39
A Deeper Look into the Williston Basin June 18, 2014 ERF – TSX & NYSE
A Deeper Look into the Williston Basin
June 18, 2014
ERF – TSX & NYSE
Significant Increase in Asset Value
More Resource: 50% increase in original oil in place (“OOIP”) driving increase of 97 MMBOE of new contingent resource
More Locations: 127% increase in drilling inventory
Better Economics: Capital efficiency improvements leading to better profitability
More Growth: Increased production, reserves and funds flow potential
2
3
Fort Berthold – A Core Asset
• 22% of 2014 corporate production*
• 26% of 2P reserves
• 40% of 2014 capital spending*
* Based on 2014 guidance estimates
Fort Berthold – Significant Value Creation
4
Original Acquisition (2009/2010) $600 MM
Net Capital Investment * $425 MM
Total Investment $1,025 MM
2P NPV10% @ Dec. 31, 2013 $1,500 MM
Current Contingent Resource est. 136 MMBOE
• Production 3 year CAGR +100%
• Reserves 3 year CAGR ~70%
• Generating free cash flow
* to December 31, 2013
CAGR is defined as the compound annual growth rate.
Fort Berthold:
Increasing Resource
Top Tier Oil Asset: Fort Berthold, North Dakota
Key Facts at December 31, 2013
Net Acreage 73,000 acres
(114 sections)
2P Reserves
Producing Wells:
Bakken wells
TF1
Total
105 MMBOE
74
25
99
Future Net Drilling Locations:
PUD locations
Cont. Resource locations
Total future locations
98
47
145
2P NPV10%* at Dec. 31/13 $1.5 billion
Contingent Resource at Dec. 31/13 39 MMBOE
6
~90% W.I.
Bakken
Three Forks
Drilling/ WOC
* Based on company interest proved plus probable reserves using McDaniel & Associates forecast pricing assumptions.
Detailed Evaluation Increases OOIP
7
• New assessment includes evaluation of
155 wells with log data and 50 wells with
core data across acreage and
surrounding area
• OOIP increase driven by:
higher oil saturation in both the
Bakken and TF1
some thickness and porosity
contribution
some TF2 contribution
excludes TF3 and TF4, and Upper
& Lower Bakken Shale
250% Increase in Contingent Resource
Original
Assumption
2014
Evaluation Increase
OOIP per DSU*
Bakken
TF1
TF2
Total
8 – 12 MMbbls
8 – 10 MMbbls
n/a
16 – 22 million bbls
8 – 16 MMbbls
10 – 16 MMbbls
2 – 20 MMbbls
20 – 42 million bbls 4 – 20 MMbbls
TOTAL WI OOIP 1 billion bbls 1.5 billion bbls 500 MMbbls
2P Reserves @ Dec. 31/13 105 MMBOE 105 MMBOE -
Contingent Resource
Utilization Assumptions:
Bakken
TF1
TF2
39 MMBOE
100%
70%
n/a
136 MMBOE
100%
100%
35%
97 MMBOE
8 * Per 1,280 acre drilling spacing unit (DSU)
Fort Berthold:
Increasing
Drilling Inventory
Well Density Schematic
10
6 / 7 Well Density* No Lower Three Forks Stand-Alone Locations
8 Well Density* Lower Three Forks
Productive
* Assumes 15% recovery factor.
