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Enerplus Announces 2012 Capital Spending Program

January 17, 2012

Jan 17, 2012

CALGARY, Jan. 17, 2012 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) (NYSE: ERF) is pleased to announce an $800 million capital spending program for 2012 that we expect will generate significant growth in production, reserves and cash flow.

"Over the past few years we have had tremendous success repositioning our company and introducing significant growth opportunities to our portfolio.  Building on the success of our 2011 activities and given the attractive opportunities available in our portfolio, we are planning a level of spending that we expect will deliver production growth of over 10% in 2012", says Gordon Kerr, President & Chief Executive Officer.  "We realize the dividend is important to our investors and currently do not plan to make any changes to it. We believe our financing plans will allow us to continue to support our growth and income strategy while maintaining our financial flexibility during this period of weak natural gas prices."

2012 Capital Program Highlights:

  • We plan to spend $800 million on exploration and development projects in 2012 with over 70% of our spending focused on oil and liquids rich natural gas projects. Our natural gas spending is expected to be focused primarily in the Marcellus on drilling to delineate and retain leases. We expect to invest close to 40% of our capital in light crude oil development at Fort Berthold, North Dakota.
  • We expect to deliver annual average production growth of over 10% in 2012. We are forecasting average production of approximately 83,000 BOE/day during 2012 growing to approximately 88,000 BOE/day as we exit the year.
  • With the current forward commodity price outlook along with the impact of our hedging program, we expect cash flow to increase significantly in 2012. This increase is the result of a growth in our total production volumes and in particular, increasing crude oil and liquids volumes.
  • We expect annual oil production to grow by approximately 7,000 BOE in 2012 with the majority of this growth coming from North Dakota. We expect our average crude oil and liquids production will increase from 45% of total production in 2011 to approximately 50% in 2012.
  • We plan to minimize spending on our operated dry gas projects given the current outlook for natural gas prices however we intend to continue to invest alongside our partners in the Marcellus as they drill to delineate and retain leases. We have allocated approximately $190 million on both our operated and non-operated leases and expect production will grow from 25 MMcf/day currently to over 70 MMcf/day as we exit 2012. Our Canadian conventional dry gas production is expected to decline throughout the year while our Marcellus gas production is expected to represent approximately 30% of our total corporate natural gas volumes by year end.
  • Through a disciplined exploration program, we plan to invest close to $100 million to unlock the value in our prospective undeveloped land base in the Duvernay, Montney, and Cardium plays and in our operated acreage in the Marcellus as well as advancing our enhanced oil recovery projects. This spending is not expected to contribute significant new production in 2012 although we expect it will set the stage for future production and reserve additions.
  • The majority of our planned capital spending will be focused on our operated properties with approximately 85% of our capital program directed to drilling and completion activities. In total we expect to drill approximately 108 net wells with approximately 95 net wells coming on-stream throughout the year.  Virtually all of the wells planned in 2012 will be horizontal wells.
  • Based upon exit production growth, we expect to see an improvement in capital efficiencies in the range of $30,000 - $35,000/BOE/day, including spending on exploration activities. The low decline rate associated with our waterflood and enhanced oil recovery projects is helping to offset the impact of increased horizontal drilling activity to our corporate decline rate. We expect our corporate decline rate to increase from approximately 21% currently to 23% by year end.
  • Over and above our capital spending program, we plan to invest approximately $40 million in the acquisition of new undeveloped land. We expect to fund a portion of these expenditures through the sale of non-core properties with limited production and have signed a sale agreement for half of this amount.

Funding Strategy

  • We currently have downside protection on approximately 64% of our anticipated net oil production (after royalty volumes) at an average floor price of US$96.22/bbl for 2012.  For calendar 2013, we currently have 5% of our expected net oil production hedged at an effective price of US$102.08/bbl.  Given the weak outlook for natural gas prices, we currently have no hedges in place for our natural gas production.
  • Despite anticipated cash flow growth in 2012 as a result of increasing production, our capital spending program and dividends are expected to exceed cash flow.  We plan to fund the shortfall through debt and equity financing including estimated proceeds from the Dividend Reinvestment Program ("DRIP") program of approximately $70 million. In addition, we continue to hold a portfolio of equity investments that we may sell to help fund capital spending or acquisitions.
  • In the first half of 2012, we plan to expand our DRIP to make it available to our U.S. investors.  Approximately 65% of the total shares currently outstanding are held by U.S. residents.
  • We intend to continue to distribute a meaningful portion of our cash flow to shareholders and have no current plans to reduce our dividend rate of $0.18/share/month.  As always, we will continue to evaluate dividend levels with respect to cash flow, debt levels, capital spending, commodity prices and market conditions.

2012 Capital Spending Breakdown

($ millions)
Development Drilling & Completions 600
Plant/Facilities 70
Maintenance 30
Exploration & Seismic 100
Total $800

2012 Production Outlook

2011E vs 2012E
Annual Production
% Change
Crude Oil (bbls/day) 37,200 40,500 +23
Natural Gas Liquids (bbls/day) 3,800 4,100 +15
Natural Gas (Mcf/day) 252,000 260,000 +0
Total (BOE/day) 83,000 88,000 +10

Tight Oil

Our Tight Oil resource play continues to be the most significant area of investment for Enerplus attracting over 40% or $350 million of our planned 2012 capital budget.  Production is expected to grow by approximately 30% from 17,000 BOE/day exiting 2011 to approximately 22,000 BOE/day exiting 2012.

We plan to spend the majority of our tight oil capital budget at Fort Berthold in Dunn and McKenzie counties in North Dakota.  We plan to spend approximately $300 million drilling 27 net horizontal wells, 90% of which will be long horizontal wells with 3 to 4 drilling rigs working in the play during the year.  Our Bakken well results have typically outperformed our expectations throughout 2011, and as a result, we are increasing our recovery estimates for a long Bakken lateral well in this area to 800,000 BOE/well (previously 600,000 - 800,000 BOE/well) based upon drilling two wells per spacing unit. Through the latter part of 2011, we experienced an escalation in our drilling and completion costs in large part due to the high activity levels in the region. As a result, we now expect long horizontal wells will cost on average $10 million including drilling, completion and tie-in.  Despite this cost increase, with our increased estimate of recoveries, we continue to see attractive rates of return in this region of over 60% based upon current commodity prices.

Crude Oil Waterfloods

We believe our waterflood portfolio offers significant drilling, optimization and enhanced oil recovery opportunities with attractive economics.  With a low base decline rate of approximately 12%, these properties provide a counterbalance to our new growth properties and help to mitigate the escalation of our overall corporate decline rate. In 2012, we intend to invest approximately $150 million, or 46% of the cash flow generated by these properties, to maintain production.  We plan to direct $85 million to drilling/completions/injector conversion activities, $58 million on plant/facilities/maintenance, and $7 million on our enhanced oil recovery projects at Giltedge and Medicine Hat.

Marcellus Gas

We plan to spend approximately $190 million in the Marcellus region in 2012, with approximately 80% allocated to our partner-operated activity in the northeast area of Pennsylvania.  Despite the low natural gas price environment, we plan to invest with our partners to retain this valuable acreage. Well results in northeast Pennsylvania have continued to surpass our expectations in terms of both initial production rates and declines. Well costs in this region are currently averaging $7 million to $8 million per well.  We plan to direct approximately $40 million to drilling appraisal wells on our operated leases in Pennsylvania where we are focused on demonstrating the potential in these areas. In total we expect to participate in drilling approximately 20 net wells in the Marcellus with approximately 18 net wells on-stream in 2012. Our total Marcellus production is expected to grow from 25 MMcf/day at the end of 2011 to over 70 MMcf/day as we exit 2012.

Liquids Rich Natural Gas

As a result of drilling success in 2011, we expect to continue to invest in liquids rich natural gas drilling in Alberta and British Columbia in 2012.  We plan to spend approximately $80 million on development drilling in the Stacked Mannville and to delineate our Montney and Duvernay acreage positions.

Debt Financing

We continue to have a strong balance sheet and financial flexibility.   At September 30, 2011, we had $735 million in unutilized credit capacity on our $1 billion bank credit facility and a trailing 12-month debt to funds flow ratio of 1.3 times.

In 2010, we voluntarily reduced our syndicated bank credit facility from $1.4 billion to $1 billion in response to increased bank fees for unused credit capacity.   We believe we have the ability to increase this bank facility or alternatively, to issue additional long-term debt in the private placement market.

Royalties, Operating Costs and General & Administrative Costs

Royalties in 2012 are expected to average 21% of gross production, up from 2011 as a result of proportionately more production from the U.S. which has a comparatively higher royalty regime.

2012 operating costs are expected to increase to $10.40/BOE as a result of wage escalation, rising Alberta power costs and water handling costs in the U.S.

General and administrative costs in 2012 are expected to remain in line with our 2011 estimates at $3.25/BOE on a cash basis and $3.55/BOE including cash and non-cash items (mostly stock options).


We do not expect to pay material cash taxes in Canada until after 2015 as we estimate we have sufficient tax pools to offset our taxable income prior to that time.  We expect to pay U.S. cash taxes of approximately 5% of U.S. cash flows in 2012.  The U.S. taxes are comprised mainly of Alternative Minimum Tax that can be used to offset future taxes.  These tax forecasts will be based on current commodity prices and capital spending plans and do not take into account any future acquisitions or divestment activities. We also have sufficient Canadian capital loss tax pools to shelter any estimated capital gains tax related to the sale of our equity investment portfolio.

Summary 2012 Guidance Target
Average annual production 83,000 BOE/day
Exit rate 2012 production 88,000 BOE/day
2012 production mix 50% oil, 50% gas
Average royalty rate 21%
Operating costs $10.40/BOE
G&A costs $3.55/BOE
Average interest and financing costs 6%
Development capital $800 million
Marcellus carry commitment $33 million
Undeveloped land acquisitions $40 million


Currency, BOE and Operational Information

All dollar amounts or references to "$" in this news release are in Canadian dollars unless specified otherwise.  Enerplus has adopted the standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may be misleading particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does 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. Unless otherwise stated, all oil and gas production information and estimates are presented on a gross basis, before deducting royalty interests.

Cautionary Note Regarding Forward-Looking Information and Statements

This news release contains certain forward-looking information and statements (collectively, "forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "budget", "guidance", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "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 and statements pertaining to the following: future capital spending amounts (including capital carry commitments), the timing and locations of such spending and the types of projects on which such capital will be spent; future growth in production, reserves and cash flow and other anticipated growth opportunities; a financing strategy to fund anticipated capital expenditures, including completion of equity and/or debt offerings and funds raised from our DRIP (including the future availability of our DRIP to our U.S. investors); future oil, natural gas liquids and natural gas prices and production levels (including anticipated 2012 average daily and exit production rates), the product mix and sources of such production, and production decline rates; future drilling activities and results and undeveloped land acquisitions; future capital efficiencies, corporate netbacks and cash flow levels; rates of return from our investments; the expected ultimate recovery of oil or gas from a particular well; well drilling costs, operating costs, general and administrative expenses and royalty expenses; sales of our equity portfolio and our non-core properties and the redeployment of proceeds realized therefrom; dividend payments made by Enerplus and the related adjusted payout ratio; the timing and payment of future taxes; our planned commodity risk management program; and future liquidity, debt levels and financial capacity and resources.

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 achieve operational, production and drilling results as anticipated; anticipated production decline rates; the general continuance of current or, where applicable, assumed industry conditions; commodity prices will remain within Enerplus' expected range of forecast prices, being the current forward market prices; availability of adequate cash flow, debt and/or equity sources to fund Enerplus' capital and operating requirements as needed and to pay dividends to shareholders as anticipated; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; availability of willing buyers for the investments and properties proposed to be disposed of; that capital, operating, financing and third party service provider costs will not exceed Enerplus' current expectations; availability of third party service providers (including drilling rigs and service crews) and cooperation of industry partners; certain foreign exchange rate and other cost assumptions; and that all conditions and approvals necessary to complete anticipated financing activities will be satisfied or obtained. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable at this time 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; unanticipated operating or drilling results or production declines; potential redeployment of available funding to alternative projects; changes in tax or environmental laws or royalty rates; failure to receive required regulatory or third party approvals or to satisfy conditions required for financings; increased debt levels or debt service requirements; insufficient available cash to pay dividends as currently anticipated; inaccurate estimation of or changes to estimates of Enerplus' oil and gas reserve and resource volumes and the assumptions relating thereto; limited, unfavourable or no access to debt or equity capital markets; increased costs and expenses; a shortage of third party service providers; the impact of competitors; reliance on industry partners; an inability to agree to terms with potential buyers of investments or assets that may be disposed of; and certain other risks detailed from time to time in Enerplus' public disclosure documents including, without limitation, those risks identified in our MD&A for the year ended December 31, 2010 and in Enerplus'  Annual Information Form dated March 11, 2011 for the year ended December 31, 2010, copies of which are available on Enerplus' SEDAR profile at and which also form part of Enerplus' annual report on Form 40-F for the year ended December 31, 2010 filed with the United States Securities and Exchange Commission, a copy of which is available at

The forward-looking information contained in this news release speaks only as of the date of this news release, and Enerplus assumes no obligation to publicly update or revise such information to reflect new events or circumstances, except as may be required pursuant to applicable laws.

Any financial outlook or future oriented financial information in this news release, as defined by applicable securities legislation, has been approved by management of Enerplus. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management's reasonable expectations as to the anticipated results of its proposed business activities for 2012. Readers are cautioned that reliance on such information may not be appropriate for other purposes. 

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