All financial figures are unaudited and in Canadian dollars (CDN$)
unless noted otherwise. All financial statements have been
prepared in accordance with International Financial Reporting
Standards ("IFRS"). This news release includes forward-looking
statements and information within the meaning of applicable
securities laws. Readers are advised to review
"Forward-Looking Information and Statements" at the conclusion of
this news release. Readers are also referred to "Notice to
U.S. Readers" and "Non-GAAP Measures" at the end of this news
release for information regarding the presentation of the financial
and operational information in this news release. A full copy
of our 2012 Second Quarter Financial Statements and MD&A have
been filed 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. 10, 2012 /CNW/ - Enerplus Corporation ("Enerplus" or
the "Corporation") is pleased to announce the results for the
second quarter of 2012. Highlights of the quarter were as follows:
-- Our operations delivered another quarter of growth with
production averaging 82,108 BOE/day during the second quarter, up
approximately 4% over our average volumes for the first quarter of
2012 and up almost 9% over the same period last year. -- Total
crude oil volumes increased by 7% in the second quarter over the
first quarter, with light oil production from Fort Berthold
increasing by almost 35%. Our light and medium crude oil now
represents 76% of our total oil production, an improvement from 72%
last year at this time. Total crude oil and natural gas liquids now
represent 49% of our production volumes, a 6% increase over the
second quarter of 2011. Our Canadian natural gas production
declined quarter over quarter as expected due primarily to the
limited capital investment in our conventional and shallow gas
assets. However, our gas production volumes in the Deep Basin
region were higher as a result of our drilling success in the
Ansell area earlier this year. -- We invested $209 million in
exploration and development capital during the second quarter.
Approximately 80% of this spending was focused on our crude oil
resource plays, specifically at Fort Berthold in the U.S. and on
our waterflood assets in Canada. The bulk of our natural gas
spending was focused in the Marcellus with our non-operated
partners as we continued to focus on lease retention in the region.
-- A total of 18.7 net wells were drilled during the quarter, of
which approximately 75% were oil wells. A total of 18.4 net wells
were brought on stream, 67% of which were oil. -- Funds flow was
approximately $147 million during the quarter ($0.74 per share),
down 10% from the first quarter of 2012. Our growing production as
well as our crude oil hedges helped offset the impact of lower
commodity prices and wider crude oil differentials during the
quarter. Our oil hedging program added $1.50/bbl of cash gains to
our realized crude oil pricing during the quarter. -- Our trailing
twelve month debt to funds flow ratio was 2.0x at June 30, 2012 and
we had $680 million available on our $1 billion bank credit
facility. -- Operating costs were on track with expectations
averaging $10.78/BOE for the second quarter and general and
administrative costs (including equity based compensation) at
$2.81/BOE were lower than expected due to lower costs associated
with our long-term incentive plans. -- We continued to protect our
balance sheet throughout the quarter in response to the further
decline in natural gas prices as well as the sharp decline in crude
oil prices. In May we closed a $405 million private placement of
long-term, senior unsecured notes, the proceeds of which were used
to reduce borrowings under our bank credit facility. These notes
have terms ranging from seven to twelve years with attractive
interest rates of approximately 4.4%. -- A Stock Dividend Program
("SDP") was implemented in June to allow all of our shareholders
the option to elect to receive shares instead of a cash dividend.
We believe this program will provide an additional source of
funding for our capital investment strategies. -- As a result of
lower cash flow expectations due to the drop in commodity prices,
we elected to reduce our monthly dividend from $0.18/share to
$0.09/share commencing with our July dividend. We believe this
reduction was necessary in order to strike a better balance between
yield and growth for our investors and also preserve financial
flexibility going forward. -- We have 18,500 bbls/day of oil
production hedged at US$96.17/bbl for the remainder of 2012 and
14,500 bbls/day of oil production hedged at US$101.36/bbl for 2013.
