All financial information contained within this news release
has been prepared in accordance with U.S. GAAP, except as noted
under "Non-GAAP Measures". 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. A full copy of our Third Quarter 2015 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. 6, 2015 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) announces the
results from operations for the third quarter of 2015, a reduction
in its monthly dividend and 2016 guidance.
"Enerplus delivered another quarter of strong operational
performance. With the continued improvement in our capital
efficiencies and the lowering of our cost structure, we are
increasing our 2015 production guidance, while reducing our
guidance for capital spending, operating and G&A costs," stated
Ian C. Dundas, President & CEO.
"As we look ahead into 2016, our focus is on sustainability. Our
2016 capital budget is down 30% from 2015, and we expect to operate
near or within funds flow. To further enhance the Company's
financial strength and sustainability in an extended low commodity
price environment, we are reducing our monthly dividend to
$0.03 per share from $0.05 per share, effective with our December 2015 dividend payment. While the
dividend remains an important part of our strategy, its reduction
reflects the need to rebalance the dividend level in the context of
lower commodity prices."
KEY TAKEAWAYS:
- Production was up 3% quarter over quarter averaging 110,794 BOE
per day primarily driven by growth in North Dakota oil production, which increased
over 20% from the second quarter of 2015 as a result of continued
strong well performance and higher activity levels in the second
and third quarters.
- Natural gas production was approximately 365 MMcf per day,
slightly lower than the second quarter. Continued outperformance in
the Marcellus was offset by a decrease in Canadian deep gas
production as a result of scheduled turnarounds at major
facilities. Overall, crude oil and natural gas liquids production
increased to approximately 50,000 barrels per day during the
quarter, up 8% over the previous quarter. Looking forward, we
expect fourth quarter oil production to be lower than the third
quarter as a result of both reduced on-stream activity in
North Dakota and divestments.
- Subsequent to the quarter, we entered into an agreement to sell
a portion of our non-operated North
Dakota properties for proceeds of $80
million. This accretive divestment allows us to increase our
focus on our operated North Dakota
acreage where we can better align our financial and operational
objectives. The divestment includes less than 2% of our overall
North Dakota acreage. Estimated
2016 production from the existing wells within these properties is
1,000 BOE per day. The transaction is expected to close in the
fourth quarter of 2015. We also divested of some minor non-core
Canadian oil properties during the quarter, with associated
production of 150 BOE per day, for proceeds of approximately
$12 million.
- As a result of the strong production performance year to date,
we are increasing our 2015 annual average production guidance to
106,000 BOE per day (from 100,000 – 104,000 BOE per day), with
approximately 46,000 barrels per day of crude oil and natural gas
liquids (from 44,000 – 46,000 barrels per day). This increased
guidance assumes our non-operated North
Dakota divestment closes in the fourth quarter of 2015.
- To enhance the Company's financial strength and sustainability
in an extended low commodity price environment, the Board of
Directors of Enerplus has approved a reduction in the monthly
dividend to $0.03 per share from
$0.05 per share, effective with the
December 2015 dividend payment.
- Funds flow was $121 million in
the third quarter, down approximately 25% from the previous
quarter, primarily due to the decline in crude oil prices in the
period.
- Capital spending was $89 million
in the third quarter, down from $148
million in the second quarter. Capital was focused on our
crude oil projects, with over 90% of spending directed to
North Dakota and our Canadian
waterflood assets. Due to continued cost improvement, strong
operational performance, and the deferral of spending into 2016 we
have reduced our annual 2015 capital spending to $510 million (from $540
million).
- Operating costs during the quarter were $8.87 per BOE, below our annual guidance of
$9.25 per BOE. As expected, we saw an
increase in operating costs from the second quarter as a result of
seasonal turnaround activity. Third quarter cash G&A costs were
$2.24 per BOE, in line with our
annual guidance, despite one-time severance charges related to
staff reductions that were incurred in the quarter. With the
continued improvement in our cost structures and increased
production guidance, we are decreasing our 2015 annual operating
cost guidance to $9.00 per BOE and
our cash G&A expense guidance to $2.20 per BOE.
- We incurred a non-cash asset impairment charge in the quarter
of $321 million (before tax). Under
U.S. GAAP we are required to use twelve month trailing average
prices to determine impairment, and consequently the impairment
reflects the low commodity prices in the fourth quarter of 2014 and
the first three quarters of 2015.
- We ended the third quarter with a debt to funds flow ratio of
2.0 times and senior debt to EBITDA ratio of 1.8 times. Subsequent
to the quarter, we paid the final installment of US$10.8 million on our maturing US$54 million senior notes. We have no additional
scheduled debt repayments until June of 2017.
- At September 30, 2015 we were
approximately 11% drawn on our covenant based $1.0 billion bank credit facility. Subsequent to
the quarter, we completed a one year extension of our bank credit
facility with our lending syndicate, which now matures in
October 2018. After confirming with
our syndicate banks that we could have maintained the facility at
its current level, we chose to decrease the facility limit to
$800 million as part of our ongoing
cost savings initiatives. This decision balances the need for
sufficient liquidity for the execution of our business plan against
the associated costs of retaining a largely undrawn bank facility.
We expect to realize savings of approximately $1 million as a result of the decreased facility
size. At the end of 2015, we expect to be approximately 10% drawn
on the resized facility.
Asset Activity
Production from North Dakota in
the quarter was up over 20% from the previous quarter, averaging
32,600 BOE per day. We drilled 3.8 net wells in Fort Berthold
with 6.5 net wells brought on-stream during the quarter for a total
capital investment of $58
million. The growth in production is a result of
continued strong well performance and an increase in on-stream
activity during the second and third quarters. Our operated
well completions activity was focused in the southeast area of our
Fort Berthold acreage and included wells in both the Bakken and
Three Forks formations. The wells were completed using a
modified high volume completion design, and produced at an average
initial 30 day production rate (IP30) of over 1,600 BOE per day,
outperforming expectations. Well costs continue to trend
down, with average well costs in the quarter, including facilities
costs, of just under US$10
million. We continue to run a one-rig drilling program
and, having deferred some completion activity into 2016, expect to
have an inventory of approximately 10 drilled uncompleted wells at
the end of 2015.
We continue to see reduced activity levels in the
Marcellus. During the third quarter, our capital spending in
the Marcellus was $3 million with 0.7
net wells drilled and 0.5 net wells brought on-stream.
Despite the low capital investment, strong well performance led to
a 5% production increase, to 210 MMcf per day, over the previous
quarter.
In Canada, following the
commercial success of the polymer pilot project at our Medicine Hat
Glauc 'C' waterflood asset, we have sanctioned the installation of
a second skid for our next polymer project. Construction of
the project was completed in October on budget and on
schedule. Polymer injection commenced in late October.
Production and Capital Spending
|
Three months ended
September 30, 2015
|
Nine months ended
September 30, 2015
|
Crude Oil & NGLs (bbls/day)
|
Average Production
Volumes
|
Capital Spending
($ millions)
|
Average Production
Volumes
|
Capital Spending
($ millions)
|
Canada
|
16,209
|
23.9
|
17,702
|
91.9
|
United States
|
33,740
|
58.6
|
28,759
|
252.9
|
Total Crude Oil & NGLs
(bbls/day)
|
49,949
|
82.5
|
46,461
|
344.8
|
Natural Gas (Mcf/day)
|
|
|
|
|
Canada
|
131,644
|
3.1
|
137,270
|
30.6
|
United States
|
233,427
|
3.3
|
222,341
|
28.5
|
Total Natural Gas (Mcf/day)
|
365,071
|
6.4
|
359,611
|
59.1
|
Company Total (BOE/day)
|
110,794
|
88.9
|
106,396
|
403.9
|
Net Drilling Activity*** – for the three months ended
September 30, 2015
|
Crude Oil
|
Wells
Drilled
|
Wells Pending
Completion/
Tie-in *
|
Wells
On-stream**
|
Dry & Abandoned
Wells
|
Canada
|
3.0
|
2.0
|
2.0
|
-
|
United States
|
3.8
|
3.8
|
6.5
|
-
|
Total Crude Oil
|
6.8
|
5.8
|
8.5
|
-
|
Natural Gas
|
|
|
|
|
Canada
|
0.6
|
-
|
2.3
|
-
|
United States
|
0.7
|
0.7
|
0.5
|
-
|
Total Natural Gas
|
1.3
|
0.7
|
2.8
|
-
|
Company Total
|
8.0
|
6.4
|
11.3
|
-
|
*Wells drilled during the quarter pending potential
completion/tie-in or abandonment as at June 30,
2015.
