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 First 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, May 8, 2015 /CNW/ - Enerplus Corporation
("Enerplus") (TSX: ERF) (NYSE: ERF) announces the results from
operations for the first quarter 2015.
HIGHLIGHTS:
- Enerplus delivered strong operating results and continued to
demonstrate prudent financial stewardship through a focus on
disciplined capital allocation and cost control. We are well
positioned to achieve our key operating targets in 2015 and remain
in a strong financial position as we navigate through a challenging
commodity price environment.
- Production averaged approximately 100,900 BOE per day, down 4%
quarter-over-quarter in response to reduced capital spending and
deferred activity. Crude oil and natural gas liquids accounted for
43% of first quarter volumes, which was in line with our
expectations. Well completion activity in North Dakota was deferred from December until
late February in response to low oil prices and cost
uncertainty.
- With prices stabilizing and improved cost structures, we plan
to accelerate second quarter well completions in North Dakota and re-establish growth in the
region. Given the solid momentum going into the second quarter, in
part based upon strong well performance in North Dakota, we are well positioned to
achieve our annual average production guidance of 93,000 - 100,000
BOE per day and liquids guidance of 42-44% despite the previously
announced sale of non-core oil producing assets.
- Significant declines in commodity prices resulted in first
quarter funds flow of $109 million
compared to $213 million in the
fourth quarter of 2014. The West Texas Intermediate benchmark price
for crude oil averaged US$48.64 per
barrel during the quarter, down from approximately US$73 per barrel during the previous quarter.
AECO and NYMEX gas prices were sharply lower quarter-over-quarter,
both falling by 26%. Although supported by our strong commodity
hedge position, funds flow over the quarter was impacted by
one-time charges of $11 million and
realized losses on our foreign exchange revenue hedges of
$8.6 million. Funds flow was also
impacted by our decision to delay completion activity in
North Dakota until late
February.
- We reported a net loss of $293
million for the quarter as we incurred a non-cash asset
impairment charge of $268 million.
Under U.S. GAAP we are required to use twelve month trailing
average prices to determine impairment and consequently the
impairment reflects the low oil prices in the fourth quarter of
2014 and the first quarter of 2015.
- Capital spending during the quarter was $167 million and remains on track with our full
year capital program. We directed the majority of capital to our
North Dakota, Wilrich and Canadian
crude oil properties. In total, we drilled 27.9 net wells and
brought 17.4 net wells on-stream across our portfolio in the first
quarter.
- Both our operating and G&A costs came in under expectations
during the quarter at $11.03 per BOE
and $2.36 per BOE respectively.
Operating costs excluding Marcellus gathering fees were
$9.66 per BOE during the quarter.
Further information on our treatment of Marcellus gathering fees is
provided in the first quarter 2015 Management's Discussion and
Analysis.
- Our focus on cost efficiencies, the deferral of activity and
our strong hedge position continue to help preserve our financial
flexibility for 2015. We ended the quarter with a debt to funds
flow ratio of 1.7 times, up from 1.3 times at year-end 2014. We
reduced our dividend by 44% to $0.05
per share effective with the April payment as we believe this is a
more appropriate level in the context of current commodity prices.
Subsequent to the quarter, our previously announced non-core asset
sales closed generating proceeds of $186
million. These proceeds were used to repay the debt
outstanding on our $1 billion bank
credit facility, which is essentially undrawn following these
divestments.
"We achieved strong operating performance despite a challenging
environment. Our focus on disciplined capital allocation and a
commitment to a strong balance sheet has positioned us with
significant financial flexibility in this market. We remain well
positioned to achieve our 2015 targets," said Ian Dundas, President & CEO.
SELECTED FINANCIAL RESULTS
|
|
|
|
|
Three months ended March 31,
|
|
|
2015
|
|
2014
|
Financial (000's)
|
|
|
|
|
Funds Flow
|
$
|
109,164
|
$
|
220,512
|
Cash and Stock
Dividends
|
|
47,359
|
|
54,935
|
Net
Income/(Loss)
|
|
(293,206)
|
|
40,037
|
Debt Outstanding -
net of cash
|
|
1,272,204
|
|
1,020,720
|
Capital
Spending
|
|
167,011
|
|
217,763
|
Property and Land
Acquisitions
|
|
(236)
|
|
9,969
|
Property
Divestments
|
|
3,712
|
|
117,225
|
Debt to Trailing
12-Month Funds Flow
|
|
1.7x
|
|
1.3x
|
|
|
|
|
|
Financial per Weighted Average Shares
Outstanding
|
|
|
|
|
Funds
Flow
|
$
|
0.53
|
$
|
1.09
|
Net Income/(Loss)
(Basic)
|
|
(1.42)
|
|
0.20
|
Weighted Average
Number of Shares Outstanding (000's)
|
|
205,845
|
|
203,178
|
|
|
|
|
|
Selected Financial Results per
BOE(1)(2)
|
|
|
|
|
Oil & Natural Gas
Sales(3)
|
$
|
26.89
|
$
|
55.66
|
Royalties and
Production Taxes
|
|
(5.50)
|
|
(12.05)
|
Commodity Derivative
Instruments
|
|
9.56
|
|
(1.72)
|
Operating
Expenses
|
|
(9.56)
|
|
(8.97)
|
Transportation
Costs
|
|
(2.92)
|
|
(2.51)
|
General and
Administrative
|
|
(2.36)
|
|
(2.31)
|
Share Based
Compensation
|
|
(0.80)
|
|
(0.77)
|
Interest, Foreign
Exchange and Other Expenses
|
|
(3.28)
|
|
(1.67)
|
Taxes
|
|
-
|
|
(0.87)
|
Funds Flow
|
$
|
12.03
|
$
|
24.79
|
SELECTED OPERATING RESULTS
|
|
Three months ended March 31,
|
|
|
|
2015
|
|
2014
|
Average Daily
Production(2)
|
|
|
|
|
|
Crude oil
(bbls/day)
|
|
39,355
|
|
37,760
|
|
NGLs
(bbls/day)
|
|
3,735
|
|
3,262
|
|
Natural gas
(Mcf/day)
|
|
346,589
|
|
346,794
|
|
Total
(BOE/day)
|
|
100,855
|
|
98,821
|
|
|
|
|
|
|
% Crude Oil &
Natural Gas Liquids
|
|
43%
|
|
42%
|
|
|
|
|
|
Average Selling
Price(2)(3)
|
|
|
|
|
|
Crude oil (per
bbl)
|
$
|
44.04
|
$
|
93.04
|
|
NGLs (per
bbl)
|
|
22.48
|
|
67.90
|
|
Natural gas (per
Mcf)
|
|
2.58
|
|
5.07
|
|
|
|
|
|
Net Wells
drilled
|
|
28
|
|
30
|
(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.
|
|
Three months ended March 31,
|
Average Benchmark Pricing
|
2015
|
2014
|
WTI crude oil
(US$/bbl)
|
$
|
48.64
|
$
|
98.68
|
AECO– monthly index
(CDN$/Mcf)
|
2.95
|
4.76
|
|
|
|
AECO– daily index
(CDN$/Mcf)
|
2.75
|
5.71
|
NYMEX – last day
(US$/Mcf)
|
2.98
|
4.94
|
|
|
|
USD/CDN exchange
rate
|
1.24
|
1.10
|
Share Trading Summary
|
CDN* – ERF
|
U.S.** - ERF
|
|
|
|
For the three months
ended March 31, 2015
|
(CDN$)
|
(US$)
|
High
|
$
|
14.53
|
$
|
11.73
|
Low
|
$
|
9.41
|
$
|
7.89
|
Close
|
$
|
12.84
|
$
|
10.14
|
*
|
TSX and other
Canadian trading data combined.
|
**
|
NYSE and other U.S.
trading data combined.
|
2015 Dividends per Share
|
|
|
|
|
|
CDN$
|
US$(1)
|
January
|
|
$
|
0.09
|
$0.08
|
February
|
|
$
|
0.09
|
$0.07
|
March
|
|
$
|
0.09
|
$0.07
|
First Quarter
Total
|
|
$
|
0.27
|
$0.22
|
(1)
|
US$ dividends
represent CDN$ dividends converted
at the relevant foreign exchange
rate on the payment date.
|
Production and Capital Spending
|
|
|
Three months ended
March 31, 2015
|
Crude Oil & NGLs (bbls/day)
|
Average Production
Volumes
|
Capital Spending
($ millions)
|
Canada
|
19,332
|
57
|
United
States
|
23,758
|
79
|
Total Crude Oil & NGLs
(bbls/day)
|
43,090
|
136
|
Natural Gas (Mcf/day)
|
|
|
Canada
|
135,419
|
20
|
United
States
|
211,170
|
11
|
Total Natural Gas (Mcf/day)
|
346,589
|
31
|
Company Total (BOE/day)
|
100,855
|
167
|
Net Drilling Activity*** – for the three months ended March 31,
2015
|
|
|
|
|
|
|
|
Crude Oil
|
Horizontal Wells
Drilled
|
Wells Pending
Completion/
Tie-in *
|
Wells
On-stream**
|
Dry & Abandoned
Wells
|
Canada
|
14.4
|
9.0
|
10.9
|
-
|
United
States
|
8.2
|
7.3
|
3.6
|
-
|
Total Crude Oil
|
22.6
|
16.3
|
14.5
|
-
|
Natural Gas
|
|
|
|
|
Canada
|
3.0
|
3.0
|
-
|
-
|
United
States
|
2.2
|
2.2
|
2.9
|
-
|
Total Natural Gas
|
5.2
|
5.2
|
2.9
|
-
|
Company Total
|
27.9
|
21.5
|
17.4
|
-
|
*Wells drilled during
the quarter pending potential completion/tie-in or abandonment as
at March 31, 2015.
|
**Total wells brought
on-stream during the quarter regardless of when they were
drilled.
|
*** Table may not add
due to rounding.
|
Asset Activity
We had some notable operational successes during the
quarter. At Fort Berthold, we continue to evolve our
completion design with strong results. Despite no operated
on-stream activity for most of the quarter, we brought a 4-well pad
on-stream at the end of February with initial 30 day average
production rates (IP30) per well ranging from 1,290 – 1,390 barrels
of oil per day. Additionally, one of our most recent Three
Forks wells, located in the southeast area of our acreage, is
significantly outperforming our expectations for that region with
an IP30 rate of approximately 1,230 barrels of oil per day.
In all, we drilled 8.2 net wells with 3.6 net wells brought
on-stream over the quarter for a total investment of $79 million. Average daily production
during the quarter was 26,500 BOE per day from both Fort Berthold
and Sleeping Giant. We are seeing cost reductions materialize
with well costs trending down close to 15% from 2014 levels.
Our average well cost in Fort Berthold year-to-date is
approximately US$11.5
million.
With drilling activity outpacing completions at Fort Berthold,
we continued to build an inventory of drilled uncompleted wells
which stood at 18.8 net wells at quarter-end. As completion
activity begins to increase in the second quarter in response to
prices stabilizing and improved cost structures, we will start to
work through some of this uncompleted well inventory. We
expect to re-establish production growth in North Dakota in the second quarter. We
are also evaluating an increase in the number of planned
completions in the second half of 2015.
In the Marcellus, capital spending was meaningfully lower in the
quarter at $11 million, compared to
$26 million during the previous
quarter. Drilling activity slowed as we moved to a one-rig
drilling program with 2.2 net wells drilled and 2.9 net wells
brought on-stream. We continued to curtail production due to
weak natural gas prices in the region and expect to continue
curtailing production for the remainder of the year.
Production during the quarter averaged 195 MMcf per day.
In our Canadian oil portfolio, we drilled 14.4 net wells with
10.9 net wells brought on-stream. The drilling activity was
largely focused at Brooks, targeting the Lower Mannville
sands. Average well results have been in line with our
expectations and we are targeting growth of approximately 1,350 BOE
per day during 2015, resulting in expected annual average
production of approximately 3,900 BOE per day from the Brooks
area. The timing of the Brooks drilling program was driven by
lease retention.
In the Deep Basin, our operated 3 horizontal well pad was
drilled and completed at Ansell. Initial production rates in
late March showed encouraging results. The wells were
completed under budget and initial production results support our
assessment of a sweet spot trend across Enerplus' lands.