In response to the recent increase in natural gas prices, we've
started to add hedge positions on our natural gas production for
2013, purchasing put protection which allows us to retain the
upside price on approximately 23 MMcf/day of natural gas production
hedged at $3.17/Mcf. -- We continue to progress on our plans for
the partial sale and/or monetization of a portion of our early
stage asset portfolio which includes the Duvernay, Montney and
operated Marcellus. We have retained a financial advisor and are
actively marketing these assets. In addition, our plans also
include selling a portion of our equity portfolio and other
non-core producing assets to help maintain our financial
flexibility. SELECTED FINANCIAL & OPERATING RESULTS Three
months ended June Six months ended June 30, 30, 2012 2011 2012 2011
Financial (000's) Funds Flow $146,547 $132,441 $309,253 $293,665
Cash and Stock 88,599 97,077 194,594 193,763 Dividends Net Income
100,264 267,982 66,443 297,531 Debt Outstanding 1,152,746 460,087
1,152,746 460,087 - net of cash Capital Spending 208,587 145,165
525,653 319,609 Property and 23,649 94,415 56,669 142,633 Land
Acquisitions Divestments (87) 571,096 52,524 630,788 Debt to
Trailing 2.0x 0.7x 2.0x 0.7x 12 Month Funds Flow Financial per
Weighted Average Shares Outstanding Funds Flow $0.74 $0.74 $1.60
$1.64 Net Income 0.51 1.50 0.34 1.66 Weighted Average 196,768
179,583 193,306 179,209 Number of Shares Outstanding Selected
Financial Results per BOE(1) Oil & Gas Sales $42.07 $51.62
$44.51 $49.28 (2) Royalties (8.36) (9.07) (8.80) (8.85) Commodity
0.68 (3.03) (0.38) (1.30) Derivative Instruments Operating Costs
(10.80) (9.86) (10.32) (9.37) G&A and Equity (2.57) (3.16)
(2.83) (3.21) Based Compensation Interest and (0.90) (0.89) (0.81)
(1.82) Other Expenses Taxes (0.51) (6.30) (0.31) (3.22) Funds Flow
$19.61 $19.31 $21.06 $21.51 Three months ended June Six months
ended June 30, 30, 2012 2011 2012 2011 Average Daily Production
Crude oil 36,527 29,330 35,300 29,831 (bbls/day) NGLs (bbls/day)
3,393 3,442 3,698 3,337 Natural gas 253,126 255,665 249,905 253,584
(Mcf/day) Total (BOE/day) 82,108 75,383 80,649 75,433 % Crude Oil
& 49% 43% 48% 44% Natural Gas Liquids Average Selling Price(2)
Crude oil (per $ 74.36 $90.92 $ 79.93 $84.23 bbl) NGLs (per bbl)
60.11 66.20 58.30 63.35 Natural gas (per 2.06 3.86 2.17 3.88 Mcf)
USD/CDN exchange 1.01 0.97 1.01 0.98 rate Net Wells drilled 19 14
53 40 (1) Non-cash amounts have been excluded. (2) Net of oil and
gas transportation costs, but before the effects of commodity
derivative instruments. Share Trading Summary CDN* - ERF U.S.** -
ERF For the three months ended June 30, 2012 (CDN$) (US$) High
$22.57 $22.78 Low $11.67 $11.35 Close $13.08 $12.87 * TSX and other
Canadian trading data combined. ** NYSE and other U.S. trading data
combined. 2012 Dividends Per Share(2) Payment Month CDN$ US$(1)
First Quarter Total $0.54 $0.54 April $0.18 $0.18 May 0.18 0.17
June 0.18 0.18 Second Quarter Total $0.54 $0.53 Total Year-to-Date
$1.08 $1.07 (1) US$ dividends represent CDN$ dividends converted at
the relevant foreign exchange rate on the payment date. (2) The
dividend has been reduced to $0.09 per share effective for the July
20, 2012 payment. Three months ended Six months ended June 30, 2012
June 30, 2012 Average Capital Average Capital Production Spending
Production Spending Play Type Volumes ($ millions) Volumes ($
millions) Tight Oil (BOE/day) 18,329 $139 16,986 $301 Crude Oil
Waterflood 16,953 27 16,539 70 (BOE/day) Conventional Oil 4,883 2
4,840 14 (BOE/day) Total Crude Oil 40,165 $168 38,365 $385
(BOE/day) Marcellus Shale Gas 36,868 29 32,493 90 (Mcfe/day) Other
Natural Gas 214,790 12 221,209 51 (Mcfe/day) Total Gas (Mcfe/day)
251,658 $41 253,702 $141 Company Total 82,108 $209 80,649 $526 Net
Drilling Activity - for the three months ended June 30, 2012 Wells
Horizontal Vertical Total Pending Dry & Wells Wells Wells
Completion/ Wells Abandoned Play Type Drilled Drilled Drilled
Tie-in* On-stream** Wells Tight Oil 7.2 - 7.2 7.2 8.0 - Crude Oil
5.8 1.0 6.8 6.8 4.4 - Waterflood Conventional - - - - - - Oil Total
Crude 13.0 1.0 14.0 14.0 12.4 - Oil Marcellus 3.5 - 3.5 3.5 3.0 -
Shale Gas Other 1.2 - 1.2 0.2 3.0 - Natural Gas Total Gas 4.7 - 4.7
3.7 6.0 - Company 17.7 1.0 18.7 17.7 18.4 - Total * Wells drilled
during the quarter that are pending potential completion/tie-in or
abandonment ** Total wells brought on-stream during the quarter
regardless of when they were drilled OPERATIONS UPDATE Tight Oil -
Fort Berthold, ND Production from the Fort Berthold region
continued to increase through the second quarter as planned. We
spent $138 million on development capital, drilling 7.0 net wells
and bringing 8.0 net wells on-stream. Production averaged 11,700
BOE/day, up almost 35% from 8,700 BOE/day during the first quarter
of this year and slightly ahead of expectations. We continued to
pursue measures to control our costs in the Fort Berthold region.
Operated spending continues to be ahead of budget as we have not
been able to see a meaningful reduction in well costs year-to-date.
As part of our effort to manage costs, we have eliminated our two
least efficient operated drilling rigs and are now running two rigs
which we expect will effectively execute the remainder of our
operated 2012 capital program. Non-operated activity has also
increased significantly as our partners are drilling more than we
originally anticipated. In conjunction with our drilling
activities, infrastructure build-out (compression, metering and
pipelines) in the region has continued at a brisk pace as we tie-in
more wells and capture the associated natural gas volumes, thereby
reducing our emissions. We originally expected to fund this tie-in
activity through a mid-stream third party however we have been
funding these capital costs directly year-to-date. We continue to
evaluate fee-based arrangements for the tie-in capital linked to
the gathering agreements now in place. We now have approximately
66% of our wells connected to pipeline. We expect spending to
moderate in the second half of 2012. Year-to-date, we've drilled
16.5 net horizontal wells at Fort Berthold, 82% of which have been
long horizontals. Crude Oil Waterfloods Production from our
waterflood properties grew by 5% quarter over quarter as a result
of our development activities. Despite wet conditions through
spring break-up at our Medicine Hat waterflood property, we were
able to complete our plans on our polymer project and began
injecting polymer into five injector wells in the latter part of
May. We also drilled 2.9 net producer wells and 1.4 net
injector wells at Medicine Hat as part of our on-going waterflood
optimization program. Production from this field was up 20%
over the first quarter and is currently producing at the highest
volume achieved since 1997. We also restarted our drilling
program in southeast Saskatchewan targeting the Ratcliffe with two
horizontal wells brought on stream during the quarter. Marcellus We
continued to invest with our non-operated partners in the Marcellus
during the second quarter spending $29 million and participating in
drilling 3.5 net wells with 3.0 net wells brought on-stream.
Our capital program has been designed to maximize lease retention
in this region throughout 2012. Some of our partners have
slowed completion and tie-in activities including reducing the
number of frac stages per well, in an effort to preserve capital.
As a result of these activities, we believe production may be lower
than originally expected in the latter half of the year exiting
2012 at approximately 60 MMcf/day compared to our original estimate
of 70 MMcf/day. Our Marcellus production increased to 37 MMcf/day
in the second quarter. Update on 2012 Guidance We continue to
manage spending levels throughout our operations in order to offset
higher spending in the Fort Berthold region. While we expect
capital spending to be lower in the second half of 2012, the
increased capital expenditures at Fort Berthold have increased our
overall capital spending program for 2012. We now expect full year
capital expenditures to be approximately $850 million, up from our
original estimate of $800 million. We are increasing our
annual average production guidance from 83,000 BOE/day to 83,500
BOE/day however we are maintaining our exit production guidance of
88,000 BOE/day. The additional spending at Fort Berthold is
expected to add oil production to our exit volumes, however we
expect this will be offset by lower production associated with
slower completion and tie-in activity in the Marcellus
region. We continue to expect our oil and liquids production
weighting to be approximately 50% as we exit 2012. We are
maintaining our guidance for full year operating costs at
$10.40/BOE however, general and administrative costs are now
expected to average $3.30/BOE down from our previous forecast of
$3.55/BOE due to reduced costs associated with our long-term
incentive programs. Outlook I am very pleased with the progress we
continue to make on the operational front. We are increasing
production quarter over quarter and have successfully shifted our
production mix to be close to 50% crude oil and natural gas
liquids. Although weaker commodity prices and widening
differentials have presented challenges for ourselves and the
industry in general, we've taken a number of steps to manage our
balance sheet and continue to pursue additional funding sources to
help improve our liquidity beyond 2012. Based upon our
success and the outlook for commodity prices, we will adjust our
growth targets and capital spending levels as needed in order to
ensure we have sufficient liquidity and deliver a competitive
return to our investors. I am also pleased to announce that Mr.
Chris Stephens has been promoted to the position of Vice-President,
Canadian Assets. Mr. Stephens is accountable for the
implementation of the Canadian asset strategy and performance and
has been with Enerplus since June of 2008. In addition, Mr.
Gordon Love has been promoted to the position of Vice-President,
Technical and Operations Services and will oversee our services and
field operations in Canada as well as Facility Asset Management and
Supply Chain Management for both our U.S. and Canadian operations.
Mr. Love joined Enerplus in 2010. Both Mr. Stephens and Mr.
Love report to Mr. Ray Daniels, Senior Vice-President of Operations
for Enerplus. Gordon J. Kerr President & Chief Executive
Officer Enerplus Corporation NOTICE TO U.S. READERS The oil and
natural gas reserves information contained in this news release has
generally been prepared in accordance with Canadian disclosure
standards, which are not comparable in all respects to United
States or other foreign disclosure standards. Reserves categories
such as "proved reserves" and "probable reserves" may be defined
differently under Canadian requirements than the definitions
contained in the United States Securities and Exchange Commission
(the "SEC") rules. In addition, under Canadian disclosure
requirements and industry practice, reserves and production are
reported using volumes prior to deduction of royalty and similar
payments. The practice in the United States is to report reserves
and production using net volumes, after deduction of applicable
royalties and similar payments. Canadian disclosure requirements
require that forecasted commodity prices be used for reserves
evaluations, while the SEC mandates the use of an average of first
day of the month price for the 12 months prior to the end of the
reporting period. BARRELS OF OIL EQUIVALENT AND CUBIC FEET OF GAS
EQUIVALENT This news release also contains references to "BOE"
(barrels of oil equivalent) and "cfe" (cubic feet of gas
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, and one barrel of oil to six
thousand cubic feet of gas (1 bbl: 6 Mcf) when converting oil to
cfes. BOEs and cfes 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 crude oil
as compared to natural gas is significantly different from the
energy equivalency of 6:1, utilizing a conversion on a 6:1 basis
may be misleading as an indication of value. Flow test
results and initial production rates: A pressure transient analysis
or well-test interpretation has not been carried out and thus
certain of the test results provided herein should be considered to
be preliminary until such analysis or interpretation has been done.
Test results and initial production rates disclosed herein may not
necessarily be 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", "objective",
"ongoing", "may", "will", "project", "should", "believe", "plans",
"intends", "budget", "strategy" and similar expressions are
intended to identify forward-looking information. In particular,
but without limiting the foregoing, this news release contains
forward-looking information pertaining to the following: Enerplus'
strategy to deliver both income and growth to investors and
Enerplus' related asset portfolio; future capital and development
expenditures and the timing and allocation thereof among our
resource plays and assets; future development and drilling
locations and plans; the performance of and future results from
Enerplus' assets and operations, including anticipated production
levels and decline rates; future growth prospects, acquisitions and
dispositions; the volumes and estimated value of Enerplus' oil and
gas reserves and contingent resource volumes and future commodity
price and foreign exchange rate assumptions related thereto; the
life of Enerplus' reserves; the volume and product mix of Enerplus'
oil and gas production; securing necessary infrastructure and third
party services; future cash flows and debt-to-cash flow levels;
returns on Enerplus' capital program; future costs and expenses;
and future issuances of debt or equity, including the terms and
timing thereof and the expected use of proceeds therefrom. The
forward-looking information contained in this news release reflect
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;
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'
reserve and resource volumes; commodity price and cost assumptions;
the continued availability of adequate debt and/or equity financing
and cash flow to fund Enerplus' capital and operating requirements
as needed; and the extent of its liabilities. 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 the demand for
or supply of Enerplus' products; unanticipated operating results,
results from development plans or production declines; 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 reserve and resource volumes; limited, unfavourable or a lack
of access to capital markets; increased costs; a lack of adequate
insurance coverage; the impact of competitors; reliance on industry
partners; a failure to complete planned assets dispositions on the
terms anticipated or at all; and certain other risks detailed from
time to time in Enerplus' public disclosure documents (including,
without limitation, those risks identified in Enerplus' Annual
Information Form and Form 40-F described above). The
forward-looking information contained in this news release speak
only as of the date of this news release, and none of Enerplus or
its subsidiaries assumes any obligation to publicly update or
revise them to reflect new events or circumstances, except as may
be required pursuant to applicable laws. NON-GAAP MEASURES In this
news release, we use the term "funds flow" to analyze operating
performance, leverage and liquidity. We calculate funds flow based
on cash flow from operating activities before changes in non-cash
operating working capital and decommissioning liabilities settled,
all of which are measures prescribed by International Financial
Reporting Standards ("IFRS") and which appear in our Consolidated
Statements of Cash Flows. Enerplus believes that, in addition to
net earnings and other measures prescribed by IFRS, the term "funds
flow" is a useful supplemental measure as it provides an indication
of the results generated by Enerplus' principal business
activities. However, this measure is not a measure recognized by
IFRS and does not have a standardized meaning prescribed by IFRS.
Therefore, this measure, as defined by Enerplus, may not be
comparable to a similar measure presented by other issuers.
Enerplus
Corporation CONTACT: For a complete copy of our 2012 Second Quarter
Report, pleasevisit ourwebsite at www.enerplus.com. For further
information, please call1-800-319-6462 or e-mail
investorrelations@enerplus.com.
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