|
**Total wells brought on-stream during the quarter
regardless of when they were drilled.
|
***
Table may not add due to rounding.
|
Crude Oil & Natural Gas Pricing
The West Texas Intermediate (WTI) benchmark price for crude oil
fell by 20% versus the previous quarter to average US$46.43 per barrel during the third quarter.
Although our U.S. Bakken crude oil differentials narrowed in the
third quarter, the weakness in WTI prices resulted in a 17%
reduction in the selling price for our crude oil compared to the
previous quarter.
Natural gas prices at AECO and NYMEX were slightly stronger
during the third quarter, both averaging 5% higher than the
previous quarter. However, strong production levels and significant
maintenance activities on the two major pipelines running through
Northeast Pennsylvania contributed
to the continued weakness in regional Marcellus pricing during the
quarter, offsetting the strength in AECO and NYMEX on our realized
natural gas price.
Marcellus basis differentials to NYMEX averaged US$1.64 per Mcf in the quarter. Basis
differentials have improved recently in the region, with spot price
differentials in the Marcellus trading between US$1.00 per Mcf to US$1.50 per Mcf below NYMEX, due to lower NYMEX
prices and the recent tie-in of new regional export pipeline
capacity.
Our commodity price hedge position is largely unchanged from the
previous quarter. For the fourth quarter of 2015, we have an
average of 14,500 barrels per day of crude oil (approximately 45%
of our expected crude oil production, net of royalties) hedged at
an average floor price of US$79.47
per barrel through a combination of swaps and three-way collar
structures. In 2016 we have an average of 11,000 barrels per day of
crude oil (approximately 34% of our expected crude oil production,
net of royalties) hedged at an average floor price of US$64.35 per barrel through a combination of
swaps and three-way collar structures.
Under our gas hedging program, for the fourth quarter of 2015 we
are swapped on an average of 101,739 Mcf per day against NYMEX
(approximately 36% of our forecasted natural gas production, net of
royalties) at an average price of US$3.97 per Mcf. In 2016 we have 25,000 Mcf per
day (approximately 9% of our forecasted natural gas production, net
of royalties) hedged through three-way collars with an average
floor price of US$3.00 per Mcf.
2015 Revised Guidance
We have increased our annual production guidance, reduced our
capital spending guidance and decreased our operating cost and
G&A expense guidance. All other guidance remains
unchanged. This increased guidance assumes the divestment of
a portion of our non-operated North
Dakota property closes in the fourth quarter of 2015.
Summary of 2015 Expectations
|
Target
|
Capital spending
|
$510 million (from $540 million)
|
Average annual production
|
106,000 BOE/day (from 100,000 – 104,000
BOE/day)
|
Crude oil & NGL volumes
|
46,000 bbls/day (from 44,000 - 46,000
bbls/day)
|
Average royalty and production tax rate (% of gross
sales, before transportation)
|
21%
|
Operating expenses
|
$9.00/BOE (from $9.25/BOE)
|
Transportation costs
|
$3.00/BOE
|
Cash G&A expenses
|
$2.20/BOE (from $2.25/BOE)
|
2016 Outlook
Our 2016 budget is focused on sustainability. Based on our
continued operational success and improving capital efficiencies,
we expect 2016 production to be relatively flat to 2015, despite
our announced divestments, with capital spending levels
significantly below those of 2015.
We have based our 2016 budget on commodity prices of
US$50 per barrel WTI and US$3.00 per Mcf NYMEX. Under these
assumptions, and including the proceeds of our fourth quarter
divestment, we expect our capital expenditures and dividend
payments to be fully funded.
Our 2016 capital budget is $350
million (down approximately 30% from 2015), with production
of 100,000 – 105,000 BOE per day, including crude oil and natural
gas liquids of 44,000 - 47,000 barrels per day. Our expected
capital allocation will be heavily weighted to our crude oil
properties at approximately 90% due to the stronger associated
netback. We are maintaining flexibility to adjust capital
spending based on commodity prices.
Operating costs are expected to average $9.20 per BOE in 2016, a slight increase from
2015, primarily due to the impact of a weak Canadian dollar on our
U.S. dollar denominated operating costs. Our cash G&A
guidance is $1.90 per BOE, down
$0.30 per BOE from 2015 guidance as a
result of staffing reductions in 2015 and continued cost savings
initiatives.
2016 Guidance
Our 2016 guidance is based on the following assumptions:
US$50 per barrel WTI, NYMEX natural
gas of US$3.00 per Mcf, AECO natural
gas at $2.85 per GJ, and US/CDN
exchange of 1.33.
Summary of 2016 Expectations
|
Target
|
Capital spending
|
$350 million
|
Average annual production
|
100,000 – 105,000 BOE/day
|
Crude oil & NGLvolumes
|
44,000 – 47,000 bbls/day
|
Average royalty and production tax rate (% of gross
sales, before transportation)
|
22%
|
Operating expenses
|
$9.20/BOE
|
Transportation costs
|
$3.00/BOE
|
Cash G&A expenses
|
$1.90/BOE
|
|
|
|
|
2016 Capital Allocation
|
$ million
|
U.S. Oil
|
$240
|
Canadian Oil
|
$70
|
Canadian Natural Gas (Deep Basin)
|
$20
|
U.S. Natural Gas (Marcellus)
|
$20
|
|
|
|
|
2016 Differential/Basis
Outlook*
|
|
U.S. Bakken (compared to WTI crude
oil)
|
US$(8.00) per barrel
|
Marcellus Basis (compared to NYMEX natural
gas)
|
US$(1.25) per Mcf
|
*Before field transportation costs
SELECTED FINANCIAL RESULTS
|
Three months ended
September 30,
|
Nine months ended
September 30,
|
|
2015
|
2014
|
2015
|
2014
|
Financial (000's)
|
|
|
|
|
Funds Flow(4)
|
$ 120,845
|
$ 212,779
|
$ 390,427
|
$ 646,502
|
Cash and Stock Dividends
|
30,944
|
55,438
|
109,238
|
165,587
|
Net Income/(Loss)
|
(292,666)
|
67,430
|
(898,416)
|
147,424
|
Debt Outstanding – net of cash
|
1,226,552
|
1,091,110
|
1,226,552
|
1,091,110
|
Capital Spending
|
88,923
|
207,838
|
403,913
|
630,027
|
Property and Land Acquisitions
|
2,005
|
3,986
|
758
|
17,186
|
Property Divestments
|
11,865
|
68,931
|
203,378
|
185,631
|
Debt to Funds Flow
Ratio(4)
|
2.0x
|
1.3x
|
2.0x
|
1.3x
|
|
|
|
|
|
Financial per Weighted Average Shares
Outstanding
|
|
|
|
|
Funds Flow
|
$
0.58
|
$ 1.04
|
$
1.89
|
$
3.17
|
Net Income/(Loss) (Basic)
|
(1.42)
|
0.33
|
(4.36)
|
0.72
|
Weighted Average Number of Shares Outstanding
(000's)
|
206,243
|
205,164
|
206,100
|
204,174
|
|
|
|
|
|
Selected Financial Results per
BOE(1)(2)
|
|
|
|
|
Oil & Natural Gas
Sales(3)
|
$ 27.04
|
$
47.67
|
$
28.17
|
$ 52.13
|
