Nov 10, 2011
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") including comparative figures pertaining to Enerplus' 2010 results. A reconciliation of comparative figures is provided in the notes to the Unaudited Interim Consolidated Financial Statements for the period ended September 30, 2011.
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 2011 Third Quarter Financial Statements and MD&A have been filed on our website at www.enerplus.com, under our profile on SEDAR at www.sedar.com and on the EDGAR website at www.sec.gov.
CALGARY, Nov. 10, 2011 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) (NYSE: ERF) is pleased to announce operating and financial results for the three months ended September 30, 2011. Highlights for the quarter include:
New Growth Acquisitions
SELECTED FINANCIAL RESULTS
|Three months ended September 30,||Nine months ended September 30,|
|Funds Flow (2)||$123,262||$193,328||$416,927||$566,363|
|Dividends to Shareholders||97,416||96,111||291,179||287,732|
|Debt Outstanding - net of cash||734,300||680,264||734,300||680,264|
|Property and Land Acquisitions||67,313||139,678||209,946||489,425|
|Financial per Weighted Average Shares Outstanding|
|Funds Flow (2)||$0.68||$1.10||$2.32||$3.23|
|Weighted Average Number of Shares Outstanding||180,266||176,075||179,566||175,430|
|Debt to Trailing 12 Month Funds Flow(5)||1.3x||1.2x||1.3x||1.2x|
|Selected Financial Results per BOE(3)|
|Oil & Gas Sales(4)||$46.44||$40.08||$48.34||$42.96|
|Commodity Derivative Instruments||(0.66)||2.76||(1.09)||1.84|
|General and Administrative||(2.45)||(2.65)||(2.96)||(2.53)|
|Interest and Other Expenses||(1.01)||(1.88)||(1.55)||(1.28)|
|SELECTED OPERATING RESULTS||Three months ended September 30,||Nine months ended September 30,|
|Average Daily Production|
|Natural gas (Mcf/day)||243,675||285,292||250,244||293,543|
|Crude oil (bbls/day)||29,337||31,639||29,665||31,393|
|% Natural gas||55%||57%||56%||58%|
|Average Selling Price(4)|
|Natural gas (per Mcf)||$ 3.73||$3.67||$3.83||$4.19|
|Crude oil (per bbl)||77.57||66.97||82.01||69.80|
|NGLs (per bbl)||64.98||46.69||63.89||50.61|
|US/CDN exchange rate||1.02||0.96||1.02||0.97|
|Net Wells drilled||35||25||75||184|
|(1)||2010 comparative amounts have been restated and are presented in accordance with International Financial Reporting Standards ("IFRS") and represent the results of Enerplus Resources Fund which converted into Enerplus Corporation on January 1, 2011.|
|(2)||See "Non-GAAP Measures" in the Management's Discussion and Analysis.|
|(3)||Non-cash amounts have been excluded.|
|(4)||Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.|
The 12 month trailing funds flow for September 30, 2010, includes funds
flow for October through December 2009 which was prepared following
previous Canadian GAAP.
|SHARE TRADING SUMMARY||CDN* - ERF||U.S.** - ERF|
|For the three months ended September 30, 2011||(CDN$)||(US$)|
* TSX and other Canadian trading data combined.
**NYSE and other U.S. trading data combined.
|2011 CASH DIVIDENDS PER SHARE||CDN$||US$|
|First Quarter Total||$0.54||$0.55|
|Second Quarter Total||$0.54||$0.55|
|Third Quarter Total||$0.54||$0.55|
|PRODUCTION & CAPITAL SPENDING||
Three months ended
September 30, 2011
Nine months ended
September 30, 2011
|Bakken/Tight Oil (BOE/day)||13,511||90||13,284||222|
|Crude Oil Waterfloods Oil (BOE/day)||13,462||33||13,404||79|
|Conventional Oil (BOE/day)||5,738||6||6,057||13|
|Total Oil (BOE/day)||32,711||129||32,745||314|
|Marcellus Shale Gas (Mcfe/day)||15,025||50||19,365||140|
|Other Natural Gas (Mcfe/day)||228,177||22||232,337||67|
|Total Gas (Mcfe/day)||243,202||72||251,702||207|
|NET DRILLING ACTIVITY - for the three months ended September 30, 2011|
|Crude Oil Waterfloods||14.1||-||14.1||12.1||2.4||-|
|Marcellus Shale Gas||4.5||-||4.5||4.3||1.1||-|
|Other Natural Gas||2.8||0.1||2.9||2.3||0.6||-|
*Wells drilled during the quarter pending potential completion/tie-in or
**Total wells brought on stream during the quarter regardless of when they were drilled
Our Bakken/tight oil production increased during the third quarter by approximately 900 BOE/day to average 13,511 BOE/day. The increase in production is attributable to our successful drilling activities in our U.S. Bakken properties in Montana and North Dakota. However, as a result of flooding earlier in the year in North Dakota, major state highway repair work continued into the third quarter and slowed our planned activities at Fort Berthold. The combination of these issues also impacted the pace of construction of our third-party gathering system at Fort Berthold which was originally expected in late spring, delaying tie-in activity and adding to our trucking costs in this area.
We invested $90 million in drilling, completions and tie-in activities during the quarter. We completed our 2011 drilling program in the Sleeping Giant field in Montana drilling two gross (1.5 net) operated horizontal wells. Four gross well completions in the area planned for the quarter were delayed until October, however, all are now on-stream and producing at a total rate of 2,200 BOE/day gross, 1,500 BOE/day net to Enerplus.
At Fort Berthold we drilled one long and six short Bakken horizontal wells and one long and two short Three Forks horizontal wells during the quarter. Three long and one short Bakken horizontal wells were completed during the quarter along with our first long Three Forks horizontal well. The long Three Forks well has produced over 25,000 barrels of oil in the first 30 days and had water cuts of approximately 30%, similar to those in the Bakken. Current production from this well is approximately 600 BOE/day with 1,200 psi flowing pressure. We continue to be pleased with the performance of our wells versus our estimated type curves. We also completed our first salt water disposal well late in the quarter. This well will allow us to reduce our trucking and water handling costs going forward. The completion of this disposal well, reduced drilling times due to the use of walking rigs and expected savings in rig moves, construction and tie-ins as a result of multi-well pads provide us with greater confidence in achieving our expected well costs of $6.7 million for short lateral wells and $8.7 million for long lateral wells, including tie-ins, despite upward cost pressures in this busy basin.
We currently have four rigs working at Fort Berthold and expect to maintain this rig count through the remainder of 2011 and into 2012. The build out of the first phase of the gathering system was completed by October and we have commenced gas sales from 14 of our producing wells. We anticipate that six of the 13 completions planned in the fourth quarter will also be tied into the gathering system immediately with the remainder tied in as compression facilities permit. We expect incremental production volumes of approximately 10% associated with the capture and sale of the natural gas once wells are tied into the gathering system.
Crude Oil Waterfloods
Our waterflood portfolio continues to be a core holding for Enerplus providing us with exposure to a variety of crude oil plays across western Canada that offer low decline production with significant upside potential. We invested $33 million in our waterflood portfolio during the quarter, drilling 14 net wells primarily targeting the Ratcliffe and Viking formations. Four net Ratcliffe wells were drilled and placed on-stream at Freda Lake with results that were 10% above our type curve expectations of 140 BOE/day per well. We expect to drill another four wells at Freda Lake through the end of the year. We also drilled five horizontal gross Viking wells at Gleneath with positive early test results.
Our polymer flood project at Giltedge is proceeding well. We're seeing polymer break through in a number of producing wells and we are now working to ensure the polymer is moving through the reservoir as efficiently as possible. We are encouraged by the early signs of improved oil production and reduced water cuts. Our annual production estimate at Giltedge has increased from 1,650 BOE/day to 1,900 BOE/day due to the polymer project and other optimization work. We have also increased our exit production outlook for the field by 600 BOE/day primarily due to these activities. As we see further reservoir response, we will evaluate our options of accelerating and/or expanding the next phase of enhanced oil recovery at Giltedge.
We have a busy program planned for the fourth quarter on our oil waterflood properties where we expect to drill 13 operated wells with the bulk of our activity focused on our Pembina, Virden, and Freda Lake properties. We will also continue constructing facilities at Medicine Hat to support the start-up of our second polymer flood project early in 2012.
We continued to see high activity levels in the Marcellus throughout the third quarter of 2011 with capital spending of $50 million on both our operated and non-operated leases. Our well results continue to exceed our expectations with net production growing by 3 MMcf/day, after adjusting for the sale of a portion of our interests late in the second quarter, to 15 MMcf/day in the third quarter. We participated in drilling 36 gross wells (4.5 net) with eight gross wells (1.1 net) coming on-stream. Although completion activity increased during the third quarter, there still continues to be a significant inventory of wells waiting to be completed and tied-in to pipelines due to the extremely wet spring and delays in pipeline gathering projects. We currently have 214 gross wells (15.5 net) waiting on completion and/or tie-in. Our current net production is 19 MMcf/day.
On our non-operated leases in the northeast region of Pennsylvania, drilling activity continued at a brisk pace with approximately 12 rigs working in the play. EXCO continues to run a three rig development program focused on multi-well pad drilling exclusively in Lycoming County. Both Chief and Chesapeake are also very active with three and six rigs running respectively in the northeast area of Pennsylvania focused primarily on lease retention strategies. The Marcellus continues to experience high levels of activity as producers drill to hold acreage and explore new step out areas and slowly move into development. There are currently 165 horizontal rigs running in the basin, concentrated in Pennsylvania and West Virginia. Well performance for the year in northeast Pennsylvania continues to outperform our expectations. Our partners are averaging 4,000 - 5,000 foot laterals, trending longer where acreage allows with an average of 8 - 15 frac stages. Chesapeake is extending the lateral length on their latest wells to approximately 6,000 feet. Current well costs in the northeast are ranging from $6.5 million to $8.0 million, slightly higher than previous quarters due to longer laterals and an extra casing string for water protection.
In our operated areas, we continue to run a one rig appraisal program and moved this rig from Clinton County, Pennsylvania to Preston County, West Virginia during the quarter. We drilled one well in southwest Preston County and are preparing to complete the well in early November. We also recently finished drilling our second well in the southeast area of Preston County and will start completion activities following rig release on our first well in southwest Preston County. Both of these wells are expected to be tied-in to pipeline by late in the first quarter of 2012. We plan to drill a third well in West Virginia before year-end and then move back to Clinton County to drill a second well during the winter. Work on our initial well in Clinton County has been completed. Our extended test showed a 24 hour peak rate of 8.3 MMcf/day (our expected 24 hour peak rate was 3.5 MMcf/day) with flowing tubing pressure of 2,600 psi.
Deep Tight Gas
We spent $20 million in delineation and development capital during the third quarter on both our operated and non-operated properties. We completed one operated well in the Bluesky formation at Ansell and initial production results of 4.2 MMcf/day are above our type curve. We also spudded a Wilrich horizontal well at Minehead, which is our first in the area and we expect to complete it in November with a late Q4/early Q1 expected tie-in. We also recently completed a vertical Stacked Mannville well at South Ansell where we're testing both the Gething and Cadomin zones. We plan to test the Wilrich zone in this well before the end of the year. This is an important delineation well for us as success here will provide added confidence for the potential development of South Ansell in 2012. We expect to drill a Montney test well at Cameron in the fourth quarter and will drill our first test in the Duvernay in 2012.
FOURTH QUARTER OUTLOOK
During the fourth quarter we expect to see a significant increase in production as a result of completion and tie-in activities, primarily in the U.S. At Fort Berthold we expect to bring 13 wells on-stream in November and December, nine Bakken and four Three Forks short horizontal wells. We also expect to add incremental production associated with field optimization activities. As a result of these activities, we expect production to grow by 5,000 - 8,000 BOE/day net by the end of December. In the Marcellus, tie-in activities by our operators are expected to accelerate in the fourth quarter with exit production in the range of 25 MMcf/day - 33 MMcf/day net to Enerplus. We expect approximately 24 additional gross wells in the Marcellus region (2.3 net wells) to come on-stream by year-end. In Canada, we plan to have approximately 23 net wells on-stream in the fourth quarter primarily in our crude oil waterflood properties targeting the Ratcliffe, Lodgepole and Viking formations. We also plan to test both the Montney and Stacked Mannville areas of the Deep Basin before year-end.
While we've experienced a number of challenges in executing our 2011 capital program to date, we continue to be encouraged by our well results, the additional growth positions we have been able to build and the strength we have maintained in our financial position. We're excited about the prospects within our portfolio and the opportunity they represent for future growth in reserves, production and cash flow. We have a very active capital program planned for the fourth quarter that we expect will add significant production volumes to achieve our exit target of 81,000 - 84,000 BOE/day. While there continues to be much uncertainty and volatility in the capital markets as a result of debt issues in Europe and slow economic growth in the U.S., Enerplus is in a very strong financial position. We have preserved our balance sheet strength and are utilizing it to achieve our growth plans in the near term and believe we are on track to deliver on these plans.
Gordon J. Kerr
President & Chief Executive Officer
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 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. Additionally, the SEC prohibits disclosure of oil and gas resources, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not be construed as reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see "Information Regarding Reserves, Resources and Operations" below.
BARRELS OF OIL EQUIVALENT AND CUBIC FEET OF GAS EQUIVALENT
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.
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: 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; and future costs and expenses.
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; 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 terms "funds flow" and "payout ratio" 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. We calculate "payout ratio" by dividing dividends to shareholders by funds flow.
Enerplus believes that, in addition to net earnings and other measures prescribed by IFRS, the terms "funds flow", and "payout 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 IFRS and do not have a standardized meaning prescribed by IFRS. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers.