Investor Presentation

1
Investor Presentation

• October 2006

2
Enerplus

• Celebrating 20 years as the first oil and gas
  income trust in Canada
• Significant internal development opportunities
  across a variety of play types
• One of the longest RLIs in the sector
• Disciplined approach to acquisitions
• Large size offers advantages in acquisitions and
  strategic investments
• Unique exposure to U.S. Bakken oil and Canadian
  oil sands

3
Corporate Profile

• FINANCIAL
• Market Capitalization 6.3 Billion
• Total Enterprise Value (1) 6.9 Billion
• Trading Symbols (TSX/NYSE) ERF.un/ERF
• YTD Avg. Daily Trading Value (2) 45 Million
• Debt/12 Month Trailing Funds Flow Ratio (3)
  0.7x
• Current Annualized Yield (4) 9.8
• OPERATIONAL
• Proved Probable Reserve Life Index (5) 13.5
  years
• 2006 Daily Production Outlook 84,000 BOE/day
• crude oil and natural gas liquids 47
• natural gas 53
• 2006 Exit Production Rate Outlook 89,000 BOE/day
• Production Operated 65
• 2006 Capital Development Budget 485 Million

• Market Cap. at November 6th, 2006 plus
  outstanding debt (net of cash) at June 30th, 2006
• Calculated using average daily volumes traded YTD
  x weighted average daily closing price figure
  YTD, (NYSE figures adjusted to account for FX _at_
  CDN 0.89 / US 1.00)
• At June 30th, 2006
• Calculated using the November 20th distribution
  multiplied by 12 months and divided by the
  November 6th closing price on the TSX
• Company interest reserves at December 31st, 2005

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Balanced Strategy
Organic Growth
Accretive Acquisitions

• Lyco Energy Corporation
• Sleeping Giant LLC
• ChevronTexaco Assets

• Resource play focus conventional and
  unconventional
• 4 years of identifiable conventional development
  opportunities
• Strong in-house technical team

Long-Term Sustainability
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Competitive Advantages

• Enjoy one of the longest reserve life indices in
  our sector
• Lower base declines
• Supports selective acquisitions
• Reduces impact of commodity price drops
• Encourages patient investment
• Resource play focused
• Relatively low geologic risk
• Potential for large scale development
• Attractive long-term declines and RLI
• Predictable results

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Competitive Advantages

• Diversification by property and commodity
• Valuable insights across the industry
• Expanded opportunity set
• Balanced commodity mix
• Execution Capabilities
• Size and purchasing power
• Partner orientation
• Strong project management skills
• Experienced technical staff

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YTD Highlights

• YTD production has average 85,335 BOE/day, ahead
  of expectations, resulting in an increase in our
  2006 production guidance to 85,500 BOE/day
• Operating costs are in line with expectations,
  but given our higher production volumes, we have
  lowered our full year estimate to 7.80/BOE
• Our payout ratio has averaged 69 for the first
  nine months and resulted in over 208 million
  reinvested into our asset base
• We continue to expect our internal development
  program will replace our annual production
  decline and have spent 368 million YTD on
  development and drilling activities
• Our debt to cash flow ratio remains one of the
  lowest in the sector at 0.6x

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5 Year Performance
Represents a 5 year simple return of 39 per
annum to investors (1)
Cumulative Distributions - 21.48 (2)

• At November 6th, 2006
• Based on a declared but unpaid November
  distributions of 0.42

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5 Year Reserve Life Index
Calculated using proved probable reserves for
2003 2005. Prior years reflect established
reserves
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Active Developer
DrillingSuccess Rate
99
98
99
99
99
Development Capital Spending
368.1
Capital spending and success rate YTD 2006
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Long-term Sustainability
Debt Distribution-adjustedReserves per Unit
Debt Distribution-adjustedProduction Per Unit
(1)
(2)
Debt Distribution-Adjusted
Debt-Adjusted
13.4
26.3
(1) Based on proved plus probable reserves at
December 31. Debt-adjusted by replacing year-end
debt with units created at year-end unit price.
Debt-adjusted as described and distribution-adjust
ed by canceling units with annual cash
distributions using weighted average unit price

• (2) Debt-adjusted by replacing quarterly change
  in debt with units created using quarter-end unit
  price. Debt-adjusted as described and
  distribution-adjusted by canceling units with
  each quarters cash distributions using
  quarter-end unit price

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Strategically Positioned

• Internal development opportunity set on
  conventional assets has increased to almost 1
  billion (over 1,500 drilling locations currently
  identified)
• Potential for 200 million in SAGD development
  and 500 million in mining development associated
  with our oil sands project before considering a
  potential upgrader or mining expansions
• Establishment of our U.S. office in Denver
  positions us to expand our investment and
  capitalize on opportunities in the U.S.
• Investing significant capital for future
  production and cash flow beyond 2006

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Key Resource Plays

• Joslyn Oil Sands Project
• Enerplus is one of the only conventional oil
  gas trusts with a significant interest in the
  oil sands
• Sizeable mining and SAGD development project

• Crude Oil Waterfloods
• Represents 20 of our current production
• Predictable secondary recovery scheme with low
  decline rates and significant original oil in
  place

• Other Conventional Oil Gas
• Includes a variety of both operated and
  non-operated oil gas production
• Diverse property set provides numerous
  development opportunities

• Shallow Natural Gas
• Long life, sweet gas representing 15 of our
  current production
• Will represent approximately half of our
  drilling activity in 2006

• Coalbed Methane
• This emerging resource play is characterized
  by low risk, repeatable drilling opportunities
• Principal activity to date focused on the
  Horseshoe Canyon formation

• Bakken Oil
• Produces over 11,600 BOE/day or 14 of our
  current production
• 42 degree API oil with low operating costs

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Crude OilWaterflood Development

• 12 major and 15 minor waterflood properties
• Approximately 20 of current production and 24
  of reserves with over108 MMBOE
• Proved plus probable RLI of 16.9 years
• Contain 1.4 billion barrels of OOIP with an
  average expected ultimate recoveryof 39
• Have invested 48.2 million for the 9 months YTD
  on drilling, recompletions, stimulations and
  optimization activities

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Shallow Natural GasProduction Growth

• 15 of current production
• 20 of reserves with over 540 billion cubic feet
  of proved plus probable reserves (90 MMBOE)
• Proved plus probable RLI of 15.9 years
• Drilled in excess of 1,350 net wells since 1998
• Have invested 39.6 million YTD to drill 181.0
  net wells
• Key development activities during the third
  quarter occurred at Hanna, Bantry, Medicine Hat,
  and Shackleton

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Bakken Resource Play

• The Bakken is the primary oil charged formation
  within the Williston Basin
• Large, aerially extensive accumulations of light
  oil with very low geological risk
• Potential for material impact due to size,
  excellent economics, repeatability and long
  reserve life
• Relatively predictable timing, cost, production
  rate and reserves (manufacturing-like in nature)
• Ongoing value creation from technology and
  program execution (drilling times, frac design,
  optimization of well length and well spacing, and
  improved recovery)

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Sleeping Giant Project

• Operated property producing from the Bakken
  formation in Richland County, Montana with an
  average W.I. of approximately 70 in lands held
• High netback sweet crude oil (42 API) with
  operating costs of 1.80/BOE
• 133 horizontal/ 9 vertical wells currently
  producing over net 11,600 BOE/day
• 25 remaining drilling locations identified in the
  Sleeping Giant Project (for full development to 2
  wells/section), with 3 rigs contracted
• 120,000 net acres of undeveloped land in Montana
  North Dakota
• Additional potential upside in higher density
  infill drilling, waterflooding, CO2 flooding and
  high pressure air injection

Saskatchewan
Manitoba
Williston Basin Bakken OilProducers
Montana
North Dakota
Bakken Oil Wells
Enerplus lands
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Canadian Oil SandsBackground

• Widely viewed and accepted as the cornerstone of
  Canadas production growth
• Oil sands production now exceeds1 million
  bbls/day and is expected to increase to nearly
  3.5 million bbls/day by 2015
• 175 billion barrels of proved recoverable
  remaining reserves in the oil sands
• 20 of reserves attributed to mining projects
• 80 of reserves attributed to in-situ production
  such as SAGD
• Proved conventional oil reserves in Canada only
  4.4 billion barrels
• Enerplus is one of the only conventional oil
  gas trusts with a significant interest in the oil
  sands

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Joslyn Project

• Acquired 16 W.I. in Joslyn Oil Sands project in
  2002 for 16 million
• Joslyn has 2 billion barrels of gross(300 MMbbls
  net to Enerplus) recoverable resources
• In 2005, Total S.A. acquired our partner Deer
  Creek Energy Limited for 1.7 billion
• Expect production from the first commercial SAGD
  Phase to begin in 2007 with peak production in
  2008
• Application filed for first mining phase in
  February. Interim reserve report from our
  independent engineers confirms a recoverable
  resource of 950 MMbbls (142 MMbbls net to
  Enerplus) for this first mining phase
• In Q106, we sold 1 of our 16 Joslyn working
  interest for an equity position in Laricina
  Energy Ltd., an emerging oil sands company
• In addition to our Joslyn activities, we continue
  to evaluate new areas primarily with a focus on
  expanding our oil sands business into other SAGD
  areas

Oil Sands Project Utilizing Steam Assisted
Gravity Drainage Mining
30 year project life
Mining
Phases I II - 200,000 barrels of bitumen per day
SAGD
Phases I to III - 25,000 barrels of bitumen per
day
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Joslyn Project
TOTALS PLANS (1)
(1) The information presented in this table
reflects Enerplus 15 working interest after the
sale of 1 to Laricina. GLJ estimates may vary
from Totals.(2) Start up for SAGD refers to
initial steaming. Start up for mining refers to
initial extraction.
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Hedging Overview
Our risk management strategies are designed to
partially mitigate a volatile price environment
while providing a degree of stability to the
economics associated with our acquisitions and
development projects, together with our overall
financial position.
(1) Daily production volumes based on 06 YTD
average daily production, volumes net of royalties
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Decreasing Payout Ratios
(1)
(1) Before the costs of internalization
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Cash Distributions
September 2004 September 2006
2004
2005
2006
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10 Year Compound Return
September 1, 1996 August 31, 2006 (1)
(1) Sources Bloomberg TSX MarketData for
SP/TSX Capped Energy Trust Index Assumes the
reinvestment of distributions and/or dividends
Based on the weekly closing price of Enerplus
trust units on the Toronto Stock Exchange.
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Analyst Coverage
Company Analyst (Canada) BMO Nesbitt
Burns Gordon Tait CIBC World Markets Brad
Borggard Canaccord Capital Bruce McDonald
FirstEnergy Capital Corp. Jill Angevine National
Bank Financial Menal Patel Peters Co.
Limited Jeff Martin RBC Dominion Securities Dirk
Lever   Raymond James Kristopher Zack Scotia
Capital Brian Ector TD Newcrest Roger
Serin Tristone Capital Cristina Lopez (United
States) Citigroup Richard Roy Merrill Lynch
Andrew Fairbanks Morningstar Kish Patel
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Summary

• Proven track record and expertise in the oil and
  gas industry with demonstrated sustainability
  through several price cycles
• Significant development inventory available to
  replace production organically
• Superior assets with one of the longest RLIs in
  the oil and gas sector
• Focused on long-life resource plays shallow gas,
  oil waterfloods, Bakken oil, CBM and oil sands
  development
• Size advantage in acquisitions and project
  development, operating in both Canada and the U.S.

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Disclaimer

• Except for the historical and present factual
  information contained herein, the matters set
  forth in this presentation, including words such
  as expects, projects, plans and similar
  expressions, are forward-looking statements
  within the meaning of applicable securities
  legislation. These forward-looking statements
  are subject to risks and uncertainties which may
  cause actual results to differ materially from
  current expectations. Many of these risks and
  uncertainties are described in Enerplus' Annual
  Information Form under the heading Risk
  Factors and in the Management's Discussion and
  Analysis in the Annual Report under the heading
  Risk Factors and Risk Management. Readers are
  also referred to risk factors described in other
  documents Enerplus files with the Canadian and
  U.S. securities authorities. Copies of these
  documents are available without charge from
  Enerplus.
• Enerplus files reports and other information with
  the Canadian securities authorities and the U.S.
  Securities and Exchange Commission. Some of these
  reports and other information have been prepared
  in accordance with the disclosure requirements in
  Canada which differ from those in the United
  States. All of Enerplus Canadian public filings
  are available at www.sedar.com and all U.S.
  public filings are available at www.sec.gov.
• All financial figures are in Canadian dollars
  unless otherwise stated
• Enerplus financial statements are prepared in
  accordance with Canadian generally accepted
  accounting principles (GAAP). Canadian GAAP
  differs in some significant respects from U.S.
  GAAP and therefore this financial information may
  not be directly comparable to the financial
  information typically provided by U.S. companies.
  The principal differences as they may apply to
  Enerplus are summarized in Note 15 to the Funds
  audited consolidated financial statements for the
  year ended December 31, 2005. A complete copy of
  the audited financial statements and notes is
  available without charge from Enerplus.

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Disclaimer

• Enerplus uses the terms funds flow from
  operations and cash available for
  distribution. These terms do not have any
  standardized meaning as prescribed by Canadian
  GAAP and therefore may not be comparable with the
  calculation of similar measures for other
  entities.
• Enerplus has adopted the standard of 6 Mcf1
  barrel of oil equivalent (BOE) when converting
  natural gas to BOEs. BOEs may be misleading,
  particularly if used in isolation. A BOE
  conversion ratio of 6 Mcf1 BOE is based on an
  energy equivalency conversion method primarily
  applicable at the burner tip and does not
  represent a value equivalency at the wellhead.
• Unless otherwise stated, all production volumes
  are stated on a gross basis, that is, our working
  interest production before the deduction of any
  royalty interest production.
• Unless otherwise stated, reserve figures and any
  resulting metrics are calculated based upon
  company interest reserves using forecast prices
  and costs. Company interest reserves are our
  working interest (operated and non-operated)
  share of reserves before the deduction of any
  royalty interest reserves, but inclusive of any
  royalty interest reserves owned by Enerplus.
  Company interest is not a term defined or
  recognized under National Instrument 51-101 (NI
  51-101) and does not have a standardized meaning
  under NI 51-101. Full NI 51-101 compliant reserve
  disclosure is available in our Annual Information
  Form under the heading Oil and Natural Gas
  Reserves.