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 First 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, May 11, 2012 /CNW/ - Enerplus Corporation ("Enerplus" or the "Corporation") (TSX: ERF) (NYSE: ERF) is pleased to announce the results for the first quarter of 2012. Highlights of the quarter were as follows:
- Production increased during the first quarter by 3% over the fourth quarter of 2011, averaging 79,190 BOE/day. We continued to see positive growth in our oil and liquids volumes which were up approximately 9% from the previous quarter primarily due to our successful drilling and completion activities in North Dakota.
- Total liquids production represented 48% of our total production mix compared to 45% in the previous quarter. We continue to expect our production volumes to grow quarter over quarter throughout 2012 as we execute our capital spending plans. Overall, we expect production to grow by 10% in 2012, averaging 83,000 BOE/day and to exit 2012 producing approximately 88,000 BOE/day.
- Approximately $317 million in capital was invested during the first quarter, higher than originally planned due to better than expected winter weather that allowed us to accelerate our capital investment activities, particularly our delineation program in new plays in Alberta, British Columbia and on our operated leases in the Marcellus. In addition, we realized higher activity levels on our operated leases and more non-operated spending than anticipated in North Dakota. Approximately half of our spending was on our tight oil assets. We expect spending will moderate through the remainder of the year as the majority of our delineation activity is now complete and we have also reduced our rig count in North Dakota from four to three rigs. We also believe that inflation is stabilizing in the Fort Berthold region and costs appear to be in line with expectations across our other plays. We continue to expect total capital spending of $800 million for the year.
- We drilled 33.8 net wells during the quarter and brought 17.9 net wells on-stream across our portfolio. Approximately 83% of the wells drilled and 86% of the on-stream wells were in our crude oil properties.
- Funds flow was approximately $163 million ($0.86/share) in the first quarter, virtually unchanged from the previous quarter. Higher crude oil production helped mitigate widening oil price differentials experienced during the quarter and weakening natural gas prices (which were approximately 33% lower than the previous quarter). We realized an average price on the sale of our crude oil of $85.91/bbl during the quarter and $2.27/Mcf for our natural gas. On a BOE basis, our average selling price was $47.04/BOE.
- Operating costs and general and administrative costs (including equity based compensation) in the first quarter were in line with expectations at approximately $10.00/BOE and $3.51/BOE respectively.
- In February, we closed an equity offering that raised net proceeds of approximately $330 million to help fund our capital spending plans in 2012. At quarter end, we had approximately $900 million in debt outstanding, net of cash, including approximately $450 million drawn on our $1 billion credit facility. Subsequent to the end of the quarter, we have undertaken a private placement of long-term, senior unsecured notes for $405 million which we expect to close on May 15, 2012, and will use the proceeds to reduce the amount drawn on our bank credit facility. The notes will have terms ranging from seven to twelve years with interest rates from 4.34% to 4.4%.
- We continued to maintain strong financial flexibility with a debt to trailing 12 months funds flow ratio of 1.6x at March 31, 2012.
- Approximately 62% of our expected 2012 net oil production is hedged at a WTI reference price of US$96/bbl and approximately 42% of our expected net crude oil production for 2013 is hedged at WTI price of US$103/bbl. We have no financial hedges in place on our gas production but do have physical fixed price natural gas contracts on approximately 65 MMcf/day or 27% of our expected net natural gas production after royalties for the period April through October 2012 at an average price of CDN$2.17/Mcf. At this time, we have no plans to shut-in or curtail any of our operated natural gas production but will continue to monitor both prices and activities in our non-operated natural gas properties.
|SELECTED FINANCIAL RESULTS||Three months ended March 31,|
|Funds Flow (1)||$162,706||$161,224|
|Cash Flow from Operating Activities||68,981||132,403|
|Dividends to Shareholders||105,995||96,686|
|Debt Outstanding - net of cash||902,937||849,685|
|Property and Land Acquisitions||33,020||48,218|
|Dividends paid per share||0.54||0.54|
|Debt to Trailing 12 Month Funds Flow||1.6x||1.2x|
|Financial per Weighted Average Shares Outstanding|
|Funds Flow (1)||$0.86||$0.90|
|Weighted Average Number of Shares Outstanding||189,844||178,832|
|Selected Financial Results per BOE(2)|
|Oil & Gas Sales(3)||$47.04||$46.92|
|Commodity Derivative Instruments||(1.48)||0.44|
|G&A and Equity Based Compensation||(3.09)||(3.28)|
|Interest and Other Expenses||(0.72)||(2.75)|
|SELECTED OPERATING RESULTS||Three months ended March 31,|
|Average Daily Production|
|Crude oil (bbls/day)||34,074||30,338|
|Natural gas (Mcf/day)||246,686||251,480|
|% Crude Oil & Natural Gas Liquids||48%||44%|
|Average Selling Price(3)|
|Crude oil (per bbl)||$ 85.91||$77.69|
|NGLs (per bbl)||56.77||60.29|
|Natural gas (per Mcf)||2.27||3.91|
|USD/CDN exchange rate||1.00||1.02|
|Net Wells drilled||34||26|
(1) See "Non-GAAP Measures" in the accompanying MD&A.
(2) Non-cash amounts have been excluded.
(3) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.
| SHARE TRADING SUMMARY - for the three months ended March 31, 2012
|| CDN* - ERF
| U.S.** - ERF
|* TSX and other Canadian trading data combined.|
|**NYSE and other U.S. trading data combined.|
|2012 CASH DIVIDENDS PER SHARE|
|First Quarter Total||$0.54||$0.54|
|US$ dividends represent CDN$ dividends converted at the relevant foreign exchange rate on the payment date.|
|PRODUCTION & CAPITAL SPENDING - for the three months ended March 31, 2012|
|Play Type|| Average Daily
| Capital Spending
|Tight Oil (BOE/day)||15,620||$162,094|
|Crude Oil Waterflood (BOE/day)||16,101||42,785|
|Conventional Oil (BOE/day)||4,794||11,939|
|Total Crude Oil (BOE/day)||36,515||$216,818|
|Marcellus Shale Gas (Mcfe/day)||28,119||61,257|
|Other Natural Gas (Mcfe/day)||227,931||38,991|
|Total Gas (Mcfe/day)||256,050||$100,248|
|Company Total (BOE/day)||79,190||$317,066|
|NET DRILLING ACTIVITY - for the three months ended March 31, 2012|
|Play Type|| Horizontal
| Dry &
|Crude Oil Waterfloods||11.8||-||11.8||8.0||7.6||0.1|
|Marcellus Shale Gas||3.7||-||3.7||3.7||2.3||-|
|Other Natural Gas||2.0||-||2.0||2.0||0.2||-|
* 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
Our Fort Berthold light oil assets in North Dakota continued to attract a signficant portion of our capital investment during the first quarter of 2012. We invested approximately $138 million drilling nine net operated wells (six long horizontal wells and three short horizontal wells), completed five net wells and brought three net wells (two long and one short horizontal well) on-stream. Although early, we believe these new wells are performing in line with our type curve expectations. We also drilled our second salt water disposal well during the quarter and expect these two wells will be sufficient to handle all of the disposal water associated with our Fort Berthold leases. Production in this area increased by 28% from the fourth quarter of 2011 to average approximately 8,700 BOE/day during the first quarter. Capital spending was higher than anticipated on both our operated leases and by our non-operated partners in the area. We expect this to moderate through the remainder of the year as we are dropping our rig count to three rigs from four as was originally planned. We continue to work to reduce our well costs through changes in completion and frac design and we are also seeing evidence of costs beginning to stabilize in the region.
Crude Oil Waterfloods
Throughout the first quarter we invested approximately $43 million in our oil waterflood properties drilling 11.8 net wells with 7.6 net wells brought on-stream. Our activities were focused largely in our Ratcliffe assets in southern Saskatchewan and in our Pembina Cardium and Medicine Hat Glauconitic "C" oil waterfloods in Alberta. We expanded our Enhanced Oil Recovery ("EOR") project at Giltedge during the quarter adding polymer to another three injection wells in January. We continue to expect production to increase by two to three times in the project area over the next two years due to the polymer injection and remain on track to make a decision on full-field expansion in late 2012 or early 2013. We continued to prepare for our second polymer flood project at Medicine Hat and anticipate polymer injection to begin late in the second quarter with response expected 12 months after initial injection.
Our Deep Gas drilling activities during the first quarter were primarily focused in the Stacked Mannville play at Ansell where we drilled, completed and tested a horizontal Wilrich well and invested in infrastructure to tie-in the field to existing pipelines. The well tested with a peak rate of over 30 MMcf/day with minimal associated liquids at a pressure of 19 Mpa after 90 hours with 6,900 barrels of water recovered. The well was choked back due to constraints at the facility, however we expect tie-in to occur during the second quarter which will allow us to further evaluate the resource potential in this area. This is the largest gas well ever drilled by Enerplus and is the second well drilled at Ansell following our Wilrich test in late 2011 that had peak rate production of 13 MMcf/day at 14 Mpa after 165 hours with over 15,000 barrels of water recovered. This well was also choked back during the test due to capacity constraints at the facility, however produced 10 MMcf/day during its first 30 days on production. We remain very encouraged by these early tests and by the potential in this region.
We continued to invest in the Marcellus during the first quarter, primarily to retain leases on our non-operated acreage and to advance our work on our operated leases. With the prolonged weakness in natural gas prices, the pace of activity in the region is slowing. Much of this slowdown was reflected in our 2012 budget, however we may see a further reduction in activity and costs in the latter half of the year. In total we invested $61 million during the quarter with $37 million spent on non-operated projects where we participated in drilling 2.7 net wells and brought 2.3 net wells on-stream. On our operated leases, we invested approximately $24 million drilling one net well, completing another and advancing our facilities/seismic projects that we expect will position us to respond quickly to a gas price recovery. The majority of our operated program will be completed by mid-year. Total Marcellus production averaged 28 MMcf/day, up from 24 MMcf/day during the fourth quarter of 2011.
Our production continues to grow and we remain on track to meet our operating guidance for the year. We have a portfolio of mature oil and gas properties combined with early stage growth assets that we believe will support our strategy of providing both growth and income to investors.
We have taken a number of steps to maintain our financial flexibility in this weak natural gas price environment. In addition, we have plans to monetize between $250 million and $500 million in assets over the next 18 months which may include selling a portion of our portfolio of equity investments along with the sale or joint venture of a portion of our undeveloped acreage. We have retained an advisor with respect to our undeveloped acreage to examine alternatives for our operated Marcellus, Montney and Duvernay plays. We expect these monetization events would have minimal impact on our current production, reserves or cash flow.
Should current commodity prices continue and/or we do not make significant progress on the aforementioned monetization plans, we are prepared to reduce our capital spending, moderate our growth expectations and/or reduce our dividend to ensure we maintain a strong financial position. I am optimistic about the prospects for our company in the year ahead and look forward to advancing our plans for the rest of the year in spite of the challenges of weak natural gas prices.
I am also pleased to announce that Mr. Edward McLaughlin has been promoted to the position of President of Enerplus USA. Mr. McLaughlin will oversee the day-to-day activities of our Bakken oil play in North Dakota and Montana as well as our Marcellus natural gas assets in the northeastern U.S. and will continue to be based in our Denver office. Mr. McLaughlin has more than 30 years of oil and gas experience in the U.S. and has held numerous senior positions within the industry including President of the U.S. subsidiary of a major oil and gas company. He will report to Mr. Ray Daniels, Senior Vice-President of Operations for Enerplus.
It is with sadness that I advise that Mr. Donald West, a member of our Board of Directors since 2003, passed away recently. Don was a valued member of our Board and recognized for his knowledge and experience within the oil and gas industry. He will be greatly missed. I would also like to thank Messrs. Harry Wheeler, Clayton Woitas and Robert Zorich who have retired from our Board for their many contributions to Enerplus over the years and wish them well in their future endeavours.
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.
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. 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.
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; 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.
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