Enerplus Increases 2013 Production Estimate and Forecasts 10% Production Growth in 2014
This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review the "Cautionary Note Regarding 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. 2, 2013 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) (NYSE: ERF) is pleased to announce that based upon continued strong operational performance during the months of October and November, we are increasing our annual average production forecast for 2013 to 89,000 BOE/day from 87,500 BOE/day. Production volumes during the fourth quarter are expected to average approximately 92,000 BOE/day due primarily to higher natural gas production.
In addition, the Board of Directors of Enerplus has approved the capital program for 2014 which includes the following highlights:
We expect to deliver 10% production growth in 2014, targeting annual
average production between 96,000 BOE/day and 100,000 BOE/day.
Crude oil production is expected to grow by 12%, resulting in a
production mix of 48% crude oil and natural gas liquids and 52% natural
Capital spending is planned at $760 million, up 11% from 2013, with two
thirds of our program directed to crude oil projects.
Based upon our forecast exit volumes, capital efficiencies have
significantly improved in 2013 to under $30,000/BOE/day. We expect to
achieve similar capital efficiencies in 2014.
- We expect a reduction in both operating costs and general and administrative costs per BOE.
Based upon our capital spending plans, we forecast average production in 2014 will range between 96,000 BOE/day and 100,000 BOE/day. The mid-point of this range reflects a 10% increase in production volumes year-over-year and 9% per share. Crude oil and natural gas liquids production is expected to increase by approximately 12%. We expect continued growth from our U.S. oil properties at Fort Berthold where production will increase by roughly 15% in 2014, driving our light crude oil volumes to represent 67% of our total oil production. Natural gas liquids are expected to be approximately 4% of total production. Our total corporate natural gas production is expected to average just over 300 MMcf/day next year, up 7% from 2013, with the majority of the growth attributable to the Marcellus.
As a result of the growth in production from our Bakken/Three Forks and Marcellus properties, over 50% of our corporate production volumes will be attributable to our U.S. assets. Our production mix is expected to remain at 48% crude oil and natural gas liquids and 52% natural gas. With the acquisition of additional interests in the Marcellus combined with the growth in our earlier stage plays in North Dakota and the Wilrich, our corporate production decline rate is expected to marginally increase to 25% in 2014 from 24% in 2013.
We are targeting a capital spending program of $760 million in 2014, up 11% from our 2013 capital forecast of $685 million. We plan to continue to focus our activities on oil projects with two thirds of our budget directed to our Bakken/Three Forks oil projects in the United States and our Canadian oil waterflood properties. The remainder of our budget will be directed to our core natural gas assets in the Marcellus and in the Deep Basin region as we move into development in the Wilrich and continue to evaluate the Duvernay.
The improvement in asset quality within our portfolio and a focused effort on reducing costs and driving operational performance has resulted in a significant improvement in capital efficiencies across our portfolio. Approximately $570 million is expected to be directed to drilling and development activities which we anticipate will deliver growth in production and reserves. We plan to allocate approximately $50 million to exploration and seismic activities.
|2014 Capital Spending Breakdown by Activity||($ millions)|
|Development Drilling & Completions||$570|
|Exploration & Seismic||$50|
The sustainability of our business has improved significantly throughout 2013 as a result of the growth in production volumes and improved capital efficiencies. We expect to build from this improvement in 2014 to deliver another year of profitable growth for our investors. We have recently entered into another agreement to sell $42 million of non-core assets in the U.S. representing approximately 2.5 MMcf/day of natural gas production associated with an over-riding royalty interest which we expect to close in early January. Our balance sheet has been strengthened by our divestment efforts which we expect will generate net proceeds, after acquisitions, of approximately $250 million. This has allowed us to increase our capital spending plans in 2014 while preserving our financial strength. We expect our 2014 adjusted payout ratio will be approximately 120% before any acquisition and divestment activity.
We expect the recent weakness in crude oil differentials could persist into 2014 and that the basis differential in the Marcellus may widen from the levels we realized during the third quarter. Based upon these assumptions and considering the backwardation in the forward crude oil market, funds flow is expected to grow by 3% in 2014 to approximately $775 million.
|2014 Commodity Price & Differentials|
|2014 Commodity Price Outlook*:|
|West Texas Intermediate Crude Oil Price||US$92.80/bbl|
|NYMEX Natural Gas Price||US$3.90/Mcf|
|AECO Natural Gas Price||$3.45/Mcf|
|Mixed Sweet Blend (MSW)||($8.00)/bbl|
|Western Canada Select (WCS)||($25.00)/bbl|
*Forward commodity price outlook as at November 26, 2013. The differential/basis outlook includes the impact of Enerplus' marketing and transportation arrangements.
Core Asset Activity
Our crude oil assets in the U.S. will continue to attract the largest percentage of our 2014 capital budget with $300 million to $325 million allocated to this core area. The majority of our spending is planned in the Fort Berthold region where we expect to continue running a two rig program targeting both the Bakken and the Three Forks. Approximately 20 net wells are expected to be drilled, completed and tied-in. During the fourth quarter of 2013, we drilled the first three wells of a seven well pad designed to test downspacing in the area. We also commenced drilling into the lower benches of the Three Forks to test the prospectivity of the lower zones.
Our low decline rate Canadian waterflood properties will continue to be an active part of our capital investment program. We plan to increase spending to approximately $160 million to $200 million in 2014 with a focus on drilling activities, advancement of our polymer projects at Giltedge and Medicine Hat and the implementation of new waterflood projects in Saskatchewan.
Capital spending in the Marcellus is expected to increase in 2014, ranging from $110 million to $130 million as a result of the additional working interests acquired in November 2013. Our spending will be focused in Bradford, Sullivan and Susquehanna counties where we have seen strong well performance throughout 2013. Based upon results to date, expected ultimate recoveries in these areas to range from 10 Bcf to over 13 Bcf of natural gas per well and provide compelling economics in the current natural gas price environment.
We plan to continue development of our assets in the Deep Basin region. We expect to continue our program in the Wilrich with 3 to 5 wells planned for the Ansell/Minehead area. We will also continue to advance our delineation activities in the Duvernay, completing one horizontal well drilled in late 2013 and drilling and completing another horizontal well early in 2014.
We expect continued improvement in both operating costs and general and administrative costs in 2014. Operating costs are expected to average $10.25/BOE, down 4% from 2013. General and administrative expenses and cash equity based compensation are also expected to decrease, averaging $2.45/BOE and $0.25/BOE, down 9% and 58% respectively. We expect our average royalty rate will increase slightly to 23.5% of revenues due to the increase in production associated with our U.S. operations which have higher royalty rates and state fees than our Canadian operations. We have sufficient tax pools to shelter our cash flow in Canada for at least the next two years, and we forecast U.S. cash taxes of 3% to 5% of U.S. cash flows over the next two years.
With the current crude oil price, over 75% of our expected 2014 funds flow will be derived from the sale of our crude oil and liquids production. As a result, our hedging strategy continues to be directed at protecting our oil volumes. We have approximately 51% of our expected 2014 oil volumes hedged, net of royalties, at a WTI price of US$93.28/bbl. We also have 27% of our expected 2014 natural gas production, net of royalties, hedged at a NYMEX price of US$4.14/Mcf and an additional 2% of our net natural gas production hedged at an AECO price of $3.96/Mcf.
|2014 Forecast Guidance Summary*|
|Capital Spending||$760 million|
Annual Average Production
96,000 - 100,000 BOE/day
|General & Administrative Expense||$2.45/BOE|
|Cash Equity Based Compensation Expense||$0.25/BOE|
|Royalties (including state fees)||23.5%|
|U.S. Cash Taxes||3 - 5% of U.S. cash flow|
|Cash Dividends||$220 million|
|Cash Dividends per share||$1.08|
|Funds Flow||$775 million|
|Funds Flow per Share||$3.81|
|Adjusted Payout Ratio||120%|
Based upon forward commodity prices, forecast costs and the Enerplus share price as of November 26, 2013 including the impact of hedging and does not include any acquisition or divestment activities not currently announced. Adjusted payout ratio is calculated as the sum of dividends paid to shareholders, net of participation in the Stock Dividend Plan plus capital expenditures divided by funds flow. See "Non-GAAP Measures" at the end of this release.
Est. effect on 2014
|Change of $5.00/bbl WTI crude oil||$0.15|
|Change of $0.50/Mcf NYMEX natural gas||$0.14|
|Change of 1,000 BOE/day production||$0.05|
|Change of $0.01 in the US$/CDN$ exchange rate||$0.05|
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INFORMATION REGARDING FINANCIAL AND OPERATIONAL INFORMATION
Currency and Production Amounts
All amounts in this news release are stated in Canadian dollars unless otherwise specified. All production volumes are presented on a company interest basis, being the Company's working interest share before deduction of any royalties paid to others plus the Company's royalty interests. Company interest is not a term defined in Canadian National Instrument 51-101- Standards of Disclosure for Oil and Gas Activities) and may not be comparable to information produced by other entities.
Barrels of Oil Equivalent and Cubic Feet of Gas 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.
See "Non-GAAP Measures" below.
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: achievement of operational targets for 2013; Enerplus' expected operating and general and administrative costs and oil and natural gas production volumes for 2013; our average realized crude oil and natural gas prices and future differentials; the proportion of our anticipated oil and natural gas production that is hedged; Enerplus' financial capacity to support capital spending plans and its dividend; potential asset divestments and acquisitions and the impact of such on our 2013 production; future efficiencies and reserves and production growth from capital spending; future capital and development expenditures and the allocation thereof among our assets; future development and drilling locations, plans and costs; the performance of and future results from Enerplus' assets and operations, including anticipated production levels, decline rates and future growth prospects; the potential change of our status from "foreign private issuer" to U.S. domestic issuer as of January 1, 2014 and expected changes in our reporting related thereto; and our ability to improve our trading multiple and create significant value for 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' operations and development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions, including third party costs; the continuation of assumed tax, royalty and regulatory regimes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing, cash flow and other sources to fund Enerplus' capital and operating requirements as needed; the continued availability and sufficiency of our funds flow and availability under our bank credit facility to fund our working capital deficiency; the extent of its liabilities; and that Enerplus will be able to complete planned asset sales. 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 reserves and resources volumes; limited, unfavourable or a lack of access to capital markets; an inability to complete planned asset sales and acquisitions; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners; 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 for the year ended December 31, 2012, filed on SEDAR and EDGAR, respectively, on February 22, 2013).
The forward-looking information contained in this news release speaks only as of the date of this news release, and none of Enerplus or its subsidiaries assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
In this news release, we use the term "adjusted payout ratio" to analyze operating performance, leverage and liquidity. We calculate "adjusted payout ratio" as cash dividends to shareholders, net of our stock dividends (and for 2012 comparative purposes, our DRIP proceeds), plus capital spending (including office capital) divided by funds flow.
Enerplus believes that, in addition to net earnings and other measures prescribed by IFRS, the term "adjusted payout ratio" is a useful supplemental measure as it provides an indication of the results generated by Enerplus' principal business activities. However, this measure is not recognized by GAAP and does not have a standardized meaning prescribed by IFRS. Therefore, this measure, as defined by Enerplus, may not be comparable to similar measures presented by other issuers.
SOURCE Enerplus Corporation