Press release from CNW Group
Enerplus Announces 2011 Second Quarter Results
Friday, August 05, 2011
Enerplus Announces 2011 Second Quarter Results06:00 EDT Friday, August 05, 2011All 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 June 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 "Information Regarding Reserves, Resources and Operations", "Notice to U.S. Readers" and "Non-GAAP Measures" at the end of this news release for information regarding the presentation of the financial, reserves, contingent resources and operational information in this news release. A full copy of our 2011 Second 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, Aug. 5, 2011 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) (NYSE: ERF) is pleased to announce operating and financial results for the three months ended June 30, 2011. Highlights for the quarter include:Acquisitions and DivestmentsWe sold approximately 45% of our Marcellus acreage position in Pennsylvania, Maryland and West Virginia, including 24.5 Bcfe of proved plus probable reserves for approximately $568 million, capturing a pre-tax gain of $272 million. Proceeds from the sale were used to reduce our outstanding bank debt, leaving our $1 billion credit facility virtually undrawn at the end of the quarter.Subsequent to the sale, we have retained a significant land position in the Marcellus that is more balanced consisting of 110,000 net acres, 60% of which is operated. Our non-operated Marcellus position includes approximately 45,000 net acres concentrated in the prolific Northeast area of Pennsylvania whereas our 65,000 net operated acres are located in West Virginia and Maryland. The independent best estimate of contingent resources associated with our remaining leases is 2.3 Tcfe and 92 Bcfe of proved plus probable natural gas reserves as of December 31, 2010.We continued to add to our undeveloped land inventory in emerging resource plays in Canada this year. Year-to-date we have acquired approximately 38,000 net acres in the liquids-rich Duvernay shale play and 14,000 net acres in two emerging Canadian oil prospects. We also added over 9,000 net acres of Montney prospective lands in the Cameron area of British Columbia, bringing our total Montney undeveloped land position to approximately 28,000 net acres. In total, we've invested approximately $75 million in unvdeveloped land to the end of July 2011.ProductionDaily production averaged 75,383 BOE/day despite challenges relating to wet weather in our key producing regions and was virtually unchanged compared to the first quarter of 2011.Field conditions have begun to improve in July and we are ramping up activities with four operated rigs now running in North Dakota at Fort Berthold and are building to four operated rigs in Canada focused mainly on our waterflood properties. We expect to bring on over 60 net wells during the second half of the year as drilling activity increases. Production volumes are expected to build throughout the remainder of the year, with the most significant increases anticipated late in the third quarter and into the fourth quarter.FinancialWe generated funds flow of $132.4 million ($0.74/share) during the quarter. Our funds flow does not reflect the gain of $272 million from the Marcellus asset sale; however it does reflect a $43 million U.S. tax expense resulting from the sale of those assets. Funds flow was $0.98 per share if adjusted for the impact of the tax expense. See "Non-GAAP Measures" below.We invested approximately $145 million in our assets during the quarter, drilling 14.1 net wells. Approximately 60% of our capital was directed toward oil projects, primarily in the Bakken and 33% invested in the Marcellus.We maintained our monthly dividend at $0.18/share through the quarter.We exited the quarter in a very strong financial position with a debt to funds flow ratio of only 0.7x.Operating costs of $9.84/BOE and G&A costs of $3.64/BOE during the quarter were marginally higher than anticipated mainly due to lower production.Our hedging program generated cash losses of approximately $21 million ($3.03/BOE) during the quarter as crude oil prices were above our hedge positions. We currently have over 60% of our anticipated crude oil production for the second half of 2011 hedged at $87.27 per barrel and have over 30% of our forecast 2012 crude oil production hedged at over $98.00 per barrel. We do not have any natural gas price hedges in place.Updated Guidance We have adjusted our capital spending guidance for 2011 from $650 million to $770 million due to an increase in drilling activity in both our operated and non-operated acreage and as a result of cost increases. We expect to drill more wells in the Marcellus where activity is focused on the highly economic northeast area of Pennsylvania, in the liquids rich Deep Basin region and also in our oil properties in Canada. Approximately 85% of our total spending remains focused in our Bakken, Marcellus and waterflood assets.Approximately $60 million of the increase in capital spending for 2011 is attributed to transitory cost increases due to the wet weather, some cost overruns on a few of our delineation projects, as well as inflationary cost increases for some services in Canada.Delays in production and capital spending due to the weather during the quarter reduced our expectations for annual average production by 800 BOE/day. We also sold 900 BOE/day of annual average production and 3,800 BOE/day of exit 2011 production due to the Marcellus sale. As a result, we are adjusting our 2011 annual average production guidance down by 2,000 BOE/day to 76,000 to 78,000 BOE/day.Due to the additional capital spending plans in the second half of the year, we are adjusting our exit production guidance up slightly to 81,000 - 84,000 BOE/day.With regard to 2012, we are evaluating opportunities within our portfolio and the potential to increase spending and production volumes beyond our original guidance issued earlier this year. We expect to provide greater clarity on our 2012 plans in the fourth quarter.SELECTED FINANCIAL RESULTS Three months ended June 30, Six months ended June 30, 20112010(1)20112010(1)Financial (000's) Funds Flow (2)$132,441$174,753$293,665$373,035 Dividends to Shareholders97,07795,909193,763191,621 Net Income/(Loss)267,98276,502297,531(107,520) Debt Outstanding - net of cash460,087697,817460,087697,817 Capital Spending145,16588,395319,609182,556 Property and Land Acquisitions94,415310,114142,633349,747 Divestments571,096181,238630,788182,776 Financial per Weighted Average Shares Outstanding Funds Flow (2)$0.74$0.99$1.64$2.13 Dividends0.540.551.081.09 Net Income/(Loss)1.500.441.66(0.61) Weighted Average Number of SharesOutstanding179,583175,705179,209175,099 Debt to Trailing 12 Month Funds Flow0.7x0.9x(5)0.7x0.9x(5) Selected Financial Results per BOE(3) Oil & Gas Sales(4)$51.62$41.18$49.28$44.39 Royalties(9.07)(7.35)(8.85)(7.96) Commodity Derivative Instruments(3.03)2.23(1.30)1.38 Operating Costs(9.86)(10.09)(9.37)(10.03) General and Administrative(3.16)(2.18)(3.21)(2.46) Interest and Other Expenses(0.89)(1.12)(1.82)(0.99) Taxes(6.30)(0.05)(3.22)(0.03) Funds Flow(2)$19.31$22.62$21.51$24.30 SELECTED OPERATING RESULTS Three months ended June 30,Six months ended June 30, 2011201020112010Average Daily Production Natural gas (Mcf/day)255,665296,566253,584297,737 Crude oil (bbls/day)29,33031,55929,83131,268 NGLs (bbls/day)3,4423,9223,3373,924 Total (BOE/day)75,38384,90975,43384,815 % Natural gas57%58%56%59% Average Selling Price(4) Natural gas (per Mcf)$3.86$3.78$3.88$4.44 Crude oil (per bbl)90.9268.7284.2371.25 NGLs (per bbl)66.2047.5563.3552.49 US$/CDN$ exchange rate1.030.971.020.97 Net Wells drilled14.11940.2158(1) 2010 comparative amounts have been restated and are presented in accordance with International Financial Reporting Standards ("IFRS"). In addition, 2010 comparatives 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 of Enerplus Corporation dated August 4, 2011.(3)Non-cash amounts have been excluded.(4) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.(5) The 12 months trailing funds flow for June 30, 2010, includes funds flow for July through December 2009 which was prepared following previous Canadian GAAP.Share Trading Summary CDN* - ERF U.S.** - ERFFor the three months ended June 30, 2011 (CDN$) (US$)High $31.54 $32.86Low $28.82 $29.61Close $30.45 $31.60* TSX and other Canadian trading data combined. **NYSE and other U.S. trading data combined. 2011 Cash Dividends Per Share Payment Month CDN$ US$*First Quarter Total $0.54 $0.55April $0.18 $0.19May 0.18 0.18June 0.18 0.18Second Quarter Total $0.54 $0.55Total Year-to-Date $1.08 $1.10*US$ dividends represent CDN$ dividends converted at the relevant foreign exchange rate on the payment date.PRODUCTION AND CAPITAL SPENDING Three months endedJune 30, 2011Six months ended June 30, 2011Play TypeAverageProductionVolumes CapitalSpending($ millions)AverageProductionVolumes CapitalSpending($ millions)Bakken/Tight Oil (BOE/day)12,724 6713,197 135Crude Oil Waterfloods (BOE/day)13,314 1913,379 48Conventional Oil (BOE/day)6,075 16,269 4Total Oil (BOE/day)32,114 8732,845 187 Marcellus Shale Gas (Mcfe/day)21,867 4721,571 89Other Natural Gas (Mcfe/day)237,746 11233,959 44Total Gas (Mcfe/day)259,613 58255,530 133 Company Total75,383 14575,433 320NET DRILLING ACTIVITY for the three months ended June 30, 2011Play TypeHorizontalWellsVerticalWellsTotal WellsWellsPendingCompletion/Tie-in*WellsOn-streamDry &Abandoned WellsBakken/Tight Oil7.6-184.108.40.206-Crude Oil Waterfloods------Conventional Oil220.127.116.11.6--Total Oil18.104.22.168.23.0-Marcellus Shale Gas4.7-4.74.7--Other Natural Gas0.2-0.20.2--Total Gas4.9-4.94.9--Company Total14.00.114.111.13.0-*Pending potential completion/tie-in or abandonment and on-stream wells measured as at June 30, 2011Bakken/Tight OilAs a result of the unusually wet weather conditions in the Williston Basin, we experienced a second consecutive quarter of lower than anticipated activity in our Bakken/tight oil resource play. We managed to keep two rigs working in Fort Berthold, North Dakota and two rigs working in Sleeping Giant, Montana throughout the quarter where we drilled 6 net operated horizontal wells and brought 2.8 net wells on-stream during the quarter. We also participated in the drilling of 1.6 net wells at Taylorton, Saskatchewan. Production volumes for the quarter averaged approximately 12,700 BOE/day, down 900 BOE/day from the first quarter due to weather and timing delays.At Fort Berthold, we drilled one long and three short Bakken horizontal wells during the quarter and completed and brought on a short Three Forks well. We began drilling a long Three Forks lateral well during the quarter and anticipate testing the well during the third quarter.We currently have four rigs working at Fort Berthold and expect to maintain this rig count through the remainder of 2011. Infrastructure and gathering system build continues to proceed and we expect to have a majority of our wells tied in by the end of the third quarter, reducing our reliance on trucking. Production volumes are also expected to increase by approximately 10% due to the associated natural gas volumes which will be captured once the wells are tied into the gathering system. We expect to drill 26 horizontal wells at Fort Berthold during the remainder of the year, targeting both the Bakken and the Three Forks formations and plan to complete and tie-in 22 wells. We have permits in place for all of our 2011 wells and are currently working to secure 2012 and 2013 drilling permits. Our 2011 plans include testing downspacing to determine optimal well density and as a result, we expect approximately 75% of the wells drilled this year will be short lateral horizontals. Under the full development scenario, approximately 75% of the wells are expected to be long horizontals. With four rigs working and our frac services agreement in place, drilling and completions activity should accelerate and we expect to remain on schedule for the balance of the year, drilling and completing three to four wells per month. We continue to expect to spend approximately $250 million in North Dakota and Montana in 2011.WaterfloodsActivity during the second quarter was mainly focused on our two enhanced oil recovery projects at Giltedge and Medicine Hat. Our polymer pilot at Giltedge is now fully operational and we are seeing indications that the polymer is moving through the project area. Assessment of oil production performance is expected by year end. At Medicine Hat, we continued to work on facility build-out to support our polymer project and plan to be injecting polymer early in 2012. Despite nominal tie-ins during the quarter, production volumes were unchanged from the first quarter at 13,300 BOE/day, emphasizing the benefits of these low decline properties.MarcellusHigh activity levels in the Marcellus continued through the second quarter of 2011 as our partners drilled wells to retain and develop leases. On our non-operated land, we participated in drilling 59 gross wells (approximately 5.3 net) with the majority of this activity in northeastern Pennsylvania where production rates and expected ultimate recoveries have been generally above our type curve. Although none of the wells drilled during the quarter were completed or tied-in due to wet weather, 1.2 net wells previously drilled were brought on stream during the quarter. There are currently 169 gross wells (12.5 net wells) drilled by our partners that are waiting on completion and/or tie-in. Production volumes during the quarter averaged 21.9 MMcfe/day, slightly above our first quarter average of 21.3 MMcfe/day. Current production is approximately 12 MMcf/day.UPDATING 2011 GUIDANCE 2011 Estimates Capital Expenditures ($millions) Original Capital Expenditure Estimate$650 Capital Reduction Due to Marcellus Disposition($50) Increased Spending$170 Revised Capital Expenditure Estimate$770 Revised Capital Expenditures By Resource Play Bakken/Tight Oil$325 Waterfloods$145 Marcellus$195 Deep Basin$55% of Total94% Original Annual Average Production Estimate (BOE/day)78,000 - 80,000Oil & Liquids Weighting47% Less Marcellus Production Sold & Weather Impacts (BOE/day)(1,700)Revised Annual Average Production (BOE/day)76,000 - 78,000Oil & Liquids Weighting45% Original Exit Production Estimate (BOE/day)80,000 - 84,000Less Marcellus Production Sold (BOE/day)(3,800)Revised Exit Production Estimate (BOE/day)81,000 - 84,000Oil & Liquids Weighting47%ADDITIONS TO THE BOARD OF DIRECTORSWe are pleased to announce that Ms. Sue MacKenzie and Mr. David Barr joined the board of directors of Enerplus effective July 1, 2011. Ms. MacKenzie has over 25 years of energy sector experience, having served as Chief Operating Officer with Oilsands Quest Inc. and Vice-President of Human Resources and Vice President of In Situ Development and Operations for Petro-Canada. Mr. Barr has 36 years of experience in the oil and gas industry, and is President and Chief Executive Officer of Logan International Inc. He was formerly Chairman of the Board of Logan International. He also spent close to 20 years with Baker Hughes in various executive roles, including Group President of numerous divisions and President of Baker Atlas.OUTLOOKThe unusual weather experienced during the first half of 2011 has presented a number of operational challenges for Enerplus. However, through the hard work and dedication of our employees, particularly in the field, we were successful in mitigating any significant impacts to our business and maintaining our production volumes at similar levels to the first quarter. We have once again delivered a significant gain to shareholders with the Marcellus sale and increased our financial strength and ability to deliver on our growth plans. The second half of 2011 is expected to be very active due to the increase in capital spending and the number of wells we plan to drill and tie-in. We will be focused on executing our capital program and achieving our production targets through the remainder of the year.For further information, please contact our Investor Relations Department at 1-800-319-6462 or email email@example.com.- 30 -Gordon J. KerrPresident & Chief Executive OfficerEnerplus CorporationNOTICE TO U.S. READERSThe 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.INFORMATION REGARDING RESERVES, RESOURCES AND OPERATIONSBarrels of Oil Equivalent and Cubic Feet of Gas EquivalentThis 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. Contingent Resource EstimatesThis 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 economic, 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." There is no certainty that we will produce any portion of the volumes currently classified as "contingent resources". The "contingent resource" estimates contained herein are presented as the "best estimate" of the quantity that will actually be recovered, effective as of December 31, 2010. A "best estimate" of contingent resources means that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate. For information regarding the primary contingencies which currently prevent the classification of our disclosed "contingent resources" associated with our Marcellus shale gas assets as reserves and the positive and negative factors relevant to the "contingent resource" estimate, see our Annual Information Form for the year ended December 31, 2010 (and corresponding Form 40-F), a copy of which is available on our SEDAR profile at www.sedar.com and a copy of the Form 40-F which is available on our EDGAR profile at www.sec.gov.FORWARD-LOOKING INFORMATION AND STATEMENTSThis 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.NON-GAAP MEASURESIn this news release, we use the terms "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 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 similar measures presented by other issuers. For further information: Investor Relations Department at 1-800-319-6462 or email firstname.lastname@example.org.