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 Second 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, Aug. 7, 2015 /CNW/ - Enerplus Corporation
("Enerplus") (TSX: ERF) (NYSE: ERF) announces the results from
operations for the second quarter of 2015.
HIGHLIGHTS:
- Through the second quarter of 2015, Enerplus delivered
production growth, improved cost performance and maintained a
strong financial position.
- Production volumes grew by 7% quarter over quarter to 107,429
BOE per day. This growth was primarily driven by increased activity
in North Dakota, where production
averaged approximately 27,100 BOE per day, up over 25% from the
first quarter of 2015. We also saw growth from our gas portfolio
with our Canadian Deep Basin and Marcellus assets showing
production increases over the first quarter of 2015. Our production
mix was essentially unchanged from the previous quarter, with crude
oil and natural gas liquids accounting for 43% of production.
- As a result of continued operational outperformance, we are
increasing our average annual production guidance range to 100,000
– 104,000 BOE per day from 97,000 – 103,000 BOE per day. We expect
approximately 44,000 – 46,000 barrels per day of crude oil and
natural gas liquids. This guidance takes into account year to date
divestments of approximately 1,900 BOE per day.
- We spent $148 million in our core
areas during the quarter, and are on track to meet our annual
capital spending guidance of $540
million, despite the weak Canadian dollar. Approximately 75%
of spending in the quarter was directed to our North Dakota properties. In total we drilled
7.8 net wells and brought 22 net wells on-stream across our
portfolio in the second quarter.
- Both operating costs and G&A expenses for the quarter came
in lower than forecast, at $7.85 per
BOE and $2.03 per BOE, respectively.
Based on our cost savings realized to date and our increased
production target, we are decreasing our annual operating cost
guidance to $9.25 per BOE from
$9.75 per BOE and our G&A expense
guidance to $2.25 per BOE from
$2.40 per BOE, representing a
combined decrease of $0.65 per
BOE.
- Funds flow increased by 47% to $160
million from the first quarter primarily due to higher
production, lower costs and improved crude oil prices, and despite
slightly weaker gas pricing.
- Our hedging program generated gains of $73 million during the second quarter.
- We reported a net loss of $312.5
million for the quarter as we incurred a non-cash asset
impairment charge in the quarter of $497
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 commodity prices in the fourth
quarter of 2014 and the first half of 2015.
- During the quarter, we closed our previously announced non-core
asset sales, along with the sale of additional minor non-core
properties for proceeds of $188
million.
- After adjusting for divestment proceeds, our adjusted payout
ratio for the first six months of 2015 was 75%.
- We ended the quarter with an improved debt to funds flow ratio
of 1.6 times, down from 1.7 times in the first quarter of 2015. At
June 30, 2015, we were approximately
8% drawn on our $1 billion credit
facility. Following the next scheduled repayment of our senior
notes in October 2015 of US$10.8 million, we have no scheduled debt
repayments until June 2017.
"We believe our second quarter results demonstrate our
commitment to maintaining our financial strength, focusing on
productivity improvements and cost control measures, and
maintaining our disciplined approach to capital allocation. Our
goal of a fully funded program in 2015 remains intact and we have
significant flexibility to navigate through this challenging
market," said Ian C. Dundas,
President & CEO.
SELECTED FINANCIAL RESULTS
|
Three months ended
June 30,
|
Six months ended
June 30,
|
|
2015
|
2014
|
2015
|
2014
|
Financial
(000's)
|
|
|
|
|
Funds
Flow(4)
|
$ 160,436
|
$
213,211
|
$ 269,600
|
$ 433,723
|
Cash and Stock
Dividends
|
30,935
|
55,214
|
78,294
|
110,149
|
Net
Income/(Loss)
|
(312,544)
|
39,957
|
(605,750)
|
79,994
|
Debt Outstanding –
net of cash
|
1,120,680
|
1,067,590
|
1,120,680
|
1,067,590
|
Capital
Spending
|
147,979
|
204,427
|
314,989
|
422,190
|
Property
Divestments
|
187,801
|
(525)
|
191,513
|
116,700
|
Debt to Funds Flow
Ratio(4)
|
1.6x
|
1.3x
|
1.6x
|
1.3x
|
|
|
|
|
|
Financial per
Weighted Average Shares Outstanding
|
|
|
|
|
Funds Flow
|
$
0.78
|
$
1.04
|
$
1.31
|
$
2.13
|
Net
Income/(Loss)
|
(1.52)
|
0.20
|
(2.94)
|
0.39
|
Weighted Average
Number of Shares Outstanding (000's)
|
206,208
|
204,158
|
206,028
|
203,671
|
|
|
|
|
|
Selected Financial
Results per BOE(1)(2)
|
|
|
|
|
Oil & Natural Gas
Sales(3)
|
$ 30.53
|
$
53.32
|
$
28.78
|
$
54.45
|
Royalties and
Production Taxes
|
(6.23)
|
(11.58)
|
(5.88)
|
(11.81)
|
Commodity Derivative
Instruments
|
7.47
|
(2.60)
|
8.48
|
(2.17)
|
Cash Operating
Expenses
|
(8.12)
|
(9.12)
|
(8.81)
|
(9.04)
|
Transportation
Costs
|
(2.87)
|
(2.39)
|
(2.89)
|
(2.45)
|
General and
Administrative
|
(2.03)
|
(1.97)
|
(2.19)
|
(2.14)
|
Cash Share-Based
Compensation
|
0.13
|
(1.12)
|
(0.32)
|
(0.95)
|
Interest, Foreign
Exchange and Other Expenses
|
(2.48)
|
(1.61)
|
(2.87)
|
(1.63)
|
Taxes
|
0.01
|
(0.40)
|
-
|
(0.63)
|
Funds Flow
|
$ 16.41
|
$
22.53
|
$
14.30
|
$
23.63
|
SELECTED OPERATING RESULTS
|
Three months ended
June 30,
|
Six months ended
June 30,
|
|
2015
|
2014
|
2015
|
2014
|
Average Daily
Production(2)
|
|
|
|
|
Crude Oil
(bbls/day)
|
41,122
|
39,863
|
40,243
|
38,817
|
Natural Gas Liquids
(bbls/day)
|
5,145
|
3,636
|
4,444
|
3,450
|
Natural Gas
(Mcf/day)
|
366,971
|
362,929
|
356,836
|
354,906
|
Total
(BOE/day)
|
107,429
|
103,987
|
104,160
|
101,418
|
|
|
|
|
|
% Crude Oil and
Natural Gas Liquids
|
43%
|
42%
|
43%
|
42%
|
|
|
|
|
|
Average Selling
Price (2)(3)
|
|
|
|
|
Crude Oil (per
bbl)
|
$
58.26
|
$
96.46
|
$ 51.35
|
$
93.25
|
Natural Gas Liquids
(per bbl)
|
20.88
|
51.80
|
21.55
|
57.66
|
Natural Gas (per
Mcf)
|
2.09
|
4.15
|
2.32
|
4.46
|
|
|
|
|
|
Net Wells
Drilled
|
8
|
14
|
36
|
44
|
(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
June 30,
|
Six months ended
June 30,
|
Average Benchmark
Pricing
|
2015
|
2014
|
2015
|
2014
|
WTI Crude Oil
(US$/bbl)
|
$
57.94
|
$
102.99
|
$
53.29
|
$ 100.84
|
AECO – monthly index
(CDN$/Mcf)
|
2.67
|
4.68
|
2.81
|
4.72
|
AECO – daily index
(CDN$/Mcf)
|
2.64
|
4.69
|
2.70
|
5.20
|
NYMEX – last day
(US$/Mcf)
|
2.64
|
4.67
|
2.81
|
4.80
|
US/CDN exchange
rate
|
1.23
|
1.09
|
1.24
|
1.10
|
|
|
|
|
|
Share Trading
Summary
|
CDN*
ERF
|
U.S.** -
ERF
|
For three months
ended June 30, 2015
|
(CDN$)
|
(US$)
|
High
|
16.09
|
13.16
|
Low
|
10.61
|
8.56
|
Close
|
10.96
|
8.79
|
*
|
TSX and other
Canadian trading data combined.
|
**
|
NYSE and other U.S.
trading data combined.
|
2015 Dividends per
Share
|
|
|
Payment
Month
|
CDN$
|
US$(1)
|
First Quarter
Total
|
$0.27
|
$0.22
|
April
|
0.05
|
0.04
|
May
|
0.05
|
0.04
|
June
|
0.05
|
0.04
|
Second Quarter
Total
|
0.15
|
0.12
|
Total
Year-to-Date
|
0.42
|
0.34
|
(1)
|
US$ dividends
represent CDN$ dividends converted at the relevant foreign exchange
rate on the payment date.
|
Production and Capital Spending
|
Three months
ended
June 30,
2015
|
Six months
ended
June 30, 2015
|
Crude Oil &
NGLs (bbls/day)
|
Average
Production
Volumes
|
Capital
Spending
($ millions)
|
Average
Production
Volumes
|
Capital
Spending
($ millions)
|
Canada
|
17,598
|
17.3
|
18,460
|
72.4
|
United
States
|
28,669
|
110.8
|
26,227
|
189.2
|
Total Crude Oil
& NGLs (bbls/day)
|
46,267
|
128.1
|
44,687
|
261.6
|
Natural Gas
(Mcf/day)
|
|
|
|
|
Canada
|
144,788
|
7.3
|
140,129
|
29.1
|
United
States
|
222,183
|
12.6
|
216,707
|
24.3
|
Total Natural Gas
(Mcf/day)
|
366,971
|
19.9
|
356,836
|
53.4
|
Company Total
(BOE/day)
|
107,429
|
148.0
|
104,160
|
315.0
|
Net Drilling Activity*** – for the three months ended
June 30, 2015
Crude
Oil
|
Wells
Drilled
|
Wells
Pending
Completion/
Tie-in
*
|
Wells
On-stream**
|
Dry &
Abandoned
Wells
|
Canada
|
1.0
|
1.0
|
6.6
|
-
|
United
States
|
5.5
|
4.5
|
9.2
|
-
|
Total Crude
Oil
|
6.5
|
5.5
|
15.8
|
-
|
Natural
Gas
|
|
|
|
|
Canada
|
0.7
|
0.7
|
3.0
|
-
|
United
States
|
0.7
|
0.4
|
3.2
|
-
|
Total Natural
Gas
|
1.4
|
1.1
|
6.2
|
-
|
Company
Total
|
7.8
|
6.5
|
22.0
|
-
|
*
|
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.
|
Asset Activity
We re-established production growth in North Dakota in the second quarter of 2015.
Production from Fort Berthold averaged 27,100 BOE per day during
the quarter, up over 25% from the first quarter of 2015. We drilled
5.5 net wells in Fort Berthold with 9.2 net wells brought on-stream
during the quarter for a total capital outlay of $111 million.
We continue to run a one-rig drilling program as we work through
our inventory of drilled uncompleted wells at Fort Berthold and
expect to drill approximately 8 net wells in the second half of the
year. We are ahead of schedule on our 2015 completions activity.
During the first six months of 2015 we brought approximately 13 net
wells on-stream. We expect to bring up to 10 additional net wells
on-stream during the second half of the year. This activity is
broadly weighted towards the third quarter and we expect production
growth through the remainder of the year. Our high intensity
completion design continues to yield excellent results. The average
initial 30 day production rate (IP30) of our operated on-stream
wells in the quarter was over 2,000 BOE per day, exceeding our high
end type curve. We continue to see improved well costs with current
costs down over 20% from 2014 levels.
In the Marcellus, continued low levels of spending ($12.6 million in the second quarter) led to 0.7
net wells drilled and 3.2 net wells on-stream. Despite the reduced
activity, well outperformance resulted in production of 201 MMcf
per day during the second quarter, a modest increase from the
previous quarter.
In the Deep Basin, we drilled three excellent wells at our
Ansell pad. The average peak 30 day production rate for a well on
the pad was approximately 10 MMcf per day, on trend with our high
end type curve.
Crude Oil & Natural Gas Pricing
The West Texas Intermediate (WTI) benchmark price for crude oil
increased by 19% quarter-over-quarter to average US$57.94 per barrel in the second quarter. The
strength in WTI prices combined with the narrowing of crude oil
differentials in both Canada and
the U.S. resulted in a 32% improvement in the selling price for our
crude oil compared to the previous quarter. The average realized
sales price for our crude oil was $58.26 per barrel during the quarter with crude
oil properties generating approximately 90% of our corporate
netback.
On the natural gas side, both AECO and NYMEX weakened from the
previous quarter due to continued high production and increased
storage levels across the continent. In the Marcellus, our realized
differential widened US$0.07 per Mcf
from the previous quarter to average US$1.39 per Mcf. Overall, as a result of lower
benchmark pricing and continued pricing weakness in the Marcellus
producing region, our realized sales price for gas fell by 19%
compared to the previous quarter to average $2.09 per Mcf.
We continued to add to our commodity hedge position for both
2015 and 2016. For the second half of 2015, we have an average of
11,250 barrels per day of crude oil hedged (representing
approximately 35% of our expected crude oil production net of
royalties) at an average floor price of US$84.58 per barrel through a combination of
swaps and three way collar structures. For 2016, we have an average
of 11,000 barrels per day of crude oil hedged (representing
approximately 34% of our expected crude oil production net of
royalties) at an average floor price of US$64.35 per barrel through a combination of
swaps and three way collar structures.
We have also added to our NYMEX gas hedging position. For the
second half of 2015, we are swapped on an average of 128 MMcf per
day at an average price of US$3.82
per Mcf, representing approximately 47% of our forecasted natural
gas production after royalties. For 2016, we have 25 MMcf per day,
or 9% of our forecasted natural gas production after royalties,
hedged through three-way collars with an average floor price of
US$3.00 per Mcf.
Outlook
We delivered another quarter of strong operating results. On the
back of this operational momentum and improved cost efficiencies,
we are increasing our 2015 production guidance and reducing our
operating and G&A expense guidance.
We continue to navigate through this challenging commodity price
environment with a strong balance sheet and hedging program that
will support our funds flow. We remain focused on driving
improvement in our operational efficiencies through both reducing
our cost structures and optimizing well performance. Above
all, the low commodity prices have not stopped us from committing
the time and resources to ensure safe, responsible and sustainable
operations across our business.
Q2 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, August 7,
2015
|
Time:
|
9:00 AM MT (11:00 AM
ET)
|
Dial-In:
|
647-427-7450
|
|
1-888-231-8191 (toll
free)
|
Audiocast:
http://event.on24.com/r.htm?e=1019901&s=1&k=5E5D391F544E5ABC6D1F186A4695576D
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:
|
77813725
|
Electronic copies of our Second 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.
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 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, 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; 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: July 22, 2015 forward
market WTI price of US$51.99 per
barrel, NYMEX gas price of US$2.89
per Mcf, AECO gas price of $2.75 per
GJ and USD/CDN exchange rate of 1.27. 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.
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 Second Quarter 2015 MD&A.
SOURCE Enerplus Corporation