The Game Plan

U.S. B

Dana W. Johnson, President, U.S
U.S. Bakken 

Regional Overview

Sour

Enerplus land
Bakken & Three Forks Geology

Middle Bakke

Geological Age Mississippian Depth 10,500 – 11,00Thickness 35 – 45 ft Porosity 5 - 6% Overpressure 0.6 – 0.8 psi/ft OOIP/640 acres 4 - 6 MMbbl 

• Believe all our acreage is 

dual development

• Industry testing Three Fo

leasehold:

• Helis Oil and Gas D

produced 90 Mbbls offsetting our Fort Bthe west

• KOG 14-21-33-16H

1,042 BOE/d; 30 daBOE/day - only 6 o

Source: Tudor Pickering Holt & Co. completed 
Fort Berthold Reserves vs. Contingent Resour

• 22.4 MMBOE P+P re

• 24 booked drilling • Less than 1 year

locations

• 60 MMBOE of “best e

contingent resource frBakken only

• 90 future drilling • 65% long laterals• 85% land utilizati• ~15% recovery fa

• Incremental upside fro

Three Forks and dow

Almost 3x P+P 

reserve upside
Fort Berthold, North Dakota

• Bakken & Three Fo• Long lease tenure, 

acreage position

• 42° API, light sweet 

• High netback produ• Production growth t

BOE/day over next 

Key FactsNet Acreage Current Production P+P Reserves (Dec. 31, 2010) Contingent Resource Est. (Best) 

>90% operated & ~90% working interest
Recoveries Improving Over Time

6-10 

STAGES

6-7 

STAGES

10

STA

Peak *

4 Wells

Ave. $6.1 

MM/Well

Improving recoveries at Fort Berthold due 

to longer laterals, more frac stages and 

better completions

Peak *

5 Wells

Ave. $5.5 

MM/Well

ER

8 W

Ave. 

MM/

* Peak Oil & Gas
Fort Berthold Bakken Results to Date

Long Laterals

(9,000 ft. 24 frac stages)

Sho

(4,500 ft. 

Type

Curve

Actual 

4 Well avg

Type 

Curve

Average 30 day initial production (bbls/day) 1,100 – 1,200 1,250 550 – Expected Ultimate Recovery (Mbbls) 600 – 800 300 – Cost/Well ($/MM) $8.5 $8.5 $120 day Cumulative Production (bbls) 81,000 100,000 40,Expected Net Present Value (12%, $MM)* $11.2 - $18.0 $3.9 – $Expected Netback* ($/bbl) ~$50 ~Expected Payout Period (years) 0.8 – 1.3 1.3 – Expected F&D ($/BOE) $9.75 - $13.00 $13.50 - $18*Based on February 14, 2011 forward price•Royalties average 20%, plus state production tax of 11.5%, op costs of $4/bbl, Differential assumption of $
Fort Berthold Results

Long laterals are 35% ahead of the average type well prediction

Short laterals are 45% ahead of the average type well prediction
• Typical rigs are 1,000– 1,600 hp with top drive to 

improve performance; 2 of 4 drilling rigs in fleet are self moving (“walkers”)

• Measured depth of wells are ~20,000’ (TVD 10,700’) 

and drill in approximately 28 days

• Intermediate casing of 7” to the lateral• Liner 4.5” with swellable or mechanical external packers 

for isolations and mechanical sleeves for stimulation

• Frac design is 24 stages with ~125,000 lbs of high 

strength proppant per stage to retain long-term conductivity and improve reserve recovery per well

Enerplus Well Design Methodology

Source: Baker Tools
Fort Berthold Well Costs

Completions - 125,000 lbs of proppant/stage, $1.3 - $1.5 MM for ceramic 

- Water: 2,500 – 3,000 bbls/stage, $3 - 6/bbl for trucking & di

Tie-in - Additional $500,000

Expect pad drilling will materially decrease tie-in costs

Total Cost $8.5 MM Total Cost $5.7 MM
Current Development Plans

B B TF TF

TF

B TF

B

1320’ 1320’ 1320’

1280 acres

1280 acres

• Maximize long horizontals • Develop from pads: 2 Bakken/2 Thr

• Tie in as soon as possible• Test inter-well spacing

• Work with other operators to time d• Reduce cycle time to 45 days from 

of final well on pad to production

• Implement salt water disposal solut• Understand and successfully imple

simultaneous operations

• Drilling and completion of ad

on producing pads
Well Timeline

Well application / permit 

approval Site Build Drilling Waiting on Frac Crews 

4-6 months

• Environmental assessment

required on all federal lands

• Have 11 permits in hand or very 

late stage approval 

• Completing EA process on 

additional 30 permits - expect approval between April and June

• 50 permits are underway for 

submittal between now and August 

• Expect 40 additional permits 

submitted by year-end 

1 month• Cannot begin 

building site until permit in hand

1 month /well• Multi-well 

pads

• “walking rig” 

will help reduce drilling time

2 months 

• Shortage of 

basin-wide fleets relative to drilling activity

10 – 12 months
2011 Fort Berthold Bakken Plans

• 2011 capital program - $230 million • 32 net operated wells, 75% long horizontals• Targeting Bakken primarily; 3 to 8 Three Forks wells 

planned 

• 3 to 4 rigs working in the play• Recently entered into agreements to secure frac

services, proppant and a rig to help ensure timely execution of plans 

• Expect to have midstream service agreements in place in 

mid-2011 to capture associated gas and liquids 

4,

+2

ov
Execution Capability

• 4 rigs under contract 

• 2 active at present; 2 moving in 

March / April, conditions permitting

• Upgrading process• 2 “walkers” focused on pad drilling• Expect to sign at least one 

incremental rig by September 

• Frac services:

• Multi-year frac services agreement 

signed – should keep pace with 3 –4 rig program 

• Plan to drill 40 – 50 wells/year from 

2012 – 2016 to fully develop acreage (Bakken and Three Forks) 
Fort Berthold Production - Gathering• Enerplus has committed to a field gathering system at the Fort B

Reservation which will:

• Aggregate production at a central collection point off the Reservatio

provide flexible options for marketing the barrels

• Gather and monetize both gas and liquids at market prices

• Reduce the potential for shut in production due to varying weather, 

conditions, and availability of trucking contractors

• Provide some ability to better manage and dispose of produced wat• Reduce the number of trucks moving on the Reservation which will 

dust and road wear, and increase safety for the residents
U.S. Bakken Infrastructure Capacity

• Current U.

production MBOE/day

• 500 M

• Pipeline ca

• 80 MB• could 

MBOE

• Rail an

capac

0

100,000200,000300,000400,000500,000600,000700,000800,000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Mandan RefineryButte PipelineEnbridge North Dakota

Belle Fourche Proposal

Keystone XL Market Link

Plains Bakken ProposalEnbridge Bakken

55k150k186k

93k60k

100k

50k

80k

125k

Pipe 

Capacity Shortfall

Source: Internal company data and industry analysis

• Numerous new pipelines and expansions of over 300 MBOE/day are pro

address the takeaway shortfall

• We control some pipeline capacity and also sell to intermediaries who ho

existing pipelines or who have access to trucking/railing facilities

Barrels
Fort Berthold Production – Enerplus Regional Tran

05

10152025

2011 2012 2013 2014

'000 bbls / day 3rd Party Sales / Transport Enbridge Bakken Expansion

Belle Fourche ReversalFour Bears PipelineHistoric Enbridge Capacity

Basic 4 Rig ProMiddle Pace (6 

Current Transportation / Sales Arrangements in Place for 

Fort Berthold Development

Enerplus has the flexibility to use its Enbridge North Dakota Pipeline capacity 

Sleeping Giant (Elm Coulee) production as well.

2011 2012 2013 2014

25201510

50

‘000 bbls/day
Sleeping Giant Overview

Key FactsNet Acreage Current Production P+P Reserves (Dec. 31, 2012011 Capital Plans 

Enerplus Acreage

2011 planned wells 

Existing wells 

• Acquired in 200• Producing 42° li

from the Middle 

• Mature, cash ge

• nearly fully 

wells/sect

• limited rem

locations

• 2011 expected o

~$3.50/BOE and $50/BOE
Sleeping Giant – Technology Enhancing Re

0

50

100150200250300350400

0 30 60 90 120 

Normalized BOE/day

Days

Normalized Type Well Performance (3rd Wells per Section) @ Sleeping 

Average Type Performance - New Style Completions - Multi-Stage FracAverageType Performance - Old Style Completions

New completions improve recovery 
U.S. Bakken Summary

• Strategic asset for Enerplus for near-term growth and cash • Economics are best in our portfolio• Execution capability is critical• Three Forks potential• Managing the challenges while growing our operations