Royalties and Production Taxes
|
(6.01)
|
(10.36)
|
(5.93)
|
(11.31)
|
Commodity Derivative Instruments
|
5.31
|
(0.26)
|
7.36
|
(1.52)
|
Cash Operating Expenses
|
(8.69)
|
(9.29)
|
(8.77)
|
(9.14)
|
Transportation Costs
|
(3.03)
|
(2.92)
|
(2.94)
|
(2.61)
|
General and Administrative
|
(2.24)
|
(1.97)
|
(2.21)
|
(2.08)
|
Cash Share-Based Compensation
|
0.35
|
0.54
|
(0.08)
|
(0.44)
|
Interest, Foreign Exchange and Other
Expenses
|
(2.47)
|
(1.18)
|
(2.72)
|
(1.48)
|
Taxes
|
1.59
|
-
|
0.56
|
(0.40)
|
Funds Flow
|
$ 11.85
|
$
22.23
|
$
13.44
|
$
23.15
|
SELECTED OPERATING RESULTS
|
Three months ended September
30,
|
Nine months ended September 30,
|
|
2015
|
2014
|
2015
|
2014
|
Average Daily
Production(2)
|
|
|
|
|
Crude Oil (bbls/day)
|
44,888
|
40,332
|
41,809
|
39,328
|
Natural Gas Liquids (bbls/day)
|
5,061
|
3,869
|
4,652
|
3,591
|
Natural Gas (Mcf/day)
|
365,071
|
359,007
|
359,611
|
356,288
|
Total (BOE/day)
|
110,794
|
104,035
|
106,396
|
102,300
|
|
|
|
|
|
% Crude Oil and Natural Gas Liquids
|
45%
|
42%
|
44%
|
42%
|
|
|
|
|
|
Average Selling Price
(2)(3)
|
|
|
|
|
Crude Oil (per bbl)
|
$
48.22
|
$ 88.28
|
$ 50.21
|
$ 92.55
|
Natural Gas Liquids (per bbl)
|
13.51
|
46.76
|
18.60
|
54.79
|
Natural Gas (per Mcf)
|
2.08
|
3.36
|
2.24
|
4.18
|
|
|
|
|
|
Net Wells Drilled
|
8
|
19
|
44
|
63
|
(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) Before transportation costs, royalties and
commodity derivative instruments.
|
(4) These non-GAAP measures may not be directly
comparable to similar measures presented by other entities. See
"Non-GAAP Measures" section in the following
MD&A.
|
|
Three months ended September
30,
|
Nine months ended September 30,
|
Average Benchmark Pricing
|
2015
|
2014
|
2015
|
2014
|
WTI Crude Oil (US$/bbl)
|
$
46.43
|
$
97.17
|
$
51.00
|
$
99.61
|
AECO – monthly index (CDN$/Mcf)
|
2.80
|
4.22
|
2.80
|
4.55
|
AECO – daily index (CDN$/Mcf)
|
2.90
|
4.02
|
2.77
|
4.81
|
NYMEX – last day (US$/Mcf)
|
2.77
|
4.06
|
2.80
|
4.55
|
US/CDN
exchange rate
|
1.31
|
1.09
|
1.26
|
1.09
|
Share Trading Summary
|
CDN* ERF
|
U.S.** - ERF
|
For the three months ended September 30,
2015
|
(CDN$)
|
(US$)
|
High
|
$ 10.93
|
$ 8.80
|
Low
|
$ 6.04
|
$ 4.54
|
Close
|
$ 6.50
|
$ 4.86
|
* TSX and other Canadian trading data
combined.
|
** NYSE and other U.S. trading data
combined.
|
2015 Dividends per Share
|
|
|
Payment Month
|
CDN$
|
US$(1)
|
First Quarter Total
|
$ 0.27
|
$ 0.22
|
Second Quarter Total
|
$ 0.15
|
$ 0.12
|
July
|
$ 0.05
|
$ 0.04
|
August
|
0.05
|
0.04
|
September
|
0.05
|
0.04
|
Third Quarter Total
|
$ 0.15
|
$ 0.12
|
Total Year-to-Date
|
$ 0.57
|
$ 0.46
|
(1) US$ dividends represent CDN$ dividends converted
at the relevant foreign exchange rate on the payment
date.
|
Outlook
We delivered another quarter of consistent operational execution
and disciplined capital spending which is underpinning the strength
of our business. Our assets are performing well and our costs
continue to decline. Our financial flexibility remains strong
and we will continue to focus on improving efficiencies and
sustainability as we move into 2016.
Importantly, despite the continued low commodity price
environment, we remain committed to ensuring safe, responsible and
sustainable operations across our business.
Q3 2015 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:
Date:
|
Friday, November 6, 2015
|
Time:
|
9:00 AM MT (11:00 AM ET)
|
Dial-In:
|
647-427-7450
|
|
888-231-8191 (toll free)
|
Audiocast:
http://event.on24.com/r.htm?e=1059283&s=1&k=4299D0FDEE63F7CD60E3097A62168840
|
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 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:
|
51232651
|
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.
Readers are cautioned that the average initial
production rates contained in this news release are not necessarily
indicative of long-term performance or of ultimate
recovery.
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",
"ongoing", "may", "will", "project", "should", "believe", "plans",
"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 2015 and 2016
average production volumes and the anticipated production mix; the
proportion of our anticipated oil and gas production that is hedged
and the effectiveness of such hedges in protecting our funds flow;
the results from our drilling program and the timing of related
production; oil and natural gas prices and differentials and our
commodity and foreign exchange risk management programs in 2015,
2016 and in the future; expectations regarding our realized oil and
natural gas prices; anticipated cash and non-cash G&A, share
based compensation and financing expenses; operating and
transportation costs; capital spending levels in 2015 and 2016,
anticipated drilling and completions program, and expected impact
on our production level; potential future asset impairments; future
debt and working capital levels and debt to funds flow ratio; our
future acquisitions and dispositions, including timing thereof and
expected proceeds therefrom; expectations regarding our measures to
preserve our financial strength, including effectiveness thereof
and amounts of anticipated savings therefrom; and the amount of
future cash dividends that we may pay to our
shareholders.
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; current commodity price and cost
assumptions; 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' reserves and resources volumes; the
continued availability of adequate debt and/or equity financing,
cash flow and other sources to fund Enerplus' capital and operating
requirements, and dividend payments as needed; availability of
third party services; and the extent of its liabilities. In
addition, our 2015 revised guidance is based on the following
assumptions: September 30, 2015
forward market WTI price of $49.68/bbl, NYMEX gas price of $2.75/Mcf, AECO gas price of $2.66/GJ and US/CDN exchange rate of 1.28. Our
2016 preliminary guidance is based on WTI price of US$50/bbl, NYMEX gas price of US$3.00/Mcf, an AECO gas price of $2.85/GJ and US/CDN exchange rate of 1.33.
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, including future decline, 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 Enerplus' capital spending activities or production
declines; curtailment of Enerplus' production due to low realized
prices or lack of adequate infrastructure; 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; our inability to comply with covenants under
our bank credit facility and senior notes; changes in estimates 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; failure to complete any
anticipated acquisitions or divestitures; 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 at December 31,
2014).
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 calculated as total
debt net of cash, divided by a trailing 12 months of funds flow. In
addition, "senior debt to EBITDA" is used to determine Enerplus'
compliance with financial covenants under its bank credit facility
and outstanding senior notes. Calculation of these terms is
described in our Third Quarter 2015 MD&A under the "Liquidity
and Capital Resources" section.
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" are useful supplemental measures as they
provide an indication of the results generated by Enerplus'
principal business activities. However, these measures, and "senior
debt to EBITDA" 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. For
reconciliation of these measures to the most directly comparable
measure calculated in accordance with U.S. GAAP, and further
information about these measures, see disclosure under "Non-GAAP
Measures" in our Third Quarter 2015 MD&A.
Electronic copies of our Third Quarter 2015 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.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation