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Enerplus Delivers Production Growth Through Second Quarter 2012

August 10, 2012

Aug 10, 2012

All financial figures are unaudited and in Canadian dollars (CDN$) unless noted otherwise.  All financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS").

This news release includes forward-looking statements and information within the meaning of applicable securities laws.  Readers are advised to review "Forward-Looking Information and Statements" at the conclusion of this news release.  Readers are also referred to "Notice to U.S. Readers" and "Non-GAAP Measures" at the end of this news release for information regarding the presentation of the financial and operational information in this news release.  A full copy of our 2012 Second Quarter Financial Statements and MD&A have been filed on our website at under our profile on SEDAR at and on the EDGAR website at

CALGARY, Aug. 10, 2012 /CNW/ - Enerplus Corporation ("Enerplus" or the "Corporation") (TSX: ERF) (NYSE: ERF) is pleased to announce the results for the second quarter of 2012. Highlights of the quarter were as follows:

  • Our operations delivered another quarter of growth with production averaging 82,108 BOE/day during the second quarter, up approximately 4% over our average volumes for the first quarter of 2012 and up almost 9% over the same period last year.

  • Total crude oil volumes increased by 7% in the second quarter over the first quarter, with light oil production from Fort Berthold increasing by almost 35%.  Our light and medium crude oil now represents 76% of our total oil production, an improvement from 72% last year at this time. Total crude oil and natural gas liquids now represent 49% of our production volumes, a 6% increase over the second quarter of 2011.  Our Canadian natural gas production declined quarter over quarter as expected due primarily to the limited capital investment in our conventional and shallow gas assets. However, our gas production volumes in the Deep Basin region were higher as a result of our drilling success in the Ansell area earlier this year.

  • We invested $209 million in exploration and development capital during the second quarter.  Approximately 80% of this spending was focused on our crude oil resource plays, specifically at Fort Berthold in the U.S. and on our waterflood assets in Canada. The bulk of our natural gas spending was focused in the Marcellus with our non-operated partners as we continued to focus on lease retention in the region.

  • A total of 18.7 net wells were drilled during the quarter, of which approximately 75% were oil wells.  A total of 18.4 net wells were brought on stream, 67% of which were oil.

  • Funds flow was approximately $147 million during the quarter ($0.74 per share), down 10% from the first quarter of 2012.  Our growing production as well as our crude oil hedges helped offset the impact of lower commodity prices and wider crude oil differentials during the quarter. Our oil hedging program added $1.50/bbl of cash gains to our realized crude oil pricing during the quarter.

  • Our trailing twelve month debt to funds flow ratio was 2.0x at June 30, 2012 and we had $680 million available on our $1 billion bank credit facility.

  • Operating costs were on track with expectations averaging $10.78/BOE for the second quarter and general and administrative costs (including equity based compensation) at $2.81/BOE were lower than expected due to lower costs associated with our long-term incentive plans.

  • We continued to protect our balance sheet throughout the quarter in response to the further decline in natural gas prices as well as the sharp decline in crude oil prices. In May we closed a $405 million private placement of long-term, senior unsecured notes, the proceeds of which were used to reduce borrowings under our bank credit facility. These notes have terms ranging from seven to twelve years with attractive interest rates of approximately 4.4%.

  • A Stock Dividend Program ("SDP") was implemented in June to allow all of our shareholders the option to elect to receive shares instead of a cash dividend.  We believe this program will provide an additional source of funding for our capital investment strategies.

  • As a result of lower cash flow expectations due to the drop in commodity prices, we elected to reduce our monthly dividend from $0.18/share to $0.09/share commencing with our July dividend. We believe this reduction was necessary in order to strike a better balance between yield and growth for our investors and also preserve financial flexibility going forward.

  • We have 18,500 bbls/day of oil production hedged at US$96.17/bbl for the remainder of 2012 and 14,500 bbls/day of oil production hedged at US$101.36/bbl for 2013. In response to the recent increase in natural gas prices, we've started to add hedge positions on our natural gas production for 2013, purchasing put protection which allows us to retain the upside price on approximately 23 MMcf/day of natural gas production hedged at $3.17/Mcf.

