Enerplus Announces Fourth Quarter and Full Year 2019 Financial and Operating Results, 2019 Year End Reserves and ESG Targets
February 21, 20204:00 AM CNW
All financial information contained within this news release has been prepared in accordance with U.S. GAAP. This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review the “Forward-Looking Information and Statements” at the conclusion of this news release. Readers are also referred to “Information Regarding Reserves, Resources and Operational Information”, “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, as well as the use of certain financial measures that do not have standard meaning under U.S. GAAP. A copy of Enerplus’ 2019 Financial Statements and MD&A is available 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. All amounts in this news release are stated in Canadian dollars unless otherwise specified.CALGARY, Feb. 21, 2020 /CNW/ – Enerplus Corporation (“Enerplus” or the “Company”) (TSX & NYSE: ERF) today reported fourth quarter 2019 cash flow from operating activities of $188.5 million and adjusted funds flow of $178.9 million. Enerplus reported a fourth quarter 2019 net loss of $429.1 million, or $(1.93) per share. The Company recognized a $451.1 million non-cash goodwill impairment related to its Canadian reporting unit in the quarter. Excluding the goodwill impairment and certain other non-cash or non-recurring items, fourth quarter 2019 adjusted net income was $34.4 million, or $0.15 per share.Full year 2019 cash flow from operating activities was $694.2 million and adjusted funds flow was $709.0 million. The Company reported a full year 2019 net loss of $259.7 million, or $(1.12) per share. Excluding the goodwill impairment and certain other non-cash or non-recurring items, full year 2019 adjusted net income was $243.2 million, or $1.05 per share.FULL YEAR 2019 SUMMARYTotal production increased 8% (14% per share) year-over-year to 101,042 BOE per dayLiquids production increased 9% (15% per share) year-over-year to 54,633 barrels per dayAdjusted funds flow was $709.0 million, which exceeded capital spending of $618.9 million, generating free cash flow of $90.1 millionReturned $206.5 million to shareholders through share repurchases and dividendsMaintained strong financial flexibility; ended the year with a net debt to adjusted funds flow ratio of 0.6 timesAchieved 139% proved plus probable (“2P”) reserves replacement, including 206% 2P reserves replacement in North Dakota2P reserves increased 3% (11% per share) year-over-year“We delivered strong results in 2019 having generated double-digit production per share growth and returning over $200 million to shareholders,” stated Ian C. Dundas, President and Chief Executive Officer. “We have positioned Enerplus to be resilient through commodity price cycles with our strong balance sheet, profitable growth plan underpinned by financial returns and focus on generating free cash flow. In addition, we believe that our commitment to environmental, social and governance initiatives will further support long-term value creation.”FOURTH QUARTER 2019 REVIEWTotal production for the fourth quarter of 2019 was 107,436 BOE per day, exceeding the Company’s guidance range of 103,000 to 107,000 BOE per day, and a 10% increase from the same period in 2018. Crude oil and natural gas liquids production was 59,846 barrels per day in the fourth quarter, achieving the high end of the Company’s guidance range of 58,000 to 60,000 barrels per day, and a 10% increase from the same period in 2018. The production increase was driven by higher North Dakota and Marcellus volumes.Adjusted funds flow was $178.9 million in the fourth quarter, 17% lower than the same period in 2018 primarily due to an increase in operating expenses and a lower Alternative Minimum Tax (“AMT”) refund of $13.9 million in the fourth quarter of 2019, compared to $27.3 million in the fourth quarter of 2018.Enerplus recorded a net loss of $429.1 million in the fourth quarter compared to net income of $249.3 million in the same period in 2018. Earnings decreased from the fourth quarter of 2018 primarily due to a $451.1 million non-cash goodwill impairment related to the Company’s Canadian reporting unit as a result of the cumulative impact of Canadian asset divestments, the shut-in of uneconomic natural gas production in Tommy Lakes and lower forecasted commodity prices. Earnings were further impacted by a $28.8 million loss on commodity derivative instruments in the fourth quarter of 2019 compared to a $253.7 million gain in the same period in 2018. Excluding the goodwill impairment and certain other non-cash or non-recurring items, fourth quarter adjusted net income was $34.4 million, compared to $102.2 million in the same period in 2018. The reduction in adjusted net income was primarily due to higher operating expenses and a realized foreign exchange loss in the fourth quarter of 2019.Enerplus’ fourth quarter 2019 Bakken crude oil price differential was US$4.40 per barrel below WTI, compared to US$5.60 per barrel below WTI for the same period in 2018. Enerplus’ fourth quarter Marcellus natural gas price differential was US$0.63 per Mcf below NYMEX, compared to US$0.34 per Mcf below NYMEX for the same period in 2018.Operating expenses in the fourth quarter increased to $8.05 per BOE, compared to $6.99 per BOE in the same period in 2018, as a result of higher fluid handling costs due to increased crude oil volumes and additional well servicing activity. Cash general and administrative (“G&A”) expenses in the fourth quarter decreased to $1.34 per BOE, compared to $1.40 per BOE in the same period of 2018, primarily due to higher production.Exploration and development capital spending totaled $99.4 million in the fourth quarter of 2019. The Company also spent $23.7 million repurchasing 2.7 million shares and paid $6.7 million in dividends during the fourth quarter.Enerplus ended the fourth quarter of 2019 with total debt net of cash of $455.0 million and was undrawn on its US$600 million senior unsecured bank credit facility. The Company’s net debt to adjusted funds flow ratio was 0.6 times at quarter-end.FULL YEAR 2019 REVIEWTotal production for 2019 was 101,042 BOE per day, an 8% (14% per share) increase from 2018. Crude oil and natural gas liquids production was 54,633 barrels per day in 2019, a 9% (15% per share) increase from 2018.Adjusted funds flow was $709.0 million in 2019, 6% lower than 2018 primarily due to lower benchmark commodity prices and higher operating expenses in 2019.Enerplus recorded a net loss of $259.7 million in 2019 compared to net income of $378.3 million in 2018. Earnings decreased from 2018 primarily due to a $451.1 million non-cash Canadian goodwill impairment and a loss on commodity derivative instruments of $66.1 million, compared to a gain of $88.2 million recorded in 2018. Excluding the goodwill impairment and certain other non-cash or non-recurring items, 2019 adjusted net income was $243.2 million, compared to $344.8 million in 2018. The reduction in adjusted net income was primarily due to lower benchmark commodity prices and higher operating expenses in 2019.Enerplus’ 2019 Bakken crude oil price differential was US$3.61 per barrel below WTI, compared to US$3.78 per barrel below WTI in 2018. Enerplus’ 2019 Marcellus natural gas price differential was US$0.39 per Mcf below NYMEX, compared to US$0.43 per Mcf below NYMEX in 2018.Operating expenses in 2019 were $7.88 per BOE, compared to $7.00 per BOE in 2018. The increase was largely due to additional well servicing activity and higher fluid handling and gas processing costs in North Dakota. Cash G&A expenses in 2019 were $1.32 per BOE, compared to $1.47 per BOE in 2018. The lower cash G&A expenses per BOE were primarily due to higher production levels in 2019 compared to 2018.Exploration and development capital spending totaled $618.9 million in 2019, below the Company’s capital budget guidance of $625 million.The Company spent $178.8 million repurchasing 18.2 million shares and paid $27.7 million in dividends in 2019. Subsequent to year end and up to February 20, 2020, the Company repurchased 0.3 million shares for total consideration of $2.5 million. Since initiating its share repurchase program in the third quarter of 2018, Enerplus has repurchased 24.5 million shares, representing approximately 10% of shares outstanding.2019 YEAR END RESERVES SUMMARYReplaced 139% of 2019 production, adding 51.0 MMBOE (57% crude oil) of 2P reserves (including revisions and economic factors).Material reserves growth was realized in North Dakota where the Company replaced 206% of 2019 production, adding 34.2 MMBOE of 2P reserves (including revisions and economic factors).Total 2P reserves were 440.8 MMBOE at year end 2019, representing a 3% (11% per share) increase from year end 2018F&D costs were $15.97 per BOE for proved developed producing (“PDP”) reserves, $11.37 per BOE for proved reserves, and $13.05 per BOE for 2P reserves, including future development costs (“FDC”).Finding, development and acquisition (“FD&A”) costs were $11.82 per BOE for proved reserves and $13.63 per BOE for 2P reserves, including FDC.2P reserves were comprised of 50% crude oil, 5% natural gas liquids, and 45% natural gas at year end 2019.ASSET ACTIVITYWilliston Basin production averaged 54,113 BOE per day (82% crude oil) during the fourth quarter of 2019, 1% lower than the prior quarter and 14% higher than the same period in 2018. Fourth quarter Williston Basin production was comprised of 50,872 BOE per day in North Dakota and 3,241 BOE per day in Montana. Full year 2019 production from the Williston Basin averaged 48,745 BOE per day, a 13% increase year-over-year. In the fourth quarter, the Company drilled 12 gross operated wells (61% average working interest) in North Dakota. No operated wells were brought on production in the fourth quarter.Marcellus natural gas production averaged 233 MMcf per day during the fourth quarter of 2019, 2% higher than the prior quarter and 10% higher than the same period in 2018. Full year 2019 production averaged 227 MMcf per day, a 9% increase year-over-year. In the fourth quarter, the Company participated in drilling 13 gross non-operated wells (2% average working interest) with five gross non-operated wells (28% average working interest) brought on production.Canadian waterflood production averaged 8,580 BOE per day (93% crude oil) during the fourth quarter of 2019, 6% lower than the prior quarter and 12% lower than the same period in 2018. Full year 2019 production averaged 9,083 BOE per day, an 8% decrease year-over-year primarily due to the sale of assets in 2019 and production declines.Average Daily Production(1) Three months ended December 31, 2019Twelve months ended December 31, 2019Crude Oil (Mbbl/d)NGL (Mbbl/d)Natural gas (MMcf/d)Total (MBOE/d)Crude Oil (Mbbl/d)NGL (Mbbl/d)Natural gas (MMcf/d)Total (MBOE/d)Williston Basin44.44.630.454.140.14.027.848.7Marcellus––232.738.8––226.737.8Canadian Waterfloods8.00.12.98.22.214.171.124.1DJ Basin126.96.36.199.91.00.10.21.0Other(2)0.10.718.84.00.20.820.34.4Total54.35.5285.5107.449.74.9278.5101.0 (1)Table may not add due to rounding.(2)Comprises non-core properties in Canada.Summary of Wells Drilled(1) Three months ended December 31, 2019Twelve months ended December 31, 2019OperatedNon-OperatedOperatedNon-OperatedGrossNetGrossNetGrossNetGrossNetWilliston Basin127.341.05544.6113.7Marcellus––130.3––381.4Canadian Waterfloods––––11.0––DJ Basin––––54.4––Other(2)––––––20.5Total127.3171.36150.0515.7 (1)Table may not add due to rounding.(2)Comprises non-core properties in Canada.Summary of Wells Brought On-Stream(1) Three months ended December 31, 2019Twelve months ended December 31, 2019OperatedNon-OperatedOperatedNon-OperatedGrossNetGrossNetGrossNetGrossNetWilliston Basin––41.64034.393.6Marcellus––51.4––455.7Canadian Waterfloods––––11.0––DJ Basin––––54.4––Other(2)––––––20.5Total––93.04639.7569.8 (1)Table may not add due to rounding.(2)Comprises non-core properties in Canada.ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG) – GREENHOUSE GAS EMISSIONS AND WATER TARGETSEnerplus believes that minimizing the environmental impacts of its operations is a foundational tenet of corporate responsibility. Moreover, as the global economy transitions to a lower carbon future, climate related policies and regulations around greenhouse gas (GHG) emissions are becoming increasingly stringent, requiring businesses to adapt to support long-term value creation. As part of Enerplus’ continued integration of ESG issues into its strategy and operations, the Company has established targets for reducing GHG emissions intensity and freshwater use.Greenhouse Gas Emissions Using 2019 as a baseline, Enerplus is targeting a 10% reduction of its GHG emissions per barrel of oil equivalent in 2020. Infrastructure expansion is expected to support the Company’s efforts to reduce levels of flared natural gas in North Dakota in 2020, helping it reach its GHG emissions intensity reduction target. The Company is evaluating additional operational changes and aims to identify technologies and opportunities to achieve further emissions intensity reductions beyond 2020.Enerplus’ 2020 target addresses scope 1 and 2 emissions. Scope 1 emissions are direct emissions from owned and operated facilities. Scope 2 emissions are indirect emissions from the generation of purchased energy for the Company’s owned and operated facilities.Water Management The vast majority (approximately 80% in 2018) of the water used in Enerplus’ operations is reused. As Enerplus aims to further improve its water use efficiency, it has established a target to reduce its freshwater use per well completion in North Dakota by 15%, on average, in 2020, compared to 2019, by reusing produced water in its fracturing operations.Other ESG Focus Areas In addition to GHG emissions and water management, Enerplus has identified culture, stakeholder engagement, health & safety, and board expertise & engagement as material ESG focus areas. Enerplus believes that the continued integration of these focus areas into its strategy and operations will enhance long-term business resilience. Enerplus’ ESG initiatives have oversight by the Board of Directors with each material focus area mapped to the applicable board subcommittee including the Compensation and Human Resources Committee, the Safety and Social Responsibility Committee and the Corporate Governance and Nominating Committee. A copy of Enerplus’ ESG presentation is available on the Company’s website at www.enerplus.com/investors/presentations-events.cfm.BOARD CHAIR APPOINTMENTEnerplus today announced that Elliott Pew will be stepping down as Board Chair effective May 7, 2020 at the Company’s annual meeting. Hilary Foulkes, a director of Enerplus since 2014 and currently the Chair of the Corporate Governance & Nominating Committee, has been appointed as the new Board Chair upon Mr. Pew stepping down. Mr. Pew has served as Board Chair since 2014 and is stepping down as part of the board’s succession planning and focus on strong continuity. Mr. Pew will continue with Enerplus as an independent director.“On behalf of the Board, I would like to thank Elliott for his dedication and leadership,” said Mr. Dundas. “And I look forward to his continued contributions as a board member. I am also excited to welcome Hilary as Chair,” continued Dundas. “Her commitment and experience during her tenure as a director have been valuable to our company and Enerplus will continue to benefit from these strengths in her new expanded role as Board Chair.”PRICE RISK MANAGEMENT UPDATEEnerplus has approximately 61% of its 2020 forecasted net crude oil production protected (based on the guidance midpoint). The Company has used swaps, put spreads and three-way collar structures to hedge crude oil providing downside protection, while retaining meaningful exposure to higher crude oil prices.Commodity Hedging Detail (As at February 20, 2020) WTI Crude Oil (US$/bbl)(1)Jan 1 – Jan 31, 2020Feb 1 – Mar 31, 2020Apr 1 – Jun 30, 2020Jul 1 – Sep 30, 2020Oct 1 – Dec 31, 2020SwapsVolume (bbls/d)5,00010,00012,0002,000–Sold Swaps$57.05$54.56$55.23$57.18–Put SpreadsVolume (bbls/d)16,00016,00016,00016,00016,000Sold Puts$46.88$46.88$46.88$46.88$46.88Purchased Puts$57.50$57.50$57.50$57.50$57.50Three Way CollarsVolume (bbls/d)–––5,0005,000Sold Puts–––$48.00$48.00Purchased Puts–––$56.25$56.25Sold Calls–––$65.00$65.00 (1)The total average deferred premium on outstanding 2020 hedges is US$1.69/bbl from January 1, 2020 to December 31, 2020.2020 GUIDANCE Enerplus’ previously announced and unchanged 2020 guidance is provided below.Capital spending$520 to $570 millionAverage annual production96,000 – 100,000 BOE/dAverage annual crude oil and natural gas liquids production57,000 – 60,000 BOE/dAverage royalty and production tax rate26%Operating expense$8.50/BOETransportation expense$4.00/BOECash G&A expense$1.50/BOE2020 Differential/Basis Outlook(1)U.S. Bakken crude oil differential (compared to WTI crude oil)US$(5.00)/bblMarcellus basis (compared to NYMEX natural gas)US$(0.45)/Mcf(1) Excluding transportation costs. Three months endedTwelve months endedSELECTED FINANCIAL RESULTSDecember 31,December 31,2019201820192018Financial (CDN$, thousands, except ratios)Net Income/(Loss)$(429,143)$249,315$(259,720)$378,279Adjusted Net Income(4)34,365102,167243,160344,813Cash Flow from Operating Activities188,492221,619694,240738,784Adjusted Funds Flow(4)178,922214,285708,992753,506Dividends to Shareholders – Declared6,6567,23427,68829,256Total Debt Net of Cash(4)454,984333,523454,984333,523Capital Spending99,38972,058618,910593,876Property and Land Acquisitions6,1269,47424,40625,840Property Divestments(316)8869,5836,912Net Debt to Adjusted Funds Flow Ratio(4)0.6x0.4x0.6x0.4xFinancial per Weighted Average Shares OutstandingNet Income/(Loss) – Basic$(1.93)$1.03$(1.12)$1.55Net Income/(Loss) – Diluted(1.93)1.02(1.12)1.53Weighted Average Number of Shares Outstanding (000’s) – Basic222,227242,344231,334244,076Weighted Average Number of Shares Outstanding (000’s) – Diluted222,227245,242231,334247,261Selected Financial Results per BOE(1)(2)Oil & Natural Gas Sales(3)$41.64$45.43$42.65$47.35Royalties and Production Taxes(10.93)(11.58)(10.88)(11.92)Commodity Derivative Instruments0.07(0.31)0.42(1.05)Cash Operating Expenses(8.05)(6.99)(7.88)(7.00)Transportation Costs(3.82)(3.71)(3.93)(3.63)General and Administrative Expenses(1.34)(1.40)(1.32)(1.47)Cash Share-Based Compensation0.010.23(0.02)(0.01)Interest, Foreign Exchange and Other Expenses(0.89)(0.90)(0.72)(0.92)Current Income Tax Recovery1.413.030.910.80Adjusted Funds Flow(4)$18.10$23.80$19.23$22.15 Three months endedTwelve months endedSELECTED OPERATING RESULTSDecember 31,December 31,2019201820192018Average Daily Production(2)Crude Oil (bbls/day)54,34449,96849,70445,424Natural Gas Liquids (bbls/day)5,5024,4834,9294,486Natural Gas (Mcf/day)285,537260,453278,451259,837Total (BOE/day)107,43697,860101,04293,216% Crude Oil and Natural Gas Liquids56%56%54%54%Average Selling Price(2)(3)Crude Oil (per bbl)$67.23$64.18$68.98$74.59Natural Gas Liquids (per bbl)18.2826.7215.1928.31Natural Gas (per Mcf)2.504.282.873.42Net Wells Drilled9125661 (1)Non‑cash amounts have been excluded.(2)Based on Company interest production volumes. See “Presentation of Production and Reserves Information” at the end of this news release.(3)Before transportation costs, royalties and commodity derivative instruments.(4)These non‑GAAP measures may not be directly comparable to similar measures presented by other entities. See “Non‑GAAP Measures” section at the end of this news release.INDEPENDENT RESERVES EVALUATIONAll of the Company’s reserves, including its U.S. reserves, have been evaluated in accordance with NI 51-101. Independent reserves evaluations have been conducted on properties comprising approximately 97% of the net present value (discounted at 10%, before tax, using January 1, 2020 forecast prices and costs described below) of the Company’s total 2P reserves.McDaniel & Associates Consultants Ltd. (“McDaniel”), an independent petroleum consulting firm based in Calgary, Alberta, has evaluated properties which comprise approximately 78% of the net present value (discounted at 10%, before tax, using the average commodity price forecasts and inflation rates of McDaniel, GLJ Petroleum Consultants (“GLJ”) and Sproule Associates Limited (“Sproule”) as of January 1, 2020) of the Company’s 2P reserves located in Canada and all of the reserves associated with the Company’s properties located in North Dakota, Montana and Colorado. The Company has evaluated the remaining 22% of the net present value of its Canadian properties using similar evaluation parameters, including the same forecast price and inflation rate assumptions utilized by McDaniel. McDaniel has reviewed the Company’s internal evaluation of these properties. Netherland, Sewell & Associates (“NSAI”), independent petroleum consultants based in Dallas, Texas, has evaluated all of the Company’s reserves associated with the Company’s properties in Pennsylvania. For consistency in the Company’s reserves reporting, NSAI also used the average commodity price forecasts and inflation rates of McDaniel, GLJ and Sproule as of January 1, 2020 to prepare its report.The following information sets out Enerplus’ gross and net crude oil, NGLs and natural gas reserves volumes and the estimated net present values of future net revenues associated with such reserves as at December 31, 2019 using forecast price and cost cases, together with certain information, estimates and assumptions associated with such reserves estimates. Under different price scenarios, these reserves could vary as a change in price can affect the economic limit associated with a property. It should be noted that tables may not add due to rounding.Reserves Summary Reserves SummaryLight & Medium Oil (Mbbls)Heavy Oil (Mbbls)Tight Oil (Mbbls)Total Oil (Mbbls)Natural Gas Liquids (Mbbls)Conventional Natural Gas (MMcf)Shale Gas (MMcf)Total (MBOE)GrossProved producing6,94717,04660,93884,9308,52622,808617,357200,150Proved developed non-producing163–271434841,3475,9991,742Proved undeveloped6603,07551,60355,3385,71788310,381112,801Total proved7,77020,121112,812140,70314,32724,242933,737314,693Total probable2,7886,47068,24077,4988,3967,395233,613126,061Proved plus Probable10,55826,591181,052218,20122,72331,6371,167,349440,755NetProved producing5,69014,22448,92768,8406,96523,529495,517162,313Proved developed non-producing138–221359621,2704,8081,434Proved undeveloped5572,55841,30944,4244,57573246,15590,038Total proved6,38516,78290,457113,62311,60224,872746,480253,785Total probable2,1605,29854,57662,0346,7587,467186,702101,154Proved plus Probable8,54522,079145,033175,65718,36132,339933,182354,938Reserves ReconciliationThe following tables outline the changes in Enerplus’ proved, probable and proved plus probable reserves, on a gross basis, from December 31, 2018 to December 31, 2019. Proved Reserves – Gross Volumes (Forecast Prices)Light & Medium Oil (Mbbls)Heavy Oil (Mbbls)Tight Oil (Mbbls)Total Oil (Mbbls)Natural Gas Liquids (Mbbls)Conventional Natural Gas (MMcf)Shale Gas (MMcf)Total (MBOE)Proved Reserves at Dec. 31, 20189,63721,181106,530137,34713,78331,007849,063297,809Acquisitions––––––––Dispositions(982)––(982)(18)(319)–(1,053)Discoveries––––––––Extensions & improvedrecovery388–21,73122,1192,34074188,89339,399Economic factors(18)(115)(958)(1,091)(75)(212)(4,376)(1,931)Technical revisions1657784651,408461,05093,16417,156Production(1,420)(1,722)(14,957)(18,098)(1,749)(8,026)(93,008)(36,686)Proved Reserves at7,77020,121112,812140,70314,32724,242933,737314,693Dec. 31, 2019 Probable Reserves – Gross Volumes (Forecast Prices)Light & Medium Oil (Mbbls)Heavy Oil (Mbbls)Tight Oil (Mbbls)Total Oil (Mbbls)Natural Gas Liquids (Mbbls)Conventional Natural Gas (MMcf)Shale Gas (MMcf)Total (MBOE)Probable Reserves at Dec. 31, 20183,0247,21560,63170,8697,27710,129300,449129,909Acquisitions––––––––Dispositions(232)––(232)(9)(163)–(268)Discoveries––––––––Extensions & improvedrecovery158–17,42817,5862,03413174,18632,007Economic factors37(201)(190)(105)(1,940)684(504)Technical revisions(165)(752)(9,617)(10,535)(803)(761)(141,706)(35,082)Production––––––––Probable Reserves at2,7886,47068,24077,4988,3967,395233,613126,061Dec. 31, 2019 Proved Plus Probable Reserves – Gross Volumes (Forecast Prices)Light & Medium Oil (Mbbls)Heavy Oil (Mbbls)Tight Oil (Mbbls)Total Oil (Mbbls)Natural Gas Liquids (Mbbls)Conventional Natural Gas (MMcf)Shale Gas (MMcf)Total (MBOE)Proved Plus Probable Reserves at Dec. 31, 201812,66028,395167,160208,21621,06041,1371,149,511427,718Acquisitions––––––––Dispositions(1,214)––(1,214)(27)(483)–(1,321)Discoveries––––––––Extensions & improved recovery546–39,15939,7064,374872163,07971,405Economic factors(15)(108)(1,158)(1,282)(180)(2,152)(3,692)(2,435)Technical revisions–26(9,152)(9,127)(757)289(48,542)(17,926)Production(1,420)(1,722)(14,957)(18,098)(1,749)(8,026)(93,008)(36,686)Proved Plus Probable Reserves at Dec. 31, 201910,55826,591181,052218,20122,72331,6371,167,349440,755Future Development CostsChanges in forecast FDC occur annually as a result of development activities, acquisition and divestment activities and capital cost estimates that reflect the evaluators’ best estimate of the capital required to bring the proved and proved plus probable reserves on production. The aggregate of the exploration and development costs incurred in the most recent year and the change during the year in estimated FDC generally reflect the total finding and development costs related to reserves additions for that year.The following is a summary of the independent reserves evaluators’ estimated FDC required to bring the total proved and proved plus probable reserves on production: Future Development CostsProved ReservesProved Plus Probable Reserves($ millions)2020$526$5502021$485$5112022$258$5132023$31$4082024$35$722025$6$7Remainder$7$5Total FDC Undiscounted$1,347$2,066Total FDC Discounted at 10%$1,183$1,723 F&D and FD&A Costs – including FDC($ millions except for per BOE amounts)2019201820173 YearProved Plus Probable ReservesFinding & Development CostsCapital Expenditures$618.9$593.8$458.0$1,670.7Net change in Future Development Costs$47.0$309.1$102.8$458.9Gross Reserves additions (MMBOE)51.065.758.0174.7F&D costs ($/BOE)$13.05$13.74$9.68$12.19Finding, Development & Acquisition CostsCapital expenditures and net acquisitions$633.7$612.7$415.1$1,661.5Net change in Future Development Costs$44.0$308.1$85.1$437.1Gross Reserves additions (MMBOE)49.764.145.6159.3FD&A costs ($/BOE)$13.63$14.37$10.98$13.17Proved ReservesFinding & Development CostsCapital Expenditures$618.9$593.8$458.0$1,670.7Net change in Future Development Costs$2.4$309.3$114.0$425.7Gross Reserves additions (MMBOE)54.654.150.5159.3F&D costs ($/BOE)$11.37$16.69$11.32$13.16Finding, Development & Acquisition CostsCapital expenditures and net acquisitions$633.7$612.7$415.1$1,661.5Net change in Future Development Costs$(0.5)$308.3$96.7$404.5Gross Reserves additions (MMBOE)53.652.941.0147.5FD&A costs ($/BOE)$11.82$17.42$12.48$14.01Proved Developed Producing ReservesFinding & Development CostsCapital Expenditures$618.9$593.8$458.0$1,670.7Gross Reserves additions (MMBOE)38.845.434.8118.9F&D costs ($/BOE)$15.97$13.08$13.17$14.05Forecast Price AssumptionsThe forecast price and cost case assumes no legislative or regulatory amendments, and includes the effects of inflation. The estimated future net revenue to be derived from the production of the reserves is based on the following average of the price forecasts of McDaniel, GLJ and Sproule as of January 1, 2020 (utilized by McDaniel, NSAI and by the Company in its internal evaluations for consistency in the Company’s reserves reporting), and the following inflation and exchange rate assumptions. WTI Crude Oil(1) US$/bblLight Crude Oil(2) Edmonton CDN$/bblAlberta Heavy Crude Oil(3) CDN$/bblU.S. Henry Hub Gas Price US$/MMBtuNatural Gas Alberta Spot @ AECO CDN$/MMBtuExchange Rate US$/CDN$Inflation Rate %/year202061.0072.6451.232.622.040.7600.0202163.7576.0656.112.872.320.7701.7202266.1878.3557.723.062.620.7852.0202367.9180.7159.453.172.710.7852.0202469.4882.6461.093.242.810.7852.0202571.0784.6062.753.322.890.7852.0202672.6886.5764.433.392.960.7852.0202774.2488.4966.043.453.030.7852.0202875.7390.3167.553.533.090.7852.0202977.2492.1769.083.603.160.7852.0203078.7994.0170.463.673.230.7852.0203180.3695.8971.873.743.290.7852.0203281.9797.8173.313.823.360.7852.0203383.6199.7674.783.893.430.7852.0203485.28101.7676.273.973.490.7852.0Thereafter(4)(4)(4)(4)(4)0.785(4)(1) West Texas Intermediate at Cushing, Oklahoma 40 degree API / 0.5% Sulphur.(2) Edmonton Light Sweet 40 degree API, 0.3% Sulphur.(3) Heavy Crude Oil 12 degree API at Hardisty, Alberta (after deducting blending costs to reach pipeline quality).(4) Escalation is approximately 2% per year thereafter.Net Present Value of Future Production RevenueThe following table provides an estimate of the net present value of Enerplus’ future production revenue after deduction of royalties, estimated future capital and operating expenditures, before income taxes. It should not be assumed that the present value of estimated future cash flows shown below is representative of the fair market value of the reserves. Net Present Value of Future Production Revenue – Forecast Prices and Costs (before tax)Reserves at December 31, 2019, ($ Millions, discounted at)0%5%10%15%Proved developed producing$3,635$2,835$2,317$1,970Proved developed non-producing$27$21$17$14Proved undeveloped$1,751$1,174$824$595Total Proved$5,414$4,029$3,158$2,579Probable$3,470$1,902$1,192$815Total Proved Plus Probable Reserves (before tax)$8,884$5,932$4,349$3,394Contingent ResourcesThe following table provides a breakdown of the economic, unrisked best estimate contingent resources associated with a portion of Enerplus’ Fort Berthold, Marcellus, and Canadian waterflood assets as at December 31, 2019. These contingent resources are economic using the average of the three independent petroleum consulting firms’ price forecasts (McDaniel, GLJ and Sproule) as of January 1, 2020, use established technologies and are all classified in the “development pending” maturity sub-class. However, there is uncertainty that it will be commercially viable to produce any portion of the resources.The evaluations of contingent resources associated with a portion of Enerplus’ Canadian waterflood properties and leases at Fort Berthold were conducted by Enerplus and audited by McDaniel. NSAI evaluated 100% of Enerplus’ Marcellus shale gas assets in the U.S., including the estimate of contingent resources.Please see Enerplus’ Annual Information Form (“AIF”) – Appendix A for additional disclosures related to Enerplus’ contingent resources as at December 31, 2019. The AIF is available at www.enerplus.com as well as on the Company’s SEDAR profile at www.sedar.com. Development Pending Contingent ResourcesUnrisked “Best Estimate” Contingent ResourcesContingent Resources Net Drilling LocationsCanadaWaterfloods – IOR/EOR on a portion of waterfloods31.1MMBOE44.2Total Canada31.1MMBOE44.2United States PropertiesFort Berthold – Bakken/Three Forks Tight Oil wells45.1MMBOE94.7Marcellus – Shale gas663.5Bcf37.0Total United States155.6MMBOE131.7Total Company186.7MMBOE175.9Live Conference CallEnerplus plans to hold a conference call hosted by Ian C. Dundas, President and CEO, today, February 21, 2020 at 9:00 a.m. MT (11:00 a.m. ET) to discuss these results. Details of the conference call are as follows: Date:Friday, February 21, 2020Time:9:00 am MT/11:00 am ETDial-In:416-764-86881-888-390-0546 (toll free)Conference ID:95232985Audiocast:https://event.on24.com/wcc/r/2176880/2A1E6E1D61161621B4188BA9FED0158BTo ensure timely participation in the conference call, callers are encouraged to dial in 15 minutes prior to the start time to register for the event. A telephone replay will be available for 30 days following the conference call and can be accessed at the following numbers: Dial-In:416-764-86771-888-390-0541 (toll free)Passcode:232985 #Electronic copies of Enerplus’ 2019 MD&A and Financial Statements, along with other public information including investor presentations, are available on the Company’s website at www.enerplus.com. For further information, please contact Investor Relations at 1-800-319-6462 or email email@example.com.Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.