** ”Super unit” equivalent to lease line drilling.
TF 2 &3 Upside** TF3 & Additional
TF Wells
Successful Industry Downspacing
• Over 175 DSUs with 6 wells or more have been drilled in North Dakota
• No decrease in industry performance in 7 well density tests (4 Bakken/ 3 TF1 wells)
• Lower TF benches can support increased density in certain areas
11
Enerplus Furbearers
Downspacing Test
Enerplus Snakes
Downspacing Test
Industry downspacing
Enerplus spacing unit
0
10
20
30
40
50
60
70
80
90
100
110
120
130
140
150
0 50 100 150
Cu
m O
il (
Mb
bl)
Days on Production
High Density Well Performance Prairie Dog 150-94-04A-09H
Fox 150-94-04A-09H
Bobcat 150-94-04A-09H
Hognose 152-94-18B-19H TF2
Ribbon 152-94-18B-19H
12
Encouraging Enerplus High Density Tests
Bakken
Three Forks
Drilling/ WOC
Snakes Pad
8 Well Density & TF2
Enerplus down spacing test
(7 well density)
Enerplus down spacing test &
TF2 test
Fur Bearers Pad Snakes Pad Fur Bearers pad
7 Well Density
Increasing to Average 7 Wells/DSU
13
8
6,7,8
6 or 7
Northwest • Highest estimate of OOIP
• Includes TF2
• 8 well density
Central/West • Well density ranging from 6 – 8 wells
depending upon OOIP and TF2 prospectivity
Central/South • Planned for 6 or 7 well density depending
upon OOIP and recovery factor
Enerplus Hognose
Successful TF2
Enerplus
Butterflies TF2
Drilling
Industry
TF2/TF3
Planned
127% Increase in Drilling Inventory
Locations
Original View
4 wells/
DSU
New View
Avg. 7 wells/
DSU
Bakken—Long 53 124
Three Forks—Long 66 89
119 213
Bakken—Short 21 63
Three Forks—Short 5 53
26 116
Total Net Future
Drilling Locations* 145 329
14
• 184 new locations added
Two thirds of locations are
long laterals
• Average 7 wells per DSU with
maximum of 8 wells
in a DSU
• Increased land utilization
• Average EUR per well Long 625 Mbbls/750 MBOE
Short 320 Mbbls/385 MBOE
* Includes Undeveloped Reserves and Contingent Resource locations
Fort Berthold:
Improving
Operational Execution
Improving Productivity through Completion Enhancements
16 16
Cum.
Oil
Per
1000
Lateral
Feet
30 60 90 120 150 180 210 240 270 300 330 Days
360 390 420 450
,
Bakken Wells
Completion Evolution Increasing Production Rates
17
Oil
(Mbbls
)
30 Day Cum. Oil
Completion Costs/Stage
• Despite larger fracs, the
switch to sand and effective
cost management has
helped reduce completion
costs
• Significant increase in 30
day cumulative production
from high intensity fracs
BKN TF
US
$K
Improving Capital Efficiencies*
18
$12,000
$10,000
$8,500
$7,000
$6,000
$-
$5,000
$10,000
$15,000
2012Ceramic;
23-29 Stages(~275 lbs/ft)
2013 Ceramic;28 Stages
(~325 lbs/ft)
2013White Sand;28 Stages
(~750 lbs/ft))
2013White Sand;35-38 Stages(~750 lbs/ft)
2013-14White Sand;36-42 Stages(~1000 lbs/ft)
Ca
pita
l E
ffic
iency*
(US
$/B
OE
/day)
• Reduction in well
costs and significant
increase in IP rates
driving top quartile
capital efficiencies
• On-going focus on
completion evolution
and cost improvement
* Capital efficiency based upon completion costs and 30 day initial production rates
19 * Long horizontal wells only (>6,000’ lateral). Data set ~5,900 wells, at April 10, 2014.
Enerplus Bakken / Three
Forks wells drilled without
high volume completions
Enerplus Bakken / Three
Forks wells drilled with
high volume completions
Peak Calendar Month Production*
Completions Enhancements Leading to Best in Basin Well Results
Fort Berthold:
Improving
Economics
30 60 90 120 150 180 210 240 Days
30 60 90 120 150 180 210 240 270 300 330
Improving Economics
New Completion vs. Old Completion
Direct Offsets, Same Formation
21
Days
Cum.
Oil
Per
1000
Lateral
Feet
Cum.
Oil
Per
1000
Lateral
Feet
+70% increase
+90% increase
Bakken
Three Forks
148N – 93W
149N – 93W
22
High
Volume
Completions
30 60 90 120 150 Days
Cum.
Oil
Per
1000
Feet
Improving Economics
New Completion vs. Old Completion
Direct Offsets, Same Formation
Bakken
Three Forks
Drilling/ WOC
+90% increase
150N – 94W
23
Completion Performance Driving Shift in Type Curves
Year 1 Type Curve Adjustment:
Increase in IP rates allows
earlier capture of NPV
24
Improving Economics* from Completion Modifications
Old EUR Old EUR New EUR New EUR
800 Mbbls 500 Mbbls 800 Mbbls 530 Mbbls
(950 MBOE) (600 MBOE) (950 MBOE) (635 MBOE)
30 Day Cum. Prod, bbls 23,000 15,000 43,000 31,000
NPV 10%, $MM $14.7 $4.7 $17.4 $7.2
IRR, btax 60% 25% 100+% 45%
Payout, Yrs 1.7 3.5 1.4 2.3
Recycle Ratio 3.8 2.3 3.9 2.5
* Assumes US$95/bbl WTI flat crude oil price and US$4.00/Mcf NYMEX natural gas price;
Based on long Bakken horizontal wells
No change in ultimate recovery assumption of 15%, but new
completions have improved initial production rates and
created significant increase in NPV and improved economics
Fort Berthold:
Future Development
Options
Future Growth Potential
26
FTB NOI and Prod 2010-2019
Further Upside Potential Exists
• Further upside potential through:
Continued evolution of completions
Lower Three Forks benches
Cost improvements and efficiencies
Higher recovery factor
Increased down spacing on non-operated acreage
27
Fort Berthold:
Gathering,
Transportation and
Differentials
U.S. Crude Marketing
Total Industry Bakken Production Take-Away Capacity:
• ~550,000 bbls/day of regional pipe capacity currently
available and another 400-450,000 bbls/day coming
into service after 2015
• Rail loading capacity is plentiful with > 1.2 MMbbls
available at more than 16 unit train facilities
• Current take-away capacity exceeds regional
production by 60%
Current production: 1.1 MMbbls/day
29
Rail 68%
Pipe 32%
Available Capacity
* Refers to March 2014 North Dakota and Montana production of ~1.1 MMbbls per NDIC and Montana
Board of Oil and Gas Conservation reports
• Enerplus seeks to maintain a balanced approach to marketing commitments
13,500 bbls/day of firm regional egress commitments currently in place
• 8,500 bbls/day of pipeline commitments to Clearbrook and Guernsey (Bakken Expansion and
Four Bears)
• 5,000 bbls/day of rail related sale commitments providing access to East, Gulf and West coast
netback prices
• Remainder is available to sell into the competitive available alternatives
5,000 bbls/day firm commitment made to Sandpiper project for 2016 to Clearbrook
Optionality Provided by Over-Capacity Build
30
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Jan Feb Mar Apr May Jun
Rail to West Coast
Rail to Gulf Coast
Rail to East Coast
Pipe to Guernsey
Pipe to Clearbrook
Recent Market Diversification
Accessing Breadth of Market to Optimize Netback, Reduce Pricing Risk
• Pipe to Clearbrook and Guernsey
gives us access to buyers that
can access markets in Eastern
Canada, Wood River, and
Cushing
• Rail gives us access to markets
in Gulf, East and West Coasts
31
Existing Pipe
Expansion Pipe
Rail
Atl. Canada
Realized Differentials (inclusive of field gathering)
32
-$25
-$20
-$15
-$10
-$5
$0
Ja
n-1
2
Apr-
12
Ju
l-1
2
Oct-
12
Ja
n-1
3
Apr-
13
Ju
l-1
3
Oct-
13
Ja
n-1
4
Apr-
14
Ju
l-1
4
Oct-
14
Ja
n-1
5
Apr-
15
Ju
l-1
5
Oct-
15
US
$/b
bl
Forecast US($13.00)/bbl
at wellhead
• 85% of Fort Berthold oil
production is connected
to third party gathering
system with balance
trucked to pipe or rail
Natural Gas and NGL Production
33
15,051
816 643
Fort Berthold (2013 BOE/day)
Oil Gas Liquids
• Gas and NGLs are gathered and marketed
by our gatherer at market netback pricing
• Realized natural gas price is higher than
NYMEX because of higher heat content
• Enerplus has been proactively focused on
gas conservation
80% of our wells are connected to gas
gathering; increasing by year-end
All wells are being equipped with high
efficiency flares as back-up in case of
disruptions
$-
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
Jan-1
2
Ma
r-1
2
Ma
y-1
2
Jul-1
2
Sep-1
2
No
v-1
2
Jan-1
3
Ma
r-1
3
Ma
y-1
3
Jul-1
3
Sep-1
3
No
v-1
3
Jan-1
4
Ma
r-1
4
Ma
y-1
4Realized Gas Price
Ft. Berthold(1300 BTU factor)
Nymex
Fort Berthold:
Summary
Significant Value Created Plus Future Opportunity
• 329 well inventory:
98 2P UD locations; 231 locations in contingent resource assessment
Over 16 years of inventory at 2 rig development
Potential to accelerate drilling
• 136 MMBOE of best estimate contingent resource
1.3x 2P reserve booking at December 31, 2013
• New completions driving significant improvement in capital efficiencies and profitability
• Generating significant free cash flow
35
36
FORWARD-LOOKING INFORMATION AND STATEMENTS
This presentation contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of
any of the words "expect", "anticipate", "continue", "estimate", “guidance”, "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", “budget”,
"strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this presentation contains forward-
looking information pertaining to the following: Enerplus' asset portfolio; future capital and development expenditures and the allocation thereof among our assets; future
development and drilling locations, plans and costs; the performance of and future results from Enerplus' assets and operations, including anticipated production levels,
expected ultimate recoveries and decline rates; future growth prospects, acquisitions and dispositions; the volumes and estimated value of Enerplus' oil and gas reserves
and contingent resource volumes and future commodity price and foreign exchange rate assumptions related thereto; the life of Enerplus' reserves; future funds flow and
debt-to-funds flow levels; potential asset acquisitions and dispositions; rates of return on Enerplus' capital program; Enerplus ' tax position; sources of funding of Enerplus’
capital program; and future costs, expenses and royalty rates.
The forward-looking information contained in this presentation reflects several material factors and expectations and assumptions of Enerplus including, without limitation:
that Enerplus will conduct its operations and achieve results of operations as anticipated; that Enerplus' development plans will achieve the expected results; the general
continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of
Enerplus' reserve and resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing, cash flow and other
sources to fund Enerplus' capital and operating requirements as needed; and the extent of its liabilities. Enerplus believes the material factors, expectations and
assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be
correct.
The forward-looking information included in this 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: changes in 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 or other regulatory
matters; changes in development plans by Enerplus or by third party operators of Enerplus' properties; increased debt levels or debt service requirements; inaccurate
estimation of Enerplus' oil and gas reserves and 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; 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 above).
The purpose of certain financial outlook information included in this presentation, including with respect to our 2014 guidance for funds flow, is to communicate our current
expectations as to our performance in 2014. Readers are cautioned that it 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 them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
Assumptions All amounts are stated in Canadian dollars unless otherwise specified.
Forward Looking Information Advisory
37
Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent This presentation contains references to "BOE" (barrels of oil equivalent), "Mcfe" (thousand cubic feet of gas equivalent), "Bcfe" (billion cubic feet of gas equivalent) and "Tcfe"
(trillion 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 Mcfes, Bcfes and Tcfes. BOEs, Mcfes, Bcfes and Tcfes 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", “free cash flow”, “capital efficiency”, and “recycle ratio” 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. “Free cash flow” is calculated as net operating income (netback) less capital expenditures. “Capital efficiency” is calculated as the change in production from the
fourth quarter of the previous year to the fourth quarter of the current year divided by total capital expenditures from the fourth quarter of the previous year up to and including the
third quarter of the current year. A “recycle ratio” is calculated as finding and development costs divided by operating netback.
Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "funds flow", "capital efficiency”, and “recycle ratio” 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.
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. In order to continue to be 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.
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 "company interest reserves" using forecast prices and
costs. "Company interest reserves" consist of "gross reserves" (as defined in NI 51-101), being Enerplus' working interest before deduction of any royalties), plus Enerplus' royalty
interests in reserves. “Company interest reserves" are not a measure defined in NI 51-101 and do not have a standardized meaning under NI 51-101. Accordingly, our
company interest reserves may not be comparable to reserves presented or disclosed by other issuers. Our oil and gas reserves statement for the year ended December 31, 2013,
which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, is contained within our Annual Information Form
for the year ended December 31, 2013 ("our AIF") which is available on our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. 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 www.sec.gov. 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 concurrently with this presentation for more complete
disclosure on our operations.
Advisories
38
Contingent Resource Estimates This presentation contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. The estimate of
contingent resources included in this presentation were evaluated by Enerplus and audited by independent reserve evaluators, McDaniel & Associates. "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 quant ities associated with a project in the early
evaluation stage. All of our contingent resource estimates are economic using established technologies and under current commodity price assumptions used by our
independent reserve evaluators. 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 we will produce any portion of the volumes currently classified as “contingent resources”. The
“contingent resource” estimates contained herein are presented as the "best estimate" of the quantity that will actually be recovered, effective as of June 1, 2014. 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 Fort
Berthold properties as reserves and the positive and negative factors relevant to the “contingent resource” estimates, see our AIF, a copy of which is available under our
SEDAR profile at www.sedar.com, and our Form 40-F, a copy of which is available under our EDGAR profile at www.sec.gov.
Advisories
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, "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 Resource Estimates” above.
Investor Relations Contacts
Jo-Anne M. Caza
Vice-President, Corporate & Investor Relations
403-298-2273
1-800-319-6462
www.enerplus.com
The Dome Tower
Suite 3000, 333 7th Ave SW
Calgary, AB Canada
T2P 2Z1
39