Crude Oil & Natural Gas Pricing
The West Texas Intermediate benchmark price for crude oil fell
more than 30% quarter-over-quarter and over 50% from the first
quarter of 2014. Both Canadian heavy and light oil
differentials were slightly weaker, while the Bakken crude oil
differential improved from the fourth quarter. Our average
realized sales price for crude oil during the quarter was down
approximately 36% from the fourth quarter to $44.04 per barrel. The outlook ahead on
crude differentials is positive. Improved market access,
particularly to the U.S. Gulf Coast, has reduced the downside
impact mid-continent refinery outages have historically had on
Canadian prices. Reduced supply from oil sands producers due
to seasonal maintenance is expected to further strengthen Canadian
crude oil differentials in the second quarter. The narrowing of the
Bakken crude differential is a result of increased rail capacity
coming into service during the quarter. The reversal of
Enbridge's Line 9, scheduled for the second quarter of 2015, is
expected to provide further support for U.S. Bakken differentials
in the coming months.
On the natural gas side, both AECO and NYMEX fell sharply as a
result of strong production in the U.S. combined with a delay in
winter weather in key regions in the U.S. which allowed storage to
return to more seasonally average levels compared to this time last
year. Our realized sales price for natural gas was $2.58 per Mcf during the quarter, down
approximately 21% from the previous quarter. In the
Marcellus, our realized differential was US$1.32 per Mcf below NYMEX, compared to the
average regional spot differential of US$1.68 per Mcf. Approximately 46% of our
Marcellus production is sold under long-term sales contracts which
have exposure to markets outside of Northeast Pennsylvania.
Our commodity hedge position continues to help support funds
flow in 2015. Approximately 35% of our expected crude oil
production net of royalties from April through December is hedged
at over US$90 per barrel and
approximately 46% of anticipated natural gas volumes net of
royalties are hedged at about US$3.90
per Mcf over the same period.
We have established an initial crude oil hedge position for
2016. Approximately 26% of our forecasted 2016 crude oil production
net of royalties is hedged with 6,000 barrels per day protected
through 3-way collars (US$50 per
barrel by US$65 per barrel by
$US80 per barrel), and an additional
2,000 barrels per day swapped at US$65.50 per barrel.
Board & Executive Changes
I would like to thank Mr. Edwin
Dodge who is retiring and not standing for re-election as a
Board member this year. Ed joined the Board of Directors of
Enerplus in May 2004 and his guidance
and direction have helped to successfully grow and transition the
business over the past 11 years.
I would also like to thank Mr. Donald
Nelson who is not standing for re-election as a Board member
this year. Don joined the Board of Directors of Enerplus in
June 2012 and has provided valuable
insight and guidance during his time as a Director.
I am pleased to announce that John
Hoffman has joined the executive team of Enerplus in the
position of Vice-President of Canadian Operations. John
brings a wealth of experience to the role having spent 25 years in
the Canadian energy industry in both leadership and engineering
roles, focused largely in the Western Canadian Sedimentary
Basin.
Outlook
Despite the current commodity price environment, Enerplus is
well positioned. We remain committed to disciplined capital
allocation with a strong focus on cost control. We continue
to achieve excellent results from our asset base with strong
momentum continuing into the second quarter. We are also
seeing encouraging signs in the market with a modest recovery in
crude oil prices and costs continuing to trend down. As we
look to re-establish production growth in our North Dakota properties, we are well
positioned to achieve our annual average production guidance range
for the year. Supported by our commodity hedging program and
commitment to reducing costs and driving operational efficiencies,
we expect to remain in a position of strength through 2015.
Q1 2015 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 8,
2015
|
Time:
|
8:00 AM MT (10:00 AM
ET)
|
Dial-In:
|
647-427-7450
|
|
1-888-231-8191 (toll
free)
|
Audiocast:
http://www.newswire.ca/en/webcast/detail/1508249/1681339
|
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:
|
16479542
|
Electronic copies of our First Quarter 2015 MD&A and
Financial Statements, along with other public information including
investor presentations, are available on our website at
www.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. "MBOE" and
"MMBOE" mean "thousand barrels of oil equivalent" and "million
barrels of oil equivalent", respectively.
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 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 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 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 its 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; 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 guidance is based on the following assumptions:
WTI price of US$55 per barrel, a
NYMEX gas price of US$2.75 per Mcf,
an AECO gas price of $2.50 per GJ and
a US$/CDN exchange rate of 1.25. 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 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; 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 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.
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 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 First Quarter 2015 MD&A.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation