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 Enerplus' First Quarter 2016
Financial Statements and MD&A are available on the Company's
website at www.enerplus.com, under its SEDAR profile at
www.sedar.com and on the EDGAR website at
www.sec.gov.
CALGARY, May 6, 2016 /CNW/ - Enerplus Corporation
("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to
announce its results from operations for the first quarter of
2016.
"We continue to position our company to deliver long-term
profitability in a lower commodity price environment. Our focus on
reducing costs and driving efficiencies across the organization has
resulted in a meaningful reduction to our cost structure. As a
result, we are reducing our combined operating, transportation and
G&A cost guidance by $1.30 per
BOE in 2016," stated Ian C.
Dundas, President & CEO. "In addition, we have been
delivering on our portfolio optimization objectives with non-core
divestments generating net proceeds of $188
million in the first quarter, further strengthening our
company's balance sheet. Operationally, our assets continue to
deliver strong results and we remain on track to achieve our
targets."
KEY TAKEAWAYS:
- Production averaged 97,860 BOE per day during the quarter,
including approximately 45,000 barrels per day of crude oil and
natural gas liquids. Total production was down 8% from the previous
quarter primarily as a result of non-core divestment activity
during the fourth quarter of 2015 and first quarter of 2016, in
which we divested properties with associated production of
approximately 9,100 BOE per day. The divested production was
approximately 90% natural gas weighted and, as a result, our crude
oil and natural gas liquids weighting increased to 46% in the first
quarter, from 43% in the previous quarter.
- We continued to see outperformance from our North Dakota wells along with strong
production results from our Canadian oil portfolio during the
quarter. As a result, and despite the previously announced second
quarter divestment of 2,300 BOE per day, we are maintaining our
2016 production guidance range of 90,000 to 94,000 BOE per day and
43,000 to 45,000 barrels per day of crude oil and natural gas
liquids.
- First quarter funds flow was $41.7
million ($0.20 per share),
down approximately 60% from the fourth quarter of 2015 as a result
of significantly lower crude oil and natural gas prices and lower
realized gains on crude oil and natural gas hedging contracts.
- We recorded a net loss of $173.7
million ($0.84 per share) in
the first quarter. Our first quarter earnings benefited from a
combined gain of $152.2 million on
property divestments and the repurchase of a portion of our
outstanding senior notes. These gains were offset by non-cash
charges of $304.7 million related to
asset impairment and a valuation allowance taken on our deferred
tax asset as a result of the decline in 12-month trailing average
commodity prices.
- Our focus on maintaining our balance sheet strength and
preserving the value of our high quality inventory during this
period of low commodity prices resulted in a 50% reduction in
capital spending from the fourth quarter of 2015, to $43.3 million. Capital spending was focused on
our crude oil properties with $19.8
million directed to North
Dakota and $19.1 million
directed to our Canadian oil portfolio. We continue to budget 2016
capital spending of $200 million,
with approximately 90% allocated to our crude oil plays (65%
North Dakota, 25% Canada).
- Our ongoing cost reduction efforts are delivering strong
results. First quarter operating expenses of $8.15 per BOE were 6% lower than the fourth
quarter of 2015 and 16% lower than the first quarter of 2015,
despite lower volumes. Based on cost savings to date, the
strengthening Canadian dollar relative to our U.S. dollar
denominated operating costs, and the previously announced
divestment of our higher cost northwest Alberta assets, we are reducing our 2016
guidance for operating expenses to $8.50 per BOE from $9.50 per BOE. We are also reducing our
transportation cost guidance to $3.10
per BOE from $3.30 per BOE as a
result of the strengthening Canadian dollar.
- Cash G&A expenses during the first quarter were
$2.07 per BOE, down 12% from the same
period in 2015 and up 18% from the fourth quarter of 2015 largely
due to severance payments incurred in the first quarter. As a
result of the reduction of our workforce to better align with our
more focused asset base and improved organizational efficiencies,
we are reducing our 2016 guidance for cash G&A expenses to
$2.00 per BOE from $2.10 per BOE.
- Overall, taking into account our reduced operating,
transportation and G&A expense guidance, we expect our 2016
cash costs to be approximately $1.30
per BOE lower than previously forecast.
- As previously announced, effective with the April 2016 payment, we reduced the monthly
dividend from $0.03 per share to
$0.01 per share. This reduction
reflected the need to rebalance the dividend level to better align
with reduced funds flow in the context of the sustained low
commodity price environment.
