
|
58% |
|
53% |
|
|
|
|
|
|
|
|
|
|
Average Selling
Price(2)(3) |
|
|
|
|
|
|
|
|
|
|
Crude oil (per bbl) |
$ |
86.49 |
$ |
96.30 |
|
$ |
90.91 |
$ |
86.05 |
|
NGLs (per bbl) |
|
44.85 |
|
49.88 |
|
|
53.01 |
|
51.48 |
|
Natural gas (per Mcf) |
|
3.22 |
|
2.96 |
|
|
4.04 |
|
3.26 |
|
Net Wells drilled |
|
19 |
|
15 |
|
|
63 |
|
50 |
(1) |
Non-cash amounts have been excluded. |
(2) |
Based on Company interest production volumes. See "Basis
of Presentation" section in the following MD&A. |
(3) |
Net of oil and gas transportation costs, but before royalties
and the effects of commodity derivative instruments. |
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30, |
|
Nine months ended September 30, |
Average Benchmark Pricing |
2014 |
2013 |
|
2014 |
2013 |
WTI crude oil (US$/bbl) |
$97.17 |
$105.82 |
|
$99.61 |
$98.14 |
AECO- monthly index (CDN$/Mcf) |
4.22 |
2.82 |
|
4.55 |
3.16 |
AECO- daily index (CDN$/Mcf) |
4.02 |
2.43 |
|
4.81 |
3.05 |
NYMEX- last day (US$/Mcf) |
4.06 |
3.58 |
|
4.55 |
3.67 |
USD/CDN exchange rate |
1.09 |
1.04 |
|
1.09 |
1.02 |
|
|
|
|
|
|
|
|
|
Share Trading Summary |
|
|
|
CDN* - ERF |
|
|
|
U.S.** - ERF |
For the three months ended September 30,
2014 |
|
|
|
(CDN$) |
|
|
|
(US$) |
High |
|
|
|
$27.05 |
|
|
|
$25.37 |
Low |
|
|
|
$20.21 |
|
|
|
$18.45 |
Close |
|
|
|
$21.26 |
|
|
|
$18.97 |
* |
TSX and other Canadian trading data combined. |
** |
NYSE and other U.S. trading data combined. |
|
|
|
|
|
|
|
|
2014 Dividends per
Share |
|
|
CDN$ |
|
|
|
US$(1) |
First Quarter Total |
|
|
$0.27 |
|
|
|
$0.24 |
Second Quarter Total |
|
|
$0.27 |
|
|
|
$0.24 |
July |
|
|
$0.09 |
|
|
|
$0.08 |
August |
|
|
$0.09 |
|
|
|
$0.08 |
September |
|
|
$0.09 |
|
|
|
$0.08 |
Third Quarter Total |
|
|
$0.27 |
|
|
|
$0.24 |
Total Year-to-Date |
|
|
$0.81 |
|
|
|
$0.72 |
(1) |
US$ dividends represent CDN$ dividends converted at the
relevant foreign exchange rate on the payment date. |
|
|
|
|
|
|
|
Production and
Capital Spending |
|
Three months ended
September 30, 2014 |
|
Nine months ended
September 30, 2014 |
Crude Oil & NGLs
(BOE/day) |
|
Average
Production
Volumes |
|
Capital
Spending
($ millions) |
|
Average
Production
Volumes |
|
Capital
Spending
($ millions) |
Canada |
|
19,415 |
|
$37 |
|
19,398 |
|
$128 |
United States |
|
24,786 |
|
96 |
|
23,521 |
|
255 |
Total Crude Oil & NGLs
(BOE/day) |
|
44,201 |
|
$133 |
|
42,919 |
|
$383 |
Natural Gas (Mcf/day) |
|
|
|
|
|
|
|
|
Canada |
|
154,855 |
|
$18 |
|
154,306 |
|
$115 |
United States |
|
204,152 |
|
57 |
|
201,982 |
|
132 |
Total Natural Gas (Mcf/day) |
|
359,006 |
|
$75 |
|
356,288 |
|
$247 |
Company Total (BOE/day) |
|
104,035 |
|
$208 |
|
102,300 |
|
$630 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Drilling Activity - for the three
months ended September 30, 2014 |
Crude Oil |
|
Horizontal
Wells |
|
Vertical
Wells |
|
Total
Wells |
|
Wells
Pending
Completion/
Tie-in * |
|
Wells
On-stream** |
|
Dry &
Abandoned
Wells |
Canada |
|
3.4 |
|
- |
|
3.4 |
|
2.2 |
|
5.5 |
|
- |
United States |
|
6.6 |
|
- |
|
6.6 |
|
6.6 |
|
5.6 |
|
- |
Total Crude Oil |
|
10.0 |
|
- |
|
10.0 |
|
8.8 |
|
11.1 |
|
- |
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
2.1 |
|
- |
|
2.1 |
|
1.4 |
|
0.8 |
|
- |
United States |
|
7.2 |
|
- |
|
7.2 |
|
6.9 |
|
5.4 |
|
- |
Total Natural Gas |
|
9.3 |
|
- |
|
9.3 |
|
8.3 |
|
6.2 |
|
- |
Company Total |
|
19.3 |
|
- |
|
19.3 |
|
17.1 |
|
17.3 |
|
- |
* |
Wells drilled during the quarter that are pending potential
completion/tie-in or abandonment as at September 30, 2014. |
** |
Total wells brought on-stream during the quarter regardless of
when they were drilled. |
|
|
ASSET ACTIVITY
Drilling activity continued at a brisk pace in Fort Berthold
during the third quarter with 6.6 net wells drilled and 5.6 net
wells brought on-stream. Production grew again to average 22,400
BOE per day, up almost 1,600 BOE per day from the second
quarter. Year-to-date, we have continued to drill into both
the Bakken and Three Forks zones with 10 operated wells and 2.4 net
non-operated wells brought on-stream. Production performance
has continued to improve as a result of our completion optimization
activity. The 30 day initial production rates on our two mile
horizontal wells brought on-stream in 2014 have averaged 1,725
barrels per day, 20% above our high expected ultimate recovery type
curve. We are also seeing an improvement of over 10% in the
60 day production rates which have averaged approximately 1,400
barrels per day.
In the Marcellus, drilling activity continued with 7.2 net wells
drilled and 5.4 net wells brought on-stream. Basis differentials in
the region continued to widen as a result of on-going production
growth and the shortage of take-away capacity. Our Marcellus
production received a discount of US$1.72 per Mcf to the NYMEX benchmark price
during the quarter. As a result of the lower prices in the region,
combined with pipeline maintenance, 3,000 - 4,000 BOE per day of
production was intentionally curtailed during the quarter.
Despite this curtailment, production from the Marcellus was
essentially unchanged from the second quarter, averaging 187 MMcf
per day. Plans are currently underway to slow our pace of activity,
moving from a four-rig program to a two-rig program. As a result,
we expect capital spending on our Marcellus assets in the fourth
quarter to be meaningfully lower than in the third quarter.
As discussed earlier in the year, Enerplus has drilled and
completed two horizontal Duvernay
wells in the Willesden Green area of central Alberta. Our initial horizontal well at
1-7-45-5W5M was completed in the first quarter of 2014 with a 13
stage hybrid slickwater frac. The well was subsequently shut-in for
installation of surface equipment and pipeline tie-in. In late
June, we brought this well on production achieving a 30 day initial
production rate of 535 BOE per day including 2.24 MMcf per day of
sales gas with 162 barrels per day of total liquids, 53%
condensate.
Our second horizontal well at 15-8-46-9W5M was completed in the
second quarter of this year with a 14 stage hybrid slickwater frac.
This well was also shut-in while surface equipment and pipelines
were installed to a third party gas plant and oil battery in the
area. We brought this well on-stream in early October and during
the first 30 days of production, it has averaged an estimated 700
BOE per day including 1.75 MMcf per day of sales gas, with 410
barrels per day of liquids, roughly 85% condensate.
Both wells have met our expectations on liquids content based
upon our geotechnical analysis. The cost of these wells was higher
than we expected, particularly on the completions, which is similar
to what others have experienced in this deep, over-pressured
play. We see a number of opportunities to increase drilling
and completion efficiencies going forward, particularly with
multi-well pads. Further evaluation of these wells over the coming
months is required in order to determine our next steps.
2014 GUIDANCE UPDATE
A summary of our revised 2014 guidance is outlined below.
2014 Expectations |
Target |
Average annual production |
102,000 - 104,000 BOE/day (from
100,000 - 104,000 BOE/day) |
Production mix (volume) |
44,000 bbls/day crude oil and
natural gas liquids
58,000 - 60,000 BOE/day natural gas (from 56,000 - 60,000
BOE/day) |
Capital spending |
$830 million (from $800
million) |
Average royalty rate
(% of gross sales, net of transportation) |
23% |
Operating costs |
$10.25/BOE (from $10.10/BOE) |
Cash G&A expenses |
$2.30/BOE |
Cash share-based compensation
expenses |
$0.45/BOE (from $0.60/BOE) |
U.S. Cash taxes (% of U.S. funds
flow) |
2% (from 3% - 5%) |
OUTLOOK
Despite the current decline in crude oil prices, Enerplus is
very well positioned. Based upon our revised production guidance,
we expect to deliver above-average production growth of 13% per
share in 2014. Our dividend payout is conservative and our
balance sheet is very strong. Our debt-to-trailing 12 month funds
flow ratio was 1.3 times at the end of the quarter and we have
virtually all of our $1 billion
revolving line of credit available. We also have a significant
portion of our crude oil production hedged for the remainder of
2014 and into 2015 at prices well above the current market. We
anticipate that these positions will provide strong funds flow
protection through the fourth quarter and into 2015, lending
support for our plans for the remainder of this year and next.
Our preliminary plans for 2015 target continued production
growth of 5 - 10% per share with a modestly lower capital spending
program than in 2014. We have a significant portfolio of economic
development opportunities in both crude oil and natural gas that
are expected to provide us with organic growth potential for many
years. We expect to maintain our strong financial position. We will
continue to apply discipline to our capital spending program,
ensuring that our plans are affordable and that our business is
sustainable.
