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Enerplus Announces 2015 Guidance: Reduced Spending, Continued Financial Flexibility and Restrained Growth

December 17, 2014

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.


  • 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.



2015 Capital Spending


 $ millions

Development Drilling & Completions











2015 Development Drilling & Completions


$ millions

Ft. Berthold North Dakota


Canadian Crude Oil & Waterfloods



Total crude oil spending





Canadian Deep Basin



Total natural gas spending






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 program 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%.


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. 


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.


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.


Capital Spending


$635 million

Annual Average Production


103,000 - 108,000 BOE/day


% crude oil and natural gas liquids



Operating Costs



Cash General & Administrative Expense



Royalties (including state fees)



U.S. Cash Taxes


2% of U.S. cash flow

Cash Dividends


$220 million

Cash Dividends per share




2015 Differential/Basis Outlook*


   Mixed Sweet Blend (MSW)



   Western Canada Select (WCS)



   U.S. Bakken



   Marcellus Basis



* 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 For further information, please contact Investor Relations at 1-800-319-6462 or email

Follow @EnerplusCorp on Twitter at


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.


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.


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

For further information: Investor Relations at 1-800-319-6462 or email

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