- We further strengthened our balance sheet during the first
quarter, ending the period with total debt, net of cash, of
$992.8 million compared to
$1,216.2 million at December 31, 2015. The $223 million reduction in total debt was a result
of applying divestment proceeds against outstanding debt combined
with the strengthening Canadian dollar relative to our U.S. dollar
denominated senior notes. Total debt was comprised of $844.5 million of senior notes and $149.6 million of bank indebtedness (19% drawn on
our $800 million facility) less
$1.3 million in cash. At
March 31, 2016, our senior debt to
EBITDA ratio was 1.6 times and our debt to funds flow ratio was 2.3
times.
- We had continued success in divesting non-core assets during
the quarter which provided net proceeds of approximately
$188 million. These proceeds, along
with our largely undrawn bank credit facility, were used to fund
the repurchase of US$172 million of
our senior notes during the quarter, and a total of US$267 million of senior notes to date. The
repurchases were completed at prices ranging from 90% of par to par
value, with no penalty or make-whole payments required, resulting
in a total gain of $19 million. As a
result of replacing fixed term, higher interest rate senior debt
with lower interest rate bank debt and using divestment proceeds to
repay outstanding debt, we expect to save approximately
US$13 million in interest expense on
an annualized basis. Utilizing a portion of our bank credit
facility in place of the senior notes provides additional
flexibility within our capital structure to reduce our leverage
further as cash becomes available.
- Subsequent to the quarter, we announced an additional non-core
divestment of certain assets located in northwest Alberta for proceeds of $95.5 million, subject to closing adjustments.
Expected annual average 2016 production associated with these
assets is approximately 2,300 BOE per day (50% natural gas). This
divestment is expected to close in the second quarter of 2016 and
we expect to realize a gain of approximately $70 million as a result of the sale. Upon
closing, this will bring total 2016 divestment proceeds to
$283 million.
- In connection with our non-core assets sales, we have
materially reduced the Company's future abandonment liabilities.
Since the start of 2015, we have reduced our asset retirement
obligations by over 30%.
ASSET ACTIVITY
North Dakota
North Dakota production
averaged 29,200 BOE per day during the first quarter, largely flat
from the previous quarter and up 36% from the same period in 2015.
We spent $19.8 million in
North Dakota in the quarter
drilling 4.4 net wells and bringing 2.5 net wells on-stream. Our
well performance continues to be strong, with the two operated
on-stream wells in the quarter delivering initial 30-day production
rates of 1,990 and 1,750 BOE per day. Subsequent to the quarter,
two further wells were brought on-stream that have averaged in
excess of 2,000 BOE per day in the first 30 days of production.
Well costs continue to trend down due to reduced drilling days,
completions optimization and changes to facilities design. Our
total drilling, completion, tie-in and facilities costs are
currently US$8.5 million, down
approximately 35% from 2014 levels.
We continue to run a single drilling rig in North Dakota given the sustained low commodity
price environment but retain the flexibility to increase activity
quickly given our inventory of drilled uncompleted wells, which
stood at approximately 11 at the end of the first quarter. Our 2016
capital program is primarily focused in North Dakota, where we expect to spend
approximately $130 million during the
full year 2016, keeping North
Dakota production largely flat.
Canada
Total production from Canada
averaged 32,590 BOE per day during the quarter. Activity was
focused on our waterflood assets at Cadogan, Giltedge and southeast
Saskatchewan, where we drilled 4
producers and 3 injector wells. Results from the program have
exceeded expectations with the wells producing at, or above, our
type curve forecast. Production from the waterflood assets averaged
17,500 BOE per day during the quarter. Activity in Canada during the rest of 2016 will be largely
focused on performance and cost optimization work.
Marcellus
Marcellus production averaged 190 MMcf per day during the first
quarter, down approximately 7% from the previous quarter due to
continued low levels of activity as a result of weak regional
natural gas pricing. Capital spending in the quarter was
$3.5 million, with 1.3 net wells
brought on-stream. We continue to plan for modest levels of
activity in the Marcellus, forecasting full year 2016 spending of
$20 million, a reduction of
approximately 37% from 2015 spending.