  • We continue to progress on our plans for the partial sale and/or monetization of a portion of our early stage asset portfolio which includes the Duvernay, Montney and operated Marcellus.  We have retained a financial advisor and are actively marketing these assets.  In addition, our plans also include selling a portion of our equity portfolio and other non-core producing assets to help maintain our financial flexibility.


  Three months ended June 30, Six months ended June 30,
  2012 2011 2012 2011
Financial (000's)        
  Funds Flow $146,547 $132,441 $309,253 $293,665
  Cash and Stock Dividends 88,599 97,077 194,594 193,763
  Net Income 100,264 267,982 66,443 297,531
  Debt Outstanding - net of cash 1,152,746 460,087 1,152,746 460,087
  Capital Spending 208,587 145,165 525,653 319,609
  Property and Land Acquisitions 23,649 94,415 56,669 142,633
  Divestments (87) 571,096 52,524 630,788
  Debt to Trailing 12 Month Funds Flow 2.0x 0.7x 2.0x 0.7x
Financial per Weighted Average Shares Outstanding        
  Funds Flow $0.74 $0.74 $1.60 $1.64
  Net Income 0.51 1.50 0.34 1.66
  Weighted Average Number of Shares Outstanding 196,768 179,583 193,306 179,209
Selected Financial Results per BOE(1)        
  Oil & Gas Sales(2) $42.07 $51.62 $44.51 $49.28
  Royalties (8.36) (9.07) (8.80) (8.85)
  Commodity Derivative Instruments 0.68 (3.03) (0.38) (1.30)
  Operating Costs (10.80) (9.86) (10.32) (9.37)
  G&A and Equity Based Compensation (2.57) (3.16) (2.83) (3.21)
  Interest and Other Expenses (0.90) (0.89) (0.81) (1.82)
  Taxes (0.51) (6.30) (0.31) (3.22)
  Funds Flow $19.61 $19.31 $21.06 $21.51

  Three months ended June 30, Six months ended June 30,
  2012 2011 2012 2011
Average Daily Production        
  Crude oil (bbls/day) 36,527 29,330 35,300 29,831
  NGLs (bbls/day) 3,393 3,442 3,698 3,337
  Natural gas (Mcf/day) 253,126 255,665 249,905 253,584
  Total (BOE/day) 82,108 75,383 80,649 75,433
  % Crude Oil & Natural Gas Liquids 49% 43% 48% 44%
Average Selling Price(2)        
  Crude oil (per bbl) $ 74.36 $90.92 $ 79.93 $84.23
  NGLs (per bbl) 60.11 66.20 58.30 63.35
  Natural gas (per Mcf) 2.06 3.86 2.17 3.88
  USD/CDN exchange rate 1.01 0.97 1.01 0.98
Net Wells drilled 19 14 53 40
(1)  Non-cash amounts have been excluded.
(2)  Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.

Share Trading Summary CDN* - ERF U.S.** - ERF
For the three months ended June 30, 2012 (CDN$) (US$)
High $22.57 $22.78
Low $11.67 $11.35
Close $13.08 $12.87
* TSX and other Canadian trading data combined.
** NYSE and other U.S. trading data combined.

2012 Dividends Per Share(2)    
Payment Month     CDN$ US$(1)
First Quarter Total     $0.54 $0.54
April      $0.18 $0.18
May     0.18 0.17
June     0.18 0.18
Second Quarter Total     $0.54 $0.53
Total Year-to-Date     $1.08 $1.07
(1)   US$ dividends represent CDN$ dividends converted at the relevant foreign exchange rate on the payment date.
(2)  The dividend has been reduced to $0.09 per share effective for the July 20, 2012 payment.

  Three months ended
June 30, 2012
Six months ended
June 30, 2012
Play Type Average
($ millions)
($ millions)
Tight Oil (BOE/day) 18,329 $139 16,986 $301
Crude Oil Waterflood (BOE/day) 16,953 27 16,539 70
Conventional Oil (BOE/day) 4,883 2 4,840 14
Total Crude Oil (BOE/day) 40,165 $168 38,365 $385
Marcellus Shale Gas (Mcfe/day) 36,868 29 32,493 90
Other Natural Gas (Mcfe/day) 214,790 12 221,209 51
Total Gas (Mcfe/day) 251,658 $41 253,702 $141
Company Total 82,108 $209 80,649 $526

Net Drilling Activity - for the three months ended June 30, 2012

Play Type Horizontal
Dry &
Tight Oil 7.2 - 7.2 7.2 8.0 -
Crude Oil Waterflood 5.8 1.0 6.8 6.8 4.4 -
Conventional Oil - - - - - -
Total Crude Oil 13.0 1.0 14.0 14.0 12.4 -
Marcellus Shale Gas 3.5 - 3.5 3.5 3.0 -
Other Natural Gas 1.2 - 1.2 0.2 3.0 -
Total Gas 4.7 - 4.7 3.7 6.0 -
Company Total 17.7 1.0 18.7 17.7 18.4 -
* Wells drilled during the quarter that are pending potential completion/tie-in or abandonment
** Total wells brought on-stream during the quarter regardless of when they were drilled


Tight Oil - Fort Berthold, ND

Production from the Fort Berthold region continued to increase through the second quarter as planned. We spent $138 million on development capital, drilling 7.0 net wells and bringing 8.0 net wells on-stream. Production averaged 11,700 BOE/day, up almost 35% from 8,700 BOE/day during the first quarter of this year and slightly ahead of expectations.

We continued to pursue measures to control our costs in the Fort Berthold region. Operated spending continues to be ahead of budget as we have not been able to see a meaningful reduction in well costs year-to-date. As part of our effort to manage costs, we have eliminated our two least efficient operated drilling rigs and are now running two rigs which we expect will effectively execute the remainder of our operated 2012 capital program. Non-operated activity has also increased significantly as our partners are drilling more than we originally anticipated.  In conjunction with our drilling activities, infrastructure build-out (compression, metering and pipelines) in the region has continued at a brisk pace as we tie-in more wells and capture the associated natural gas volumes, thereby reducing our emissions. We originally expected to fund this tie-in activity through a mid-stream third party however we have been funding these capital costs directly year-to-date. We continue to evaluate fee-based arrangements for the tie-in capital linked to the gathering agreements now in place. We now have approximately 66% of our wells connected to pipeline.

We expect spending to moderate in the second half of 2012. Year-to-date, we've drilled 16.5 net horizontal wells at Fort Berthold, 82% of which have been long horizontals.

Crude Oil Waterfloods

Production from our waterflood properties grew by 5% quarter over quarter as a result of our development activities. Despite wet conditions through spring break-up at our Medicine Hat waterflood property, we were able to complete our plans on our polymer project and began injecting polymer into five injector wells in the latter part of May.  We also drilled 2.9 net producer wells and 1.4 net injector wells at Medicine Hat as part of our on-going waterflood optimization program. Production from this field was up 20% over the first quarter and is currently producing at the highest volume achieved since 1997.  We also restarted our drilling program in southeast Saskatchewan targeting the Ratcliffe with two horizontal wells brought on stream during the quarter.


We continued to invest with our non-operated partners in the Marcellus during the second quarter spending $29 million and participating in drilling 3.5 net wells with 3.0 net wells brought on-stream.  Our capital program has been designed to maximize lease retention in this region throughout 2012.  Some of our partners have slowed completion and tie-in activities including reducing the number of frac stages per well, in an effort to preserve capital. As a result of these activities, we believe production may be lower than originally expected in the latter half of the year exiting 2012 at approximately 60 MMcf/day compared to our original estimate of 70 MMcf/day. Our Marcellus production increased to 37 MMcf/day in the second quarter.

Update on 2012 Guidance

We continue to manage spending levels throughout our operations in order to offset higher spending in the Fort Berthold region.  While we expect capital spending to be lower in the second half of 2012, the increased capital expenditures at Fort Berthold have increased our overall capital spending program for 2012. We now expect full year capital expenditures to be approximately $850 million, up from our original estimate of $800 million. 

We are increasing our annual average production guidance from 83,000 BOE/day to 83,500 BOE/day however we are maintaining our exit production guidance of 88,000 BOE/day. The additional spending at Fort Berthold is expected to add oil production to our exit volumes, however we expect this will be offset by lower production associated with slower completion and tie-in activity in the Marcellus region.  We continue to expect our oil and liquids production weighting to be approximately 50% as we exit 2012. We are maintaining our guidance for full year operating costs at $10.40/BOE however, general and administrative costs are now expected to average $3.30/BOE down from our previous forecast of $3.55/BOE due to reduced costs associated with our long-term incentive programs.


I am very pleased with the progress we continue to make on the operational front. We are increasing production quarter over quarter and have successfully shifted our production mix to be close to 50% crude oil and natural gas liquids. Although weaker commodity prices and widening differentials have presented challenges for ourselves and the industry in general, we've taken a number of steps to manage our balance sheet and continue to pursue additional funding sources to help improve our liquidity beyond 2012.  Based upon our success and the outlook for commodity prices, we will adjust our growth targets and capital spending levels as needed in order to ensure we have sufficient liquidity and deliver a competitive return to our investors.

I am also pleased to announce that Mr. Chris Stephens has been promoted to the position of Vice-President, Canadian Assets.  Mr. Stephens is accountable for the implementation of the Canadian asset strategy and performance and has been with Enerplus since June of 2008.  In addition, Mr. Gordon Love has been promoted to the position of Vice-President, Technical and Operations Services and will oversee our services and field operations in Canada as well as Facility Asset Management and Supply Chain Management for both our U.S. and Canadian operations. Mr. Love joined Enerplus in 2010.  Both Mr. Stephens and Mr. Love report to Mr. Ray Daniels, Senior Vice-President of Operations for Enerplus.

Gordon J. Kerr
President & Chief Executive Officer
Enerplus Corporation


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 United States or other foreign disclosure standards. Reserves categories such as "proved reserves" and "probable reserves" may be defined differently under Canadian requirements than the definitions contained in the United States Securities and Exchange Commission (the "SEC") rules. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments. Canadian disclosure requirements require that forecasted commodity prices be used for reserves evaluations, while the SEC mandates the use of an average of first day of the month price for the 12 months prior to the end of the reporting period.


This news release also contains references to "BOE" (barrels of oil equivalent) and "cfe" (cubic feet of gas 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, and one barrel of oil to six thousand cubic feet of gas (1 bbl: 6 Mcf) when converting oil to cfes. BOEs and cfes 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 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. 

Flow test results and initial production rates: A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been done. Test results and initial production rates disclosed herein may not necessarily be indicative of long-term performance or of ultimate recovery.


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: Enerplus' strategy to deliver both income and growth to investors and Enerplus' related asset portfolio; future capital and development expenditures and the timing and allocation thereof among our resource plays and assets; future development and drilling locations and plans; the performance of and future results from Enerplus' assets and operations, including anticipated production levels and decline rates; future growth prospects, acquisitions and dispositions; the volumes and estimated value of Enerplus' oil and gas reserves and contingent resource volumes and future commodity price and foreign exchange rate assumptions related thereto; the life of Enerplus' reserves; the volume and product mix of Enerplus' oil and gas production; securing necessary infrastructure and third party services; future cash flows and debt-to-cash flow levels; returns on Enerplus' capital program; future costs and expenses; and future issuances of debt or equity, including the terms and timing thereof and the expected use of proceeds therefrom.

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 conduct its operations and achieve results of operations as anticipated; that Enerplus' 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 Enerplus' reserve and resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing and cash flow to fund Enerplus' capital and operating requirements as needed; and the extent of its liabilities. 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 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; a failure to complete planned assets dispositions on the terms anticipated or at all; 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 described above).

The forward-looking information contained in this news release speak only as of the date of this news release, and none of Enerplus or its subsidiaries assumes 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 "funds flow" to analyze operating performance, leverage and liquidity. We calculate funds flow based on cash flow from operating activities before changes in non-cash operating working capital and decommissioning liabilities settled, all of which are measures prescribed by International Financial Reporting Standards ("IFRS") and which appear in our Consolidated Statements of Cash Flows.

Enerplus believes that, in addition to net earnings and other measures prescribed by IFRS, the term "funds flow" is a useful supplemental measure as it provides an indication of the results generated by Enerplus' principal business activities. However, this measure is not a measure recognized by IFRS and does not have a standardized meaning prescribed by IFRS. Therefore, this measure, as defined by Enerplus, may not be comparable to a similar measure presented by other issuers.










SOURCE: Enerplus Corporation

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