ERF: TSX & NYSE. CAPP ScotiaBank Conference

Transcription

1 ERF: TSX & NYSE CAPP ScotiaBank Conference April 12, 2016

2 Forward Looking Information Advisory FORWARD-LOOKING INFORMATION AND STATEMENTS This presentation contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws ("forward-looking information"). The use of any of the words "expect", "anticipate", "continue", "estimate", guidance, "ongoing", "may", "will", "project", "should", "believe", "plans", budget, "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this presentation contains forward-looking information pertaining to the following: expected 2016 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our funds flow; our drilling program, including future development locations and plans, the results from our drilling program and the timing of related production; future oil and natural gas prices and differentials and our commodity risk management programs; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; future efficiencies and reserves and production growth; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating costs; capital spending levels in 2016 and their impact on our production levels and land holdings; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes and regular U.S. taxes; future funds flow levels, including on per share basis; future debt and working capital levels and debt-to-funds flow ratios and adjusted payout ratios, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; the amount and timing of future cash dividends that we may pay to our shareholders; and future dispositions, including expected proceeds therefrom and production volumes associated therewith; and expectations regarding our measure to preserve our financial strength, including effectiveness thereof and amounts of anticipated savings therefrom. The forward-looking information included in this presentation 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: continued low commodity prices environment or further decline of commodity prices; changes in realized prices for Enerplus products; 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, incentive programs 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; inability to comply with debt covenants under our bank credit facility and outstanding senior notes; inaccurate estimation of Enerplus' oil and gas reserves and contingent resources 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; constraints on, or unavailability of, adequate pipeline and transportation capacity; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in our AIF and Form 40-F, described below and under Risk Factors and Risk Management in our MD&A, for the year ended December 31, 2015). The forward-looking information contained in this presentation reflects several material factors, expectations and assumptions made by Enerplus including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our 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 our reserve and resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing and funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our funds flow and availability under our bank credit facility to fund our working capital deficiency; our ability to negotiate debt covenant relief under our bank credit facility and outstanding senior notes if required; the availability of third party services; and the extent of our liabilities. Our 2016 revised guidance is based on WTI price of US$38.63/bbl, NYMEX gas price of US$2.43/Mcf, and AECO gas price of $2.27/GJ, and US/CDN exchange rate of We believe 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 purpose of our funds flow disclosure, including on a per share basis and sensitivity analysis, is to assist readers in understanding our expected and targeted financial results, and this information may not be appropriate for other purposes. The forward-looking information contained in this presentation speaks only as of the date of this presentation, and none of Enerplus or its subsidiaries assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws. 1

3 Enerplus Key Attributes Profitable Growth & Dividend Income Top Tier Assets Core growth positions in top resource plays North Dakota Bakken/Three Forks and Marcellus Supported by low-decline, high-margin assets with EOR upside Operational Excellence Track record of delivering on production and cost targets Proven technical expertise Consistently ranked as a leading operator in North Dakota Successfully applying new technologies to EOR development Strong results from investment in safety and regulatory processes Strong Financial Stewardship No near-term maturities on long-term debt; strong liquidity position Disciplined cost management Return focused capital allocation 2

4 Portfolio Repositioning Continued Optimization and Improved Concentration Improved portfolio focus: fewer, larger positions Production (BOE/day) 110, ,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10, ,000-20,000 $1, E Other (Shallow Gas, Deep Gas) Williston Basin Cumulative Net A&D Proceeds Canadian Waterfloods Marcellus Cumulative Net A&D Proceeds (1) ($MM) $1,200 $1,000 $800 $600 $400 $200 $0 -$200 3 areas now represent 95% of reserves 2P Reserves (MMBOE) % 18% 28% 47% Marcellus Williston Basin Waterfloods 36% 42% 17% 5% Other (Shallow Gas, Deep Gas) (2) 1) Net acquisition and divestment proceeds proceeds include completed transactions to the end of February ) Year-end P reserves are adjusted for Deep Basin divestment in Q ) 2016E production based on midpoint of guidance range (90 94 mboe/d) 3

5 Top Tier Asset Portfolio Canadian Oil Waterfloods 15,000 17,000 BOE/d 2016E Production Long-life, low decline Large discovered OOIP; 93 future net drilling locations and EOR potential Primary, secondary & tertiary recovery potential 52% 48% Liquids Natural Gas 30% 70% U.S. Oil Williston Basin Top tier acreage position at Fort Berthold Bakken/Three Forks 236 future net drilling locations Top quartile well performance 31,000 35,000 BOE/d U.S. Natural Gas Marcellus Top tier gas play 47,000 net acres with 128 future net drilling locations Canada MMcf/d U.S. 4

6 2016 Guidance: Preserving Financial Flexibility Key priorities: Maintain balance sheet strength 2016 divestment proceeds of $193MM have bolstered balance sheet Preserve value of high quality inventory Should commodity prices recover, incremental spending would be directed to growth 2016 Guidance (1) Capital Allocation US$38.63/bbl WTI US$2.43/Mcf NYMEX Capital Spending ($MM) $200 Average Production (BOE/day) 90,000 94,000 Funds Flow ($MM) $200 $20 $130 $50 Dividends ($MM) $37 Simple Payout Ratio 19% Adjusted Payout Ratio (APO) 120% APO, net of A&D (2) 28% Canadian Oil (Waterfloods) U.S. Oil (Williston Basin) U.S. Natural Gas (Marcellus) 1) Based on WTI US$38.63/bbl, NYMEX US$2.43/Mcf, AECO $2.27/GJ, US/CDN ) Includes completed divestments in

7 Debt Composition Debt Composition at December 31, 2015 Updated Senior Notes Maturities (1) Senior Unsecured Notes CDN$1,137MM Bank Credit Facility $800 million 11 banks in Enerplus bank credit facility Unsecured, covenant-based with current borrowing rate of 2.9% Credit facility matures October 31, 2018 Repurchased US$267 million (YTD 2016) at an average discount to par value of 95% Currently US$533 million and CDN$30 million in senior notes outstanding Notes are rated NAIC 2 (investment grade) and rank equally with bank credit facility; weighted average interest rate of 5% CDN $ Millions 140 $132 Undrawn Amount $713MM Drawn Bank Facility $87MM Senior Notes $1,107MM (2) $30MM (3) $29 $29 $59 $106 $106 $105 $105 $27 $27 0 $ ) Outstanding senior notes as at April 7, U.S. dollar denominated senior notes translated to Canadian dollars at an FX rate of US/CDN ) Canadian dollar equivalent of U.S. dollar denominated notes translated at December 31, 2015 FX rate of US/CDN ) Canadian dollar denominated notes 6

8 Fort Berthold Overview Fort Berthold, North Dakota Key Facts Discovered OOIP (1) MMbbls/1280 DSU Discovered OOIP (1) 1.4 billion bbls Recovery Factor 15% Net Acreage 74,000 acres 2P Reserves (2) 144 MMBOE Contingent Resources (3) 97 MMBOE Future Net Drilling Locations 236 wells (84 P+PUDs, 152 CR) 2P F&D Cost (2015) (4) $7.60/BOE 2016E Production 26,500 30,500 BOE/day 2015 Production 27,700 BOE/day 2016 Focus Bakken Three Forks Drilling/ WOC Continue to improve capital and operational efficiencies Optimize completion design by area 1) Operated acreage only 2) Gross working interest at Dec 31, ) Unrisked best estimate contingent resources at Dec 31, 2015 having a development status sub-class development pending 4) F&D cost includes future development costs 7

9 Fort Berthold Concentrated Core Position & Room to Run The Core represents ~10% of the basin ND Acreage Quality Avg Long Lateral s Peak Monthly Production By Township ND Drilling Density Total Wells per Township Lower well density in our operated townships Significant running room Enerplus has taken a measured approach to: Optimize completions Define the resource Manage financial risk CORE FLANKS Enerplus operated townships MARGINAL CORE MARGINAL INNER CORE CORE CORE INNER CORE Enerplus operated townships CORE FLANKS MARGINAL CORE MARGINAL INNER CORE CORE INNER CORE CORE CORE CORE 8

10 Fort Berthold Completions A Step Change in Productivity Significant Increase in Productivity Through Completion Evolution Fort Berthold Well Results Type Curve Economics (1)(2)(3)(4) Cumulative oil (bbls) 300, , , , , & 2015 wells 1,200 Mbbl EUR 900 Mbbl EUR 2013 wells 600 Mbbl EUR 2012 wells EUR (Mbbl) 1, EUR (MBOE) 1,400 1, Day Cum Prod (bbls) 48,118 36,089 1 st Year Cum Prod (bbls) 267, ,341 NPV 10% (US$MM) $6.5 $2.3 IRR Pretax (%) 41% 19% Payout (Years) BESC (US$/bbl) $37.80 $44.30 Capital (US$MM) $9.0 $9.0 50, Days 1) Economics are based on WTI US$50/bbl and NYMEX US$3.00/Mcf 2) Long horizontal wells. Capital assumption includes drill, complete tie-in and facility costs 3) BESC (break-even supply costs) based on 10% rate of return and are referenced to WTI 4) Sales point differential to WTI: -US$7.50 9

11 Enerplus Bakken Position: Among the Lowest Breakeven Costs in Lower 48 (1) Enerplus North Dakota wells in Fort Berthold had, on average, among the lowest breakeven costs in the lower 48 and the lowest among all Bakken players (1) 1) Source: RS Energy Group No More Guessing Jan 12,

12 Average Cumulative Production (Bcf) Marcellus Well Performance and Economics Marcellus Type Curves Type Curve Economics (1)(2)(3) Bcf Type Curve 10 Bcf Type Curve 2014 Onstream Actuals 2015 Onstream Actuals EUR (Bcf) IP30 (MMcf/d) IRR Pretax (%) 7% 18% NPV 10% (US$MM) -$0.7 $1.7 Payout (Years) BESC (US$/Mcf) $3.18 $ Capital (US$MM) $6.0 $ Basis (US$/Mcf) Basis diff to NYMEX (4) Incremental 2016 Annual Funds Flow ($MM) $ $0.75 $ $0.50 $ Note: Numbers on curves indicate gross wells Months on Production 1) Economics are based on NYMEX US$3.00/Mcf 2) BESC (break-even supply costs) are referenced to NYMEX 3) Basis differentials to NYMEX: US$1.25, 2017 US$1.00, 2018 & beyond: -US$0.50 4) Basis differential sensitivity is based on our 2016 guidance NYMEX price of US$2.43/Mcf (and US$1.00/Mcf basis) 11

13 Our Competitive Advantage Top-tier assets Demonstrated track record of delivering profitable growth in production, reserves and funds flow Strong operational capability with disciplined capital allocation and focus on improving capital efficiencies Prudent financial strategy & balance sheet management Attractive valuation 12

14 Supplemental Information

15 2016 Guidance 2016 Guidance 2016 Guidance (1) Capital Spending $200MM Average Production (BOE/d) 90,000 94,000 Average Liquids (bbls/d) 43,000 45,000 Operating Costs Transportation Expense Cash G&A $9.50/BOE $3.30/BOE $2.10/BOE Royalties & Production Tax (2) 23% 1) 2016 guidance assumptions: WTI of US$38.63/bbl, NYMEX of US$2.43/Mcf, and AECO $2.27/GJ, and US/CDN exchange rate of ) Based on % of gross sales, before transportation 14

16 Crude Oil Hedging Summary Q Q H 2016 Hedge position as % of forecasted production (1) Hedged Unhedged 45% 55% 64% 36% 74% 26% Volume (bbl/d) Price (US$/bbl) Volume (bbl/d) Price (US$/bbl) Volume (bbl/d) Price (US$/bbl) Swaps 9,000 $ ,000 $ Way Collars Sold Puts 8,000 $ ,000 $ ,000 $49.78 Purchased Puts 8,000 $ ,000 $ ,000 $63.98 Sold Calls 8,000 $ ,000 $ ,000 $ ) % of forecast production hedged is based on volumes after royalties and production taxes, and based on 2016 annual average production of 90,000 94,000 BOE/day 2) All prices are WTI 15

17 Natural Gas Hedging Summary Jan - Mar 2016 Apr - Oct 2016 Nov - Dec 2016 Hedge position as % of forecasted production (1) 19% 34% 22% Hedged Unhedged 81% 66% 78% Volume (Mcf/d) Price (US$/Mcf) Volume (Mcf/d) Price (US$/Mcf) Volume (Mcf/d) Price (US$/Mcf) Swaps 16,484 (2) $2.48 (2) 50,000 $2.53 (2) 25,000 $2.48 (2) 3 Way Collars Sold Puts 25,000 $ ,000 $ ,000 $2.50 Purchased Puts 25,000 $ ,000 $ ,000 $3.00 Sold Calls 25,000 $ ,000 $ ,000 $3.75 1) % of forecast production hedged is based on volumes after royalties and production taxes, and based on 2016 annual average production of 90,000 94,000 BOE/day 2) Weighted average volume and price 3) All prices are NYMEX 16

18 2016 Funds Flow Sensitivities 2016 Sensitivities Est. effect on 2016 Funds Flow ($ Million) Est. effect on 2016 Funds Flow per Share ($/share) Change of $5.00/bbl WTI crude oil $66 $0.32 Change of $0.50/Mcf NYMEX natural gas $44 $0.21 Change of 1,000 BOE/day production for rest of year $3 $0.01 Change of $0.01 in the USD/CDN exchange rate $3 $ Differential Outlook: * Mixed Sweet Blend (MSW) Western Canada Select (WCS) U.S. Bakken Marcellus Basis US($3.50)/bbl US($14.00)/bbl US($7.00)/bbl US($1.00)/Mcf * Before field transportation costs. Compared to $ WTI crude oil and $ NYMEX gas. The sensitivities and differentials above are based on forward prices at January 29, 2016 of: WTI US$38.63/bbl, NYMEX US$2.43/Mcf, AECO $2.27/GJ and a US/CDN FX rate of Per share metrics are based on approximately million shares outstanding. 17

19 Enerplus Board of Directors Elliott Pew, Chairman of the Board Mr. Pew has over thirty five years of diverse experience in the oil and gas industry, most recently as Co-Founder and Chief Operating Officer for Common Resources, a private exploration and production company in Houston, from 2007 until it was sold in Mr. Pew served on the Board of Managers for Common Resources II from , and later, Common Resources III from 2012 to present. Mr. Pew held various senior executive positions with Newfield Exploration Company in Houston, where he served from 1998 through While there, he led the company s worldwide exploration program, including the GOM shelf, GOM deepwater, onshore US, and international areas. Further, he also led expansion efforts into the onshore Gulf Coast in the late 1990s. Prior to Newfield, Mr. Pew was Senior Vice President-Exploration of American Exploration Company in Houston. Mr. Pew currently serves on the Board of Directors for Southwestern Energy Company, a public exploration and production company in Houston. He holds an M.A.in Geology from the University of Texas at Austin, and an A.B. in Geology from Franklin and Marshall College. David H. Barr, Director Mr. Barr has 38 years of experience in the oil and gas industry, and is President and Chief Executive Officer of Logan International Inc., a company focused on downhole tools and completion services. He was formerly Chairman of the Board of Logan International. He also spent close to 36 years with Baker Hughes in various executive roles, including Group President of numerous divisions and President of Baker Atlas. He currently serves as a Director of ION Geophysical Corporation and Probe Technology Services. Mr. Barr holds a B.S. Mechanical Engineering degree from Texas Tech University. Michael R. Culbert, Director Mr. Culbert brings over thirty years of diverse experience in the oil and gas industry in North America and is currently the President, Chief Executive Officer and a Director of Progress Energy Canada Ltd. He brings a strong background in business development, economics and strategic planning and holds a Bachelor of Science degree in Business Administration. He currently sits on the Board of Directors of Pacific NorthWest LNG Ltd. and is also a member of the Canadian Association of Petroleum Producers Board of Governors. Ian C. Dundas, Director Mr. Dundas became President and Chief Executive Officer of Enerplus on July 1, He joined the company in 2002 as Vice-President of Business Development, with accountability for all corporate acquisition and divestment strategies. In 2010, his role expanded to that of Executive Vice-President. In 2011, his responsibilities were further expanded to include the role of Chief Operating Officer, overseeing the development and execution of the company s operational strategies, strategic planning, marketing, reserves, as well as acquisitions and divestments. As President and Chief Executive Officer, Mr. Dundas is responsible for overall leadership of the strategic and operational performance of Enerplus. Hilary A. Foulkes, Director Ms. Foulkes has more than 30 years of experience within the Canadian oil and gas industry focused in the areas of exploration, development and investment banking. Ms. Foulkes is currently the Chair of Tudor, Pickering, Holt & Co. Securities Canada, a private energy advisory firm, and is a Director of Parallel Energy Trust, a Canadian oil and gas energy trust. She has held executive roles in both investment banking and oil and gas operations, including Executive Vice- President and Chief Operating Officer for Penn West Petroleum Ltd. She is a professional geologist and earned a Bachelor of Science (Honours, Earth Sciences) from the University of Waterloo. Her career highlights include being the architect and lead negotiator of award-winning, multi-billion dollar international joint ventures. 18

20 Enerplus Board of Directors continued Robert B. Hodgins, Director Mr. Hodgins has been an independent businessman since November Prior to that, Mr. Hodgins served as the Chief Financial Officer of Pengrowth Energy Trust (a TSX and NYSE-listed energy trust) from 2002 to Prior to that, Mr. Hodgins held the position of Vice President and Treasurer of Canadian Pacific Limited (a diversified energy, transportation and hotels company) from 1998 to 2002 and was Chief Financial Officer of TransCanada PipeLines Limited (a TSX and NYSE-listed energy transportation company) from 1993 to Mr. Hodgins received a Bachelor of Arts in Business from the Richard Ivey School of Business at the University of Western Ontario in 1975 and received a Chartered Accountant designation and was admitted as a member of the Institute of Chartered Accountants of Ontario in 1977 and Alberta in Susan M. MacKenzie, Director Ms. MacKenzie has over 25 years of energy sector experience, most recently serving as Chief Operating Officer with Oilsands Quest Inc. in 2010 and currently serves as a Director of Enerplus, Freehold Royalties Ltd., a Canadian oil and gas royalty focused company and TransGlobe Energy Corporation, a Canadian oil and gas company. Prior to that, Ms. Mackenzie enjoyed a 12-year career at Petro-Canada where she held senior roles including Vice-President of Human Resources and Vice President of In Situ Development & Operations. Ms. MacKenzie was also with Amoco Canada for 14 years in a variety of engineering and leadership roles in natural gas, conventional oil and heavy oil exploitation. Ms. MacKenzie holds a Bachelor of Engineering (Mechanical) degree from McGill University, an MBA from the University of Calgary and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA). Glen D. Roane, Director Mr. Roane is a corporate director and currently serves as a director of Enerplus, Badger Daylighting Ltd. and Logan International Inc. Mr. Roane is also a member of the Alberta Securities Commission. Previously he served as a board member of many TSX-listed companies and private companies including Repap Enterprises Inc., Ranchero Energy Inc., Forte Resources Inc., Valiant Energy Inc., Maxx Petroleum Ltd., UTS Energy Corporation, Destiny Resource Services Ltd., NQL Energy Services Inc., Severo Energy Ltd., Flexpipe Systems Inc., Tarpon Energy Services Ltd., SilverWillow Energy Corporation and the GBC American Growth Fund. Mr. Roane retired from TD Asset Management Inc., a subsidiary of The Toronto-Dominion Bank in Previously he was a founding partner of Lancaster Financial Inc., a financial advisory and investment management firm and was formerly employed by Burns Fry Limited and by the Toronto Dominion Bank. Mr. Roane holds a Bachelor of Arts (1977) and an MBA (1979) from Queen's University in Kingston, Ontario and holds the ICD.D designation from the Institute of Corporate Directors. Sheldon B. Steeves, Director Mr. Steeves has over 37 years of experience in the North American oil and gas industry and is currently a Director of NuVista Energy Ltd., a Canadian oil and gas company with operations in the Western Canadian sedimentary basin and of PrairieSky Royalty Ltd., a Canadian oil and gas royalty focused company. From January 2001 until April 2012, Mr. Steeves was Chairman and CEO of Echoex Ltd., a junior private company focused on greenfield organic growth in Western Canada. Mr. Steeves spent over 15 years at Renaissance Energy where he was appointed Chief Operating Officer in He holds a Bachelor of Science in Geology from the University of Calgary. 19

21 Advisories Assumptions All amounts are stated in Canadian dollars unless otherwise specified. Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent This presentation contains references to "BOE" (barrels of oil equivalent) and "BcfGE" (billion 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 BcfGEs. BOEs and BcfGEs 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 oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading. "MBOE" and "MMBOE" mean "thousand barrels of oil equivalent" and "million barrels of oil equivalent", respectively. Non-GAAP Measures In this presentation, we use the terms "funds flow", debt to funds flow, netback, adjusted payout ratio, and capital efficiency as measures to analyze operating performance, leverage and liquidity. Funds flow is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. Debt to funds flow ratio is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The debt to funds flow ratio is calculated as total debt net of cash, divided by a trailing 12 months of funds flow. Netback is calculated as oil and gas revenues after deducting royalties, operating costs and transportation expenses. Capital efficiency is calculated as the total capital expenditures from the fourth quarter of the previous year up to and including the third quarter of the current year, divided by the change in production from the fourth quarter of the previous year to the fourth quarter of the current year, including base decline. Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "funds flow", netback, and "capital efficiency 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 U.S. GAAP and do not have a standardized meaning prescribed by U.S.GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. For reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about these measures, see disclosure under Non-GAAP Measures in our 2015 Management s Discussion & Analysis. Presentation of Production and Reserves Information Under U.S. GAAP, oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under IFRS and Canadian industry protocol, oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. To remain comparable with our Canadian peer companies, the summary results contained within this presentation presents our production and BOE measures on a before royalty company interest basis. In addition, initial test results and production performance referenced should be considered preliminary data and such data is not necessarily indicative of long-term performance, or of ultimate recovery. Readers are cautioned that the average initial production rates contained in this presentation are not necessarily indicative of long-term performance or of ultimate recovery. All production volumes and revenues presented herein are reported on a company interest basis, before deduction of Crown and other royalties, plus Enerplus royalty interest. Unless otherwise specified, all reserves volumes in this presentation (and all information derived therefrom) are based on gross reserves" using forecast prices and costs. Gross reserves" (as defined in National Instrument Standards of Disclosure for Oil and Gas Activities (NI ), being Enerplus working interest before deduction of any royalties. Our oil and gas reserves statement for the year ended December 31, 2015 includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI , and is contained within our Annual Information Form for the year ended December 31, 2015 ("our AIF") which is available on our website at and under our SEDAR profile at Additionally, our AIF forms part of our Form 40-F that is filed with the U.S. Securities and Exchange Commission and is available on EDGAR at Readers are also urged to review the Management s Discussion & Analysis and financial statements filed on SEDAR and as part of our Form 40-F on EDGAR for more complete disclosure on our operations. Discovered Petroleum Initially-In-Place and Discovered Original Oil-In-Place Discovered Petroleum Initially-In-Place ( PIIP ) is that quantity of petroleum that is estimated to be contained in known accumulations prior to production. The recoverable portion of discovered PIIP includes production, reserves and contingent resources; the remainder is unrecoverable. Discovered Original Oil in Place ( OOIP ) is not defined in NI and does not have a standardized meaning under NI Discovered OOIP as used in this presentation is the crude oil portion of discovered PIIP. Discovered OOIP for our North Dakota assets were provided by an independent estimate by McDaniel & Associates Ltd. dated June 9, 2014 and as of June 1, Discovered OOIP pertaining to our Canadian waterflood assets are estimates by internal qualified reserves evaluators, combined for all Canadian waterflood assets. See our AIF for disclosure of specific categories assigned to our reserves and contingent resources. 20

22 Advisories Contingent Resources Estimates This presentation contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with oil and gas reserves. The estimates of contingent resources included in this presentation pertaining to Canadian waterflood assets and Fort Berthold were evaluated by Enerplus internal qualified reserves evaluators and audited by independent reserves evaluators, McDaniel & Associates Ltd. The estimates of contingent resources included in this presentation pertaining to the U.S. Shale Gas-Marcellus were evaluated by independent reserves evaluators, Netherland, Sewell & Associates, Inc. "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 economics, 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. All of our contingent resources estimates are economic using established technologies and based on January 1, 2016 forecast prices of McDaniel & Associates Ltd. Enerplus expects to develop these contingent resources in the coming years, however it is too early in their development for these resources to be classified as reserves at this time. There is no certainty that it will be commercially viable for us to produce any portion of the volumes currently classified as contingent resources. Development pending contingent resources refer to a contingent resources sub-class for a project where resolution of the final conditions are being actively pursued (there is a high chance of development) and the project is expected to be developed in a reasonable timeframe. The contingent resources estimates contained herein are presented as the "best estimate" of the quantity that will actually be recovered. Contingent resources estimates are effective as of December 31, 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 additional information regarding the primary contingencies which currently prevent the classification of our disclosed contingent resources associated with our Marcellus shale gas properties, our Fort Berthold properties, and a portion of our Canadian waterflood properties as reserves, and the positive and negative factors relevant to the "contingent resource estimates, see Appendix A to our AIF, a copy of which is available under our SEDAR profile at and our Form 40-F, a copy of which is available at Finding & Development ( F&D )and Finding, Development & Acquisition ( FD&A ) Costs F&D costs presented in this presentation are calculated (i) in the case of F&D costs for proved reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated proved future development costs in the year, by the additions to proved reserves in the year, and (ii) in the case of F&D costs for proved plus probable reserves, by dividing the sum of exploration and development costs incurred in the year plus the change in estimated proved plus probable future development costs in the year, by the additions to proved plus probable reserves in the year. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally reflect total finding and development costs related to its reserves additions for that year. FD&A costs presented in this presentation are calculated (i) in the case of FD&A costs for proved reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred in the year plus the change in estimated proved future development costs in the year, by the additions to proved reserves including net acquisitions in the year, and (ii) in the case of FD&A costs for proved plus probable reserves, by dividing the sum of exploration and development costs and the cost of net acquisitions incurred in the year plus the change in estimated proved plus probable future development costs in the year, by the additions to proved plus probable reserves including net acquisitions in the year. The aggregate of the exploration and development and net acquisition costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding, development and acquisition costs related to its reserves additions for that year. See "Non-GAAP Measures" above. NOTICE TO U.S. READERS The oil and natural gas reserves information contained in this presentation 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 gross (or, as noted above with respect to production information, "company interest") volumes, which are 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 in SEC filings, 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 Contingent Resources Estimates above. 21

23 Investor Relations Contacts Drew Mair Manager, Investor Relations Krista M. S. Norlin Sr. Investor Relations Analyst The Dome Tower Suite 3000, 333 7th Ave SW Calgary, AB Canada T2P 2Z1 22