Production and Capital Spending(1)
|
Three months
ended
March 31,
2016
|
Crude Oil &
NGLs (bbls/day)
|
Average
Production
Volumes
|
Capital
Spending
($ millions)
|
Canada
|
15,990
|
$19.1
|
United
States
|
29,012
|
$20.7
|
Total Crude Oil
& NGLs (bbls/day)
|
45,002
|
$39.8
|
Natural Gas
(Mcf/day)
|
|
|
Canada
|
99,539
|
-
|
United
States
|
217,611
|
$3.5
|
Total Natural Gas
(Mcf/day)
|
317,150
|
$3.5
|
Company Total
(BOE/day)
|
97,860
|
$43.3
|
(1) Table may not add
due to rounding
|
|
|
NET DRILLING
ACTIVITY(1)– for the three months ended March 31,
2016
|
|
|
Crude
Oil
|
Wells
Drilled
|
Wells
On-stream
|
Canada
|
7.0
|
6.0
|
United
States
|
4.4
|
2.5
|
Total Crude
Oil
|
11.4
|
8.5
|
Natural
Gas
|
|
|
Canada
|
-
|
-
|
United
States
|
0.1
|
1.3
|
Total Natural
Gas
|
0.1
|
1.3
|
Company
Total
|
11.5
|
9.8
|
(1) Table may not add
due to rounding
|
CRUDE OIL & NATURAL GAS PRICING
The WTI benchmark crude oil price fell by 21% versus the
previous quarter as seasonal refinery outages combined with
continued oversupply drove U.S. oil inventories to near-maximum
levels. This supply imbalance pushed WTI prices to a low of
US$26.05 per barrel in February
before improving by the end of the quarter as refinery demand
returned and there were growing indications of supply declines in
North America and elsewhere.
Modestly weaker crude oil differentials in both Canada and the U.S. also contributed to the
weakness in realized oil prices during the quarter. Our average
Bakken realized crude oil price differential was US$8.38 per barrel below WTI in the quarter.
NYMEX natural gas prices fell by 8% and AECO monthly prices fell
by approximately 20% compared to the previous quarter. Both markets
remained weak in response to continued high production with lower
than normal seasonal demand that resulted in significant storage
surpluses across North America
relative to the first quarter of 2015.
Our overall realized natural gas price outperformed changes in
NYMEX and AECO prices due to improving differentials in the
Marcellus. Weaker NYMEX prices narrowed Marcellus benchmark
differentials, resulting in an average Marcellus realized price
differential of US$0.91 per Mcf below
NYMEX, a 19% improvement from the previous quarter. We continue to
expect our realized Marcellus differentials in 2016 to improve
relative to recent years due to reduced industry spend and the
continued build out of regional take-away capacity.
RISK MANAGEMENT
We continue to protect a portion of our funds flow through
commodity hedging and have added additional price protection on
both our crude oil and natural gas production in 2017. Currently,
we have a combination of swaps and collars in 2016 and 2017
covering approximately 31% and 20% respectively, of forecast net
oil production, after royalties. For natural gas, we have a
combination of swaps and collars in 2016 and 2017 covering
approximately 31% and 16% respectively, of forecast net natural gas
production, after royalties.
Commodity Hedging Detail (as at May 2,
2016)
|
|
|
|
|
|
|
|
|
Crude
Oil
(US$/bbl)(1)
|
|
|
NYMEX
Natural
Gas
(US$/Mcf)(1)
|
|
|
Apr 1, 2016
–
Jun 30, 2016
|
Jul 1, 2016
–
Dec 31, 2016
|
Jan 1, 2017
–
Dec 31, 2017
|
Apr 1, 2016
–
Oct 31, 2016
|
Nov 1, 2016
–
Dec 31, 2016
|
Jan 1, 2017
–
Dec 31, 2017
|
Swaps
|
|
|
|
|
|
|
Sold Swaps
|
$64.28
|
-
|
-
|
$2.53
|
$2.48
|
-
|
Volume (bbl/d or
Mcf/d)
|
3,000
|
-
|
-
|
50,000
|
25,000
|
-
|
% of net
production
|
10%
|
-
|
-
|
23%
|
11%
|
-
|
|
|
|
|
|
|
|
3 Way Collars
|
|
|
|
|
|
|
Sold Puts
|
$50.13
|
$49.78
|
$35.67
|
$2.50
|
$2.50
|
$2.00
|
Volume (bbl/d or
Mcf/d)
|
8,000
|
8,000
|
6,000
|
25,000
|
25,000
|
35,000
|
% of net
production
|
26%
|
26%
|
20%
|
11%
|
11%
|
16%
|
|
|
|
|
|
|
|
Purchased
Puts
|
$64.38
|
$63.98
|
$48.18
|
$3.00
|
$3.00
|
$2.67
|
Volume (bbl/d or
Mcf/d)
|
8,000
|
8,000
|
6,000
|
25,000
|
25,000
|
35,000
|
% of net
production
|
26%
|
26%
|
20%
|
11%
|
11%
|
16%
|
|
|
|
|
|
|
|
Sold Calls
|
$79.38
|
$79.63
|
$60.00
|
$3.75
|
$3.75
|
$3.32
|
Volume (bbl/d or
Mcf/d)
|
8,000
|
8,000
|
6,000
|
25,000
|
25,000
|
35,000
|
% of net
production
|
26%
|
26%
|
20%
|
11%
|
11%
|
16%
|
|
|
|
|
|
|
|
Collars
|
|
|
|
|
|
|
Purchased
Puts
|
$33.41
|
-
|
-
|
-
|
-
|
-
|
Volume (bbl/d or
Mcf/d)
|
1,670
|
-
|
-
|
-
|
-
|
-
|
% of net
production
|
5%
|
-
|
-
|
-
|
-
|
-
|
|
|
|
|
|
|
|
Sold Puts
|
$41.75
|
-
|
-
|
-
|
-
|
-
|
Volume (bbl/d or
Mcf/d)
|
1,670
|
-
|
-
|
-
|
-
|
-
|
% of net
production
|
5%
|
-
|
-
|
-
|
-
|
-
|
(1) Based on weighted
average price (before premiums), assuming average annual production
of 92,000 BOE/day for 2016 and 2017, less royalties
and production taxes of 23% in
aggregate
|
2016 REVISED GUIDANCE
We have revised our full year 2016 guidance as a result of
further reductions to our cost structure related to operating,
transportation and G&A expenses. Capital spending and
production guidance remain unchanged. The revised guidance
considers the announced divestment of our northwest Alberta assets expected to close during the
second quarter.
Summary of 2016
Expectations
|
Revised
Guidance
|
Original
Guidance
|
Capital
spending
|
$200
million
|
$200
million
|
Average annual
production
|
90,000 – 94,000
BOE/day
|
90,000 – 94,000
BOE/day
|
Crude oil and natural
gas liquids volumes
|
43,000 – 45,000
BOE/day
|
43,000 – 45,000
BOE/day
|
Average royalty and
production tax rate
|
23%
|
23%
|
Operating
expenses
|
$8.50/BOE
|
$9.50/BOE
|
Transportation
expense
|
$3.10/BOE
|
$3.30/BOE
|
Cash G&A
expenses
|
$2.00/BOE
|
$2.10/BOE
|
Q1 2016 CONFERENCE CALL DETAILS
A conference call hosted by Ian C.
Dundas, President and CEO will be held at 8:00AM MT (10:00AM
ET) today to discuss these results. Details of the
conference call are as follows:
Date:
|
Friday, May 6,
2016
|
Time:
|
8:00 AM MT (10:00 AM
ET)
|
Dial-In:
|
647-427-7450
|
|
888-231-8191 (toll
free)
|
Audiocast:
|
http://event.on24.com/r.htm?e=1169442&s=1&k=DB13444A94245E531DE0286BB7C8AC04
|
|
|
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:
|
86983471
|
|
|
SELECTED FINANCIAL RESULTS
|
Three months ended
March 31,
|
|
2016
|
2015
|
Financial
(000's)
|
|
|
Funds
Flow(4)
|
$
|
41,727
|
$
|
109,164
|
Dividends to
Shareholders
|
14,464
|
47,359
|
Net
Income/(Loss)
|
(173,666)
|
(293,206)
|
Debt Outstanding -
net of cash
|
992,837
|
1,272,204
|
Capital
Spending
|
43,276
|
167,011
|
Property and Land
Acquisitions
|
3,554
|
(236)
|
Property
Divestments
|
187,768
|
3,712
|
Debt to Funds Flow
Ratio(4)
|
2.3x
|
1.7x
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
Funds
Flow
|
$
|
0.20
|
$
|
0.53
|
Net
Income/(Loss)
|
(0.84)
|
(1.42)
|
Weighted Average
Number of Shares Outstanding (000's)
|
206,716
|
205,845
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
Oil & Natural Gas
Sales(3)
|
$
|
19.14
|
$
|
26.89
|
Royalties and
Production Taxes
|
(3.95)
|
(5.50)
|
Commodity Derivative
Instruments
|
4.45
|
9.56
|
Cash Operating
Expenses
|
(8.12)
|
(9.56)
|
Transportation
Costs
|
(2.89)
|
(2.92)
|
General and
Administrative Expenses
|
(2.07)
|
(2.36)
|
Cash Share-Based
Compensation
|
(0.08)
|
(0.80)
|
Interest, Foreign
Exchange and Other Expenses
|
(1.81)
|
(3.28)
|
Current Income Tax
Recovery
|
0.02
|
-
|
Funds Flow
|
$
|
4.69
|
$
|
12.03
|
SELECTED OPERATING RESULTS
|
Three months ended
March 31,
|
|
2016
|
2015
|
Average Daily
Production(2)
|
|
|
Crude Oil
(bbls/day)
|
39,508
|
39,355
|
Natural Gas Liquids
(bbls/day)
|
5,494
|
3,735
|
Natural Gas
(Mcf/day)
|
317,150
|
346,589
|
Total
(BOE/day)
|
97,860
|
100,855
|
|
|
|
% Crude Oil &
Natural Gas Liquids
|
46%
|
43%
|
|
|
|
Average Selling
Price (2)(3)
|
|
|
Crude Oil (per
bbl)
|
$
|
31.59
|
$
|
44.04
|
Natural Gas Liquids
(per bbl)
|
11.34
|
22.48
|
Natural Gas (per
Mcf)
|
1.77
|
2.58
|
|
|
|
Net Wells
drilled
|
11
|
28
|
(1)
|
Non-cash amounts have
been excluded.
|
(2)
|
Based on Company
interest production volumes. See "Basis of Presentation" section in
the First Quarter 2016 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
First Quarter 2016 MD&A.
|
|
Three months ended
March 31,
|
|
Average Benchmark
Pricing
|
2016
|
2015
|
|
WTI crude oil
(US$/bbl)
|
$
|
33.45
|
$
|
48.64
|
|
AECO natural gas –
monthly index (CDN$/Mcf)
|
2.11
|
2.95
|
|
AECO natural gas –
daily index (CDN$/Mcf)
|
1.83
|
2.75
|
|
NYMEX natural gas –
last day (US$/Mcf)
|
2.09
|
2.98
|
|
USD/CDN exchange
rate
|
1.37
|
1.24
|
|
Share Trading
Summary
|
|
CDN*
ERF
|
U.S.** -
ERF
|
For the three
months ended March 31, 2016
|
|
(CDN$)
|
(US$)
|
High
|
|
|
$
|
5.37
|
$
|
4.03
|
Low
|
|
|
$
|
2.68
|
$
|
1.84
|
Close
|
|
|
$
|
5.09
|
$
|
3.93
|
* TSX and other
Canadian trading data combined.
|
|
|
|
|
|
** NYSE and other
U.S. trading data combined.
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 Dividends per
Share
|
|
|
|
|
|
|
Payment
Month
|
|
CDN$
|
US$(1)
|
January
|
|
$
|
0.03
|
$
|
0.02
|
February
|
0.03
|
0.02
|
March
|
0.03
|
0.02
|
First Quarter
Total
|
|
$
|
0.09
|
$
|
0.06
|
(1) US$ dividends
represent CDN$ dividends converted at the relevant foreign exchange
rate on the payment date.
|
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 its Canadian peer companies, the summary results
contained within this news release presents Enerplus' 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 2016 average
production volumes and the anticipated production mix; the
proportion of anticipated oil and gas production that is hedged and
the effectiveness of such hedges in protecting funds flow; the
results from drilling programs and the timing of related
production; oil and natural gas prices and differentials and
commodity and foreign exchange risk management programs in 2016 and
in the future; expectations regarding 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 2016, anticipated drilling and
completions program, and the expected impact on production levels;
potential future asset impairments; future debt and working capital
levels and debt to funds flow ratios; future acquisitions and
dispositions, including timing thereof, production and reduction of
asset retirement obligations associated therewith and expected
proceeds therefrom; expected gains in respect to our repurchase of
a portion of senior notes and asset divestments; anticipated amount
of interest expense savings in respect to our repurchase of senior
notes; expectations regarding measures to preserve financial
strength, including effectiveness thereof and amounts of
anticipated savings therefrom; and the amount of future cash
dividends that may be paid to 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, Enerplus' 2016 revised guidance is based on the following
assumptions: WTI of US$42.38/bbl,
NYMEX gas price of US$2.28/Mcf, and
AECO gas price of $1.72/GJ, and
USD/CDN exchange rate of 1.29. 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; Enerplus' inability to comply with covenants under
its 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 its AIF
and Form 40-F at December 31,
2015).
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 Enerplus Corporation's First Quarter 2016 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 Enerplus'
First Quarter 2016 MD&A.
Electronic copies of Enerplus Corporation's First Quarter 2016
MD&A and Financial Statements, along with other public
information including investor presentations, are available on its
website at www.enerplus.com. Shareholders may, upon request,
receive a printed copy of our audited financial statements at any
time. Follow @EnerplusCorp on Twitter at
https://twitter.com/EnerplusCorp.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation