All financial information contained within this news release has been
prepared in accordance with U.S. GAAP including comparative figures
2013 KEY TAKEAWAYS:
•Funds flow per share grew by 14%•Production grew by 9%, exceeding guidance in spite of non-core asset sales•Proved plus probable reserves were up 17% year-over-year, replacing 284% of 2013 production•Capital spending, operating costs and general and administrative costs were all reduced•Debt to funds flow ratio at year-end improved to 1.4x
4th Quarter 2013:
• Production continued to grow during the fourth quarter of 2013 averaging 94,167 BOE per day, up 7% from the previous quarter and 10% compared to the same period in 2012. Production during the month of December averaged 99,569 BOE per day, ahead of our exit guidance of 95,000 BOE per day. Marcellus production exceeded our expectations, producing 170 MMcf per day during the month of December including the additional working interests acquired in late November. Crude oil and natural gas liquids volumes were virtually unchanged quarter over quarter, despite the sale of 900 barrels per day of crude oil in
• We invested
• Funds flow totaled
• Cash operating costs and general and administrative expenses per BOE were both down compared to the third quarter, averaging
• We closed a number of transactions during the fourth quarter including the acquisition of additional working interests in our Marcellus natural gas properties for
• We also closed the sale of non-core producing assets in
• We delivered annual production growth of 9% in 2013, exceeding both our annual and exit production forecasts for the year. Daily production averaged 89,800 BOE, ahead of guidance of 89,000 BOE per day. Total oil production increased by 5% in 2013 to average 38,250 barrels per day, despite the sale of 2,700 BOE per day of non-core oil production.
• Natural gas production increased by 15% to average 288 MMcf per day for the year, representing 54% of our annual production volumes. Strong well performance in the Marcellus combined with the acquisition of additional working interests in December helped to drive this result.
• Funds flow grew by 17% year-over-year to
• Capital spending came in slightly lower than our forecast of
• We continued to concentrate our portfolio throughout 2013. We sold
• Our capital efficiencies improved again in 2013. Based upon our capital spending and the growth in production volumes from the fourth quarter of 2012 to the same period in 2013, this reflects a capital efficiency of approximately
• With the increase in funds flow, a reduction in capital spending and improved capital efficiencies, our adjusted payout ratio improved to 114% in 2013 including participation in our Stock Dividend Plan ("SDP"). Monthly dividends to shareholders were maintained throughout the year, totaling
• As a result of the growth in funds flow and the net proceeds from our divestment activities, our financial flexibility increased in 2013. Approximately 80% of our bank credit facility was undrawn and our trailing twelve month debt-to-funds-flow ratio fell to 1.4 times at year-end, down from 1.7 times at year-end 2012.
• Our proved plus probable ("2P") company interest reserves increased by 17% at year-end, replacing 284% of our 2013 average daily production.
• Finding and development costs including future development capital ("FDC") were
• Finding, development and acquisition costs, including FDC, were
• The net present value of our future net revenues discounted at 10% before tax increased by 7% in 2013 to approximately
|SELECTED FINANCIAL RESULTS||Three months ended ||Twelve months ended |
|Cash and Stock Dividends||54,665||53,572||216,864||301,560|
|Debt Outstanding - net of cash||1,022,308||1,064,365||1,022,308||1,064,365|
|Property and Land Acquisitions||173,387||121,391||244,837||185,337|
|Debt to Trailing 12 Month Funds Flow||1.4x||1.7x||1.4x||1.7x|
|Financial per Weighted Average Shares Outstanding|
|Weighted Average Number of Shares Outstanding (000's)||202,257||198,256||200,567||195,633|
|Selected Financial Results per BOE(1)(2)|
|Oil & Natural Gas Sales(3)|
|Commodity Derivative Instruments||1.90||2.04||0.81||0.61|
|General and Administrative||(2.28)||(2.34)||(2.54)||(2.61)|
|Share Based Compensation||(1.06)||(0.03)||(0.71)||(0.18)|
|Interest and Other Expenses||(1.51)||(1.45)||(1.71)||(1.42)|
|SELECTED OPERATING RESULTS||Three months ended ||Twelve months ended |
|Average Daily Production(2)|
|Crude oil (bbls/day)||37,731||38,597||38,250||36,509|
|Natural gas (Mcf/day)||315,739||259,904||288,423||251,773|
|% Crude Oil & Natural Gas Liquids||44%||49%||46%||49%|
|Average Selling Price(2)(3)|
|Crude oil (per bbl)|
|NGLs (per bbl)||54.26||47.31||52.25||53.01|
|Natural gas (per Mcf)||3.26||3.01||3.26||2.39|
|Net Wells drilled||18||11||62||75|
|(1)||Non-cash amounts have been excluded.|
|(2)||Based on Company interest production volumes.|
|(3)||Net of oil and gas transportation costs, but before royalties and the effects of commodity derivative instruments.|
|Three months ended ||Twelve months ended |
|Average Benchmark Pricing|
|WTI crude oil (US$/bbl)|
|USD/CDN exchange rate||1.05||0.99||1.03||1.00|
|SHARE TRADING SUMMARY||CDN* - ERF||U.S.** - ERF|
For the twelve months ended ||(CDN$)||(US$)|
* TSX and other Canadian trading data combined.
|2013 DIVIDENDS PER SHARE||CDN$||US$(1)|
|First Quarter Total|
|Second Quarter Total|
|Third Quarter Total|
|Fourth Quarter Total|
|(1)||US$ dividends represent CDN$ dividends converted at the relevant foreign exchange rate on the payment date.|
|2013 PRODUCTION & CAPITAL SPENDING|
|Crude Oil & NGLs (bbls/day)||Q4|
|Total Crude Oil & NGLs (bbls/day)||41,544||41,722||40,413|
|Natural Gas (Mcf/day)|
|Company Total (BOE/day)||94,167||89,793||99,569|
|2013 NET DRILLING ACTIVITY***|
|Total Crude Oil||41.2||.2||41.4||6.3||43.3||-|
* Wells drilled during the year that are pending potential completion/tie-in or abandonment as at
** Total wells brought on-stream during the year regardless of when they were drilled.
*** Table may not add due to rounding.
Our 2013 capital program was focused in our four core areas - the U.S. Bakken/Three Forks, the Marcellus, our Canadian crude oil waterfloods and our deep gas opportunities within the
We continued to invest in the Marcellus throughout 2013, concentrating our drilling activity within the most economic areas in northeastern
Our activities in
RESERVES AND CONTINGENT RESOURCE ASSESSMENT:
Our total 2P reserves increased by over 17% year-over-year, driven by significant reserve additions in the Marcellus and also in our Bakken/Three Forks properties in
In addition to the 2P reserves, an assessment of the additional resource potential within a portion of our asset base has identified 363 MMBOE of economic, best estimate contingent resources ("contingent resources") as of
Our contingent resource assessment includes:
• 39 MMBOE of contingent resources attributable to both the Bakken and Three Forks at Fort Berthold. 18 MMBOE of previously assessed contingent resources were converted to reserves in 2013 and 23 MMBOE of new contingent resources were added primarily associated with the Three Forks formation. This assessment assumes a well density of two wells per drilling spacing unit within the Bakken and two wells per spacing unit within the first bench of the Three Forks formation only. We believe further upside potential may exist through both increased drilling density and also drilling into the lower benches in the Three Forks.
• 59 MMBOE of contingent resources attributable to improved oil recovery ("IOR") and enhanced oil recovery ("EOR") in our Canadian waterflood assets. Approximately 4 MMBOE of previously assessed contingent resources were converted to reserves in 2013.
• 1.3 Tcf of contingent resources associated with our Marcellus natural gas assets. We added approximately 290 Bcf of contingent resources associated with the acquisition of additional working interests and reclassified 258 Bcf of contingent resources to reserves as a result of our successful drilling activity.
• 253 Bcf of contingent resources associated with our Wilrich deep gas assets in
At this time, there has been no assessment of the resource potential within our
We expect to produce an average of 96,000 - 100,000 BOE/day in 2014, an increase of 9% year-over-year or 8% per share using the mid-point of this range. We expect continued growth from our U.S. oil properties at Fort Berthold where we anticipate that average annual production will increase by approximately 30% in 2014, driving our light crude oil volumes to 67% of our total oil production. Total crude oil and natural gas liquids production is expected to increase by approximately 12%. Natural gas production is expected to increase by 7% averaging over 300 MMcf per day with the majority of the growth attributable to the Marcellus. Our U.S. assets are anticipated to account for over 50% of our corporate production volumes in 2014. The production mix is expected to remain at approximately 48% crude oil and natural gas liquids and 52% natural gas although continued outperformance in the Marcellus could push the natural gas share higher.
The improvement in asset quality and operational performance along with our focus on cost reductions and productivity enhancements has resulted in a significant improvement in capital efficiencies across our portfolio. We plan to build on these improvements in 2014 to deliver another year of profitable growth complemented by a meaningful dividend to our investors. Our plans include investing
We continue to hedge a portion of our crude oil and natural gas production in order to provide downside protection to our funds flow estimates. As of
Changes to Board of Directors
We are pleased to announce that Ms.
Live Conference Call
To ensure timely participation in the conference call, callers are encouraged to dial in 15 minutes prior to the start time to register for the event. A podcast of the conference call will also be available on our website for downloading following the event. A telephone replay will be available for 30 days following the conference call and can be accessed at the following numbers:
|1-855-859-2056 (toll free)|
Electronic copies of our 2013 year-end MD&A and Financial Statements, along with 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 firstname.lastname@example.org.
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INFORMATION REGARDING RESERVES, RESOURCES 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).
Presentation of Production and Reserves 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 IFRS and 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
Contingent Resource Estimates
This news release contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. "Contingent resources" are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as ultimate recovery rates, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as "contingent resources" the estimated discovered recoverable quantities associated with a project in the early evaluation stage. All of our contingent resource estimates are economic using established technologies and under current commodity price assumptions used by our independent reserve evaluators.
For additional information regarding the primary contingencies which
currently prevent the classification of our disclosed "contingent
resources" associated with our Marcellus shale gas properties, our Fort
Berthold properties, our Wilrich natural gas properties and a portion
of our Canadian crude oil properties as reserves and the positive and
negative factors relevant to the "contingent resource" estimates, see
our AIF, a copy of which is available under our SEDAR profile at www.sedar.com, and our Form 40-F, a copy of which is available under our EDGAR
profile at www.sec.gov.
See "Non-GAAP Measures" below.
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
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:
The forward-looking information contained in this news release reflects several material factors and expectations and assumptions of
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 realized prices for
The purpose of certain financial outlook information included in this news release, including with respect to our 2014 guidance for funds flow, is to communicate our current expectations as to our performance in 2014. Readers are cautioned that it may not be appropriate for other purposes. The forward-looking information contained in this news release speaks only as of the date of this news release, and none of
In this news release, we use the terms "funds flow", "adjusted payout
ratio", "capital efficiency", "recycle ratio" and "netback" 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. "Adjusted payout ratio" is
calculated as cash dividends to shareholders, net of our stock
dividends and DRIP proceeds, plus capital spending (including office
capital) divided by funds flow. "Capital efficiency" is calculated as
the change in production from the fourth quarter of the previous year
to the fourth quarter of the current year divided by total capital
expenditures from the fourth quarter of the previous year up to and
including the third quarter of the current year. "Netback" is
calculated as oil and gas revenues after deducting royalties, operating
costs and transportation expenses. A "recycle ratio" is calculated as
finding and development costs divided by operating netback.
President & Chief Executive Officer