SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Report of Foreign Issuer
pursuant to Rule 13-a-16 or 15d-16
of the Securities Exchange
Act of 1934
FOR THE MONTH OF December,
2014
FORM 6-K
COMMISSION FILE NUMBER
1-15150
The Dome Tower
Suite
3000, 333 - 7th Avenue S.W.
Calgary, Alberta
Canada T2P 2Z1
(403) 298-2200
Indicate by check mark whether
the registrant files or will file annual reports under cover Form 20-F or Form 40-F.
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if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7)
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whether, by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the
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EXHIBIT INDEX
EXHIBIT 99.1 - News Release Dated December 17, 2014 - Enerplus Announces 2015 Guidance: Reduced Spending, Continued Financial Flexibility and Restrained Growth |
SIGNATURE
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
ENERPLUS CORPORATION
BY: |
/s/ |
David A. McCoy |
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David A. McCoy |
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Vice President, General Counsel & Corporate Secretary |
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DATE: December 17, 2014
Exhibit 99.1
Enerplus Announces 2015 Guidance: Reduced Spending, Continued
Financial Flexibility and Restrained Growth
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. For information regarding the presentation of certain information
in this news release, see "Currency, BOE and Operational Information" at the conclusion of this news release.
CALGARY, Dec. 17, 2014 /CNW/ - Enerplus Corporation ("Enerplus")
(TSX: ERF) (NYSE: ERF) has approved a capital budget for 2015 that is designed to preserve our balance sheet strength and financial
flexibility while delivering restrained production growth. This disciplined approach to capital spending is focused on our
core areas with the best economics.
Highlights:
| · | Enerplus expects to spend $635 million in capital in 2015. This represents
a $195 million or 23% reduction in capital spending compared to our 2014 forecast. |
| · | Average 2015 production is expected to be 103,000 BOE/day to 108,000
BOE/day. At the low end of this range, Enerplus would expect to hold production constant, and at the high end of the range we would
expect approximately 5% production growth. |
| · | Debt-to-funds flow is expected to be below 2 times at the end of 2015,
even if WTI averages US$65/bbl for the year (NYMEX at US$3.75/MMBtu, AECO at $3.30/GJ, and FX at 1.15). We have not assumed any
proceeds from non-core divestments. |
| · | 2015 operating costs are forecast at $10.50/BOE. This is slightly higher
than 2014 estimates due to the impact of a weaker Canadian dollar when converting our U.S. operating costs, as well as the sale
of lower operating cost non-core Canadian natural gas properties in the fourth quarter of 2014. |
| · | Cash general and administrative ("G&A") costs are expected
to remain constant at $2.30/BOE. |
Capital Spending
Based upon the commodity price risks we see for 2015, we have
established a defensive capital budget that is designed to deliver modest production growth and preserve our financial strength
while continuing to invest for the future. Approximately 60% of our annual capital spending is expected to occur in the first half
of 2015. We expect to drill 75 net wells and bring 80 net wells on-stream in 2015.
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2015 Capital Spending |
$ millions |
Development Drilling & Completions |
$530 |
Plant/Facilities |
$75 |
Maintenance |
$30 |
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Total |
$635 |
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2015 Development Drilling & Completions |
$ millions |
Ft. Berthold North Dakota |
$320 |
Canadian Crude Oil & Waterfloods |
85 |
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Total crude oil spending |
$405 |
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Marcellus |
$90 |
Canadian Deep Basin |
35 |
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Total natural gas spending |
$125 |
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Total |
$530 |
We expect our 2015 capital program to deliver exit capital
efficiencies of approximately $25,000 per flowing BOE per day.
North Dakota
We plan to maintain our Bakken/Three Forks two rig program
in North Dakota. We expect to invest $320 million in Fort Berthold, drilling approximately 24 net wells and bringing 22 net wells
on-stream. The 30-day initial production rates of our long Bakken wells drilled in 2014 have exceeded our expectations by
20%. These wells have one of the lowest break even supply costs within the basin. We expect the NPV10% average break even
supply cost on our Ft. Berthold program in 2015 will be approximately WTI US$58/bbl, which is calculated at current costs.
The majority of the capital spend is in areas where we expect internal rates of return ("IRR") above 30% at US$65/bbl
WTI.
Canadian Crude Oil & Waterfloods
We plan to invest $135 million in our Canadian crude oil assets
in 2015 which includes $85 million of drilling and completion costs. Approximately 45% or $60 million of this is planned for the
Brooks area in response to land retention requirements. We expect to drill 23 wells and complete 28 wells in Brooks in 2015. We
expect a NPV10% break even supply cost of approximately WTI US$58/bbl in Brooks. We also expect to spend $35 million advancing
our waterflood and EOR projects at Medicine Hat and Giltedge.
Natural Gas
Spending in the Marcellus is expected to decrease by almost
45% in 2015 to $90 million. Despite this reduction in spending, we expect strong well performance and lower capital costs to provide
production growth of approximately 10%. We have assumed continued Marcellus production curtailment in 2015 (similar to the curtailment
experienced in 2014) in response to low natural gas prices.
Our 2015 Canadian natural gas activities will be focused on
the Wilrich where we plan to drill two wells and complete three wells in the Ansell area for an anticipated cost of approximately
$22 million. In the Duvernay, we plan to evaluate the performance of our existing wells and have minimal capital spending planned
for 2015.
We will continue to evaluate our capital prgoram in the context
of commodity prices, economic conditions, and cost structures and are prepared to make changes to our overall capital spending
plans as necessary.
Production Outlook
We expect daily production will average between 103,000 BOE/day
to 108,000 BOE/day, with a relatively flat profile throughout the year. Using the mid-point of this range, this represents a 2%
increase over our expected 2014 production levels, generally balanced between oil/liquids and natural gas. On a per share basis,
production growth is also expected to be approximately 2%.
Expenses
Our operating costs are expected to be $10.50/BOE for 2015.
This is slightly higher than 2014 due to the impact of a weaker Canadian dollar on our U.S. operating costs, as well as the sale
of lower operating cost non-core Canadian natural gas properties during the fourth quarter of 2014.
Cash G&A expenses are expected to be maintained at $2.30
per BOE.
Royalty costs, including state production taxes and impact
fees, are expected to remain at 23% of revenues net of transportation.
Based upon current commodity prices, we expect to pay cash
taxes of approximately 2% of U.S. funds flow in 2015. We have sufficient tax pools to shelter our Canadian cash flow from material
cash taxes until after 2018.
Hedging
We have a significant amount of our crude oil volumes hedged
at prices well above the current market for the remainder of 2014 and into 2015. For the fourth quarter of 2014, we have approximately
65% of our expected net after royalty crude oil production hedged at a price of US$95.29 per barrel.
In 2015, assuming the midpoint of our guidance range, we have
47% of our expected crude oil production, net of royalties, hedged for the first six months at a WTI price of US$93.58 per barrel.
We also have 24% of our expected net crude oil production hedged for the second half of 2015 at a WTI price of US$93.86 per barrel.
In addition to our crude oil hedges, we have downside protection
at an average NYMEX price of US$4.13/MMbtu on approximately 38% of our forecast 2015 natural gas production after royalties, through
a combination of instruments.
Funding the 2015 Capital Program
We believe that we are well positioned to withstand the recent
commodity price volatility through a reduced capital spending program, strong hedge position and significant credit capacity. We
expect to fund our 2015 capital program and dividend with funds from operations and a modest increase in debt. Assuming no additional
divestments in 2015, debt-to-funds flow is expected to be below 2 times at the end of 2015, if WTI averages US$65/bbl for the full
year (NYMEX US$3.75/MMBtu, AECO at $3.30/GJ, and FX of 1.15).
At the end of December 2014, we expect we will have approximately
$925 million of credit available on our $1 billion bank facility and a trailing 12 month debt-to-funds flow of 1.3 times.
Most of our debt is in the form of long term senior unsecured notes. We have approximately $100 million in term debt due in the
next two years which we expect to roll into new notes or repay with bank debt.
Dividend
The dividend is an important part of our strategy to create
shareholder value. We have no plans to change the dividend. However, we will be monitoring commodity prices and economic conditions
going forward. We are prepared to make adjustments as necessary to the dividend depending on the severity and duration of the downturn.
2015 Forecast Guidance Summary
Our estimates do not include any acquisition or divestment
activities, although divestments continue to be part of our strategy to high-grade our portfolio. Enerplus suspended its Stock
Dividend Program in September 2014 to reduce dilution.
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Capital Spending |
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$635 million |
Annual Average Production |
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103,000 - 108,000 BOE/day |
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% crude oil and natural gas liquids |
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43%-45% |
Operating Costs |
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$10.50/BOE |
Cash General & Administrative Expense |
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$2.30/BOE |
Royalties (including state fees) |
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23% |
U.S. Cash Taxes |
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2% of U.S. cash flow |
Cash Dividends |
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$220 million |
Cash Dividends per share |
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$1.08 |
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2015 Differential/Basis Outlook*
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Mixed Sweet Blend (MSW) |
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US($6.00)/bbl |
Western Canada Select (WCS) |
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US($17.00)/bbl |
U.S. Bakken |
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US($9.00)/bbl |
Marcellus Basis |
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US($1.40)/MMBtu |
* Before field transportation costs. Compared to US$ WTI crude oil and US$ NYMEX gas. |
Electronic copies of our quarterly and annual results, news
releases and 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, BOE, AND OPERATIONAL INFORMATION
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.
See "Non-GAAP Measures" below.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking information
and forward-looking statements within the meaning of applicable securities laws ("forward-looking information").
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: capital expenditures for 2015 and the timing and allocation of such expenditures among our properties
and assets; our anticipated 2014 total capital expenditures; expected 2014 and 2015 average production volumes and growth and the
anticipated production mix; our 2014 and 2015 year-end debt-to-funds flow ratio; bank credit availability at December 31, 2014;
2015 operating, general and administrative and royalty costs; our anticipated U.S. cash taxes payable in 2015, available tax shelter
and the time at which we may pay Canadian cash taxes; our anticipated 2015 drilling program including the anticipated capital spending
for such drilling program among our properties; 2015 capital efficiencies; our expected break even supply costs and internal rates
of return ("IRR") for wells on certain of our properties; anticipated well recovery volumes; and the proportion
of our anticipated oil and gas production that is hedged; the sources available to fund our 2015 capital expenditures; anticipated
future debt levels and the anticipated refinancing of certain debt; our anticipated dividend payment levels; potential acquisition
and divestment activities; future oil and natural gas prices and differentials.
The forward-looking information contained in this news
release reflects several material factors, expectations and assumptions including, without limitation: that we will conduct our
operations and achieve results of operations as anticipated; that our drilling and 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 our reserve and resource volumes; commodity price and cost assumptions;
including those set forth in this news release; the continued availability of adequate debt and/or equity financing and funds flow
to fund our capital, operating and working capital requirements and dividend payments as needed; the continued availability and
sufficiency of our funds flow and availability under our bank credit facility; the availability of third party services; and the
extent of our liabilities. We believe 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 and deviations from anticipated commodity price levels;
changes in realized prices of Enerplus' products; changes in the demand for or supply of our products; unanticipated operating
or drilling results, results from our capital spending activities or production declines; changes in tax or environmental laws,
royalty rates or other regulatory matters; changes in our capital plans or by third party operators of our properties; increased
debt levels or debt service requirements; inaccurate estimation of our 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 and third party service providers; a failure to complete planned asset dispositions on the terms anticipated
or at all; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation,
those risks and contingencies described under "Risk Factors and Risk Management" in our MD&A for the year ended December
31, 2013 and in our other public filings).
The forward-looking information contained in this news
release speaks only as of the date of this news release, and we do not assume any obligation to publicly update or revise such
forward-looking information 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 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 used to analyze leverage and liquidity
and 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 ratio" 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. See disclosure under "Non-GAAP
Measures" in our MD&A for the three and none months ended September 30, 2014 for reconciliation of these measures to the
most directly comparable measures calculated in accordance with U.S. GAAP.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation
%CIK: 0001126874
For further information: Investor Relations at 1-800-319-6462
or email investorrelations@enerplus.com.
CO: Enerplus Corporation
CNW 19:00e 17-DEC-14
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