CONFERENCE CALL DETAILS
A conference call hosted by Ian C. Dundas, President and CEO will be held at
9:00AM MT (11:00AM ET) today to discuss these results.
Details of the conference call are as follows:
|
Live Conference Call |
|
|
Date: |
Friday, November 7, 2014 |
Time: |
9:00AM MT / 11:00AM ET |
Dial-In: |
647-427-7450 |
|
888-231-8191 (toll free) |
|
Passcode: 17622905 |
Audiocast: |
http://www.newswire.ca/en/webcast/detail/1424204/1582028 |
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 be available on our website for downloading. A
telephone replay will be available for 30 days following the
conference call. The telephone replay can be accessed at the
following numbers:
|
|
Dial-In: |
416-849-0833 |
|
1-855-859-2056 (toll free) |
|
|
Passcode: |
17622905 |
|
|
Electronic copies of our Third Quarter 2014
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.
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.
Presentation of Production
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
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.
See "Non-GAAP Measures" below.
FORWARD-LOOKING INFORMATION AND
STATEMENTS
This news release contains certain
forward-looking information and forward-looking statements within
the meaning of applicable securities laws ("forward-looking
information"). 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: expected
2014 and 2015 average production volumes and the anticipated
production mix; the proportion of our anticipated oil and gas
production that is hedged; the results from our drilling program
and the timing of related production; future oil and natural gas
prices and differentials and our commodity risk management
programs; expectations regarding our realized oil and natural gas
prices; future royalty rates on our production and future
production taxes; anticipated cash and non-cash G&A,
share-based compensation and financing expenses; operating costs;
capital spending levels in the remainder of 2014 and in 2015 and
its impact on our production level; our future U.S. cash taxes;
deferred income taxes, our tax pools and the time at which we may
pay Canadian cash taxes and regular U.S. taxes; future debt and
working capital levels and debt-to-funds-flow ratio and adjusted
payout ratio, financial capacity, liquidity and capital resources
to fund capital spending and working capital requirements; the
amount and timing of future cash dividends that we may pay to our
shareholders; and future dispositions, including expected proceeds
therefrom and production volumes associated therewith.
The forward-looking information contained in
this news release reflects several material factors, expectations
and assumptions including, without limitation: that we will conduct
our operations and achieve results of operations as anticipated;
that our 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 our reserve
and resource volumes; commodity price and cost assumptions; the
continued availability of adequate debt and/or equity financing and
funds flow to fund our capital, operating and working capital
requirements, and dividend payments as needed; the continued
availability and sufficiency of our funds flow and availability
under our bank credit facility to fund our working capital
deficiency; the availability of third party services; and the
extent of our liabilities. We believe 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
of Enerplus' products; changes in the demand for or supply of our
products; unanticipated operating results, results from our capital
spending activities or production declines; changes in tax or
environmental laws, royalty rates or other regulatory matters;
changes in our capital plans or by third party operators of our
properties; increased debt levels or debt service requirements;
inaccurate estimation of our oil and gas reserve and resource
volumes; limited, unfavourable or a lack of access to capital
markets; increased costs; a lack of adequate insurance coverage;
the impact of competitors; reliance on industry partners and third
party service providers; a failure to complete planned asset
dispositions on the terms anticipated or at all; and certain other
risks detailed from time to time in our public disclosure documents
(including, without limitation, those risks and contingencies
described under "Risk Factors and Risk Management" in our MD&A
for the year ended December 31, 2013
and in our other public filings).
The forward-looking information contained in
this news release speaks only as of the date of this news rlease,
and we do not assume any obligation to publicly update or revise
such forward-looking information 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" and "debt-to-funds flow ratio" 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. "Debt-to-funds flow
ratio" is used to analyze leverage and liquidity and is calculated
as total debt net of cash, divided by a trailing 12 months of funds
flow.
Enerplus believes that, in addition to net
earnings and other measures prescribed by U.S. GAAP, the terms
"funds flow", and "debt-to-funds flow 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. See disclosure under
"Non-GAAP Measures" in our Third Quarter MD&A for
reconciliation of these measures to the most directly comparable
measures circulated in accordance with U.S. GAAP.
SOURCE Enerplus Corporation
Video with caption: "Video: Q3 Q&A with President and CEO,
Ian C. Dundas". Video available at:
http://stream1.newswire.ca/cgi-bin/playback.cgi?file=20141107_C9461_VIDEO_EN_43192.mp4&posterurl=http://photos.newswire.ca/images/20141107_C9461_PHOTO_EN_43192.jpg&clientName=Enerplus%20Corporation&caption=Video%3A%20Q3%20Q%26A%20with%20President%20and%20CEO%2C%20Ian%20C%2E%20Dundas&title=ENERPLUS%20CORPORATION%20%2D%20Enerplus%20Continues%20Operational%20Momentum%20in%20Third%20Quarter%202014%20%26%20Increases%20Annual%20Production%20Guidance&headline=Enerplus%20Continues%20Operational%20Momentum%20in%20Third%20Quarter%202014%20%26%20Increases%20Annual%20Production%20Guidance