ghs energy conference -...
TRANSCRIPT
GHS Energy Conference
June 25, 2014
ERF – TSX & NYSE
Enerplus Proven Strategy
1
Deliver
sustainable,
profitable
growth and
income to
investors
Strong financial flexibility
Competitive total return of 10%-15%
Focused, top tier resource plays &
mature assets with low decline
Disciplined, return-based capital
allocation
2014 Focus
• Operational execution
Production growth of approximately 10%
Target capital efficiencies of <$30,000/BOE/day
• Financial discipline
• Adjusted payout and debt-to-funds flow ratios maintained or
improved year-over-year
• Cost Reductions
Operating costs and general & administrative expenses
• Advance future opportunity set within portfolio
Increasing future opportunity at Fort Berthold
Duvernay appraisal
Commerciality of polymer project at Medicine Hat
2
3
Core Areas
Canadian Oil–Waterfloods
• Large OOIP with low decline
• ~160 net future drilling locations and EOR potential
• 20% of 2014E production
Canadian Natural Gas–Deep Basin
• 160,000 net acres in the deep basin; 145,000 net acres
are in the Wilrich and Duvernay with 450 net future
drilling locations
• 15% of 2014E production
U.S. Natural Gas–Marcellus
• Top tier dry gas play with robust economics and >240 net
future drilling locations
• 30% of 2014E production
U.S.
Oil
U.S.
Gas
Canadian
Gas
Canadian
Oil
U.S. Oil–Williston Basin
• Operated Bakken/Three Forks position with 330 net future
drilling locations
• Upside potential via downspacing, additional Three Forks
and EOR
• 25% of 2014E production (light crude)
2014 Capital
40%
2014 Capital
20%
2014 Capital
25%
2014 Capital
15%
Cdn Natural Gas 15%
Cdn Oil 20%
U.S. Natural Gas 30%
U.S. Oil 25%
Non-Core 10%
2014E Production by Core Area
PA U.S.
Gas
Crude Oil
40% Natural Gas 56%
Liquids 4%
2014E Production Mix
Demonstrated Per Share Growth
4
0.15 0.15 0.16
0.18(1)
-
0.02
0.04
0.06
0.08
0.10
0.12
0.14
0.16
0.18
0.20
2011 2012 2013 2014E
Production/share
(1) Based upon mid-point of 2014 production guidance of 96,000 – 100,000 BOE/day
(2) Proved plus probable company interest reserves and shares outstanding at December 31.
1.71 1.78 1.74
2.00
-
0.25
0.50
0.75
1.00
1.25
1.50
1.75
2.00
2.25
2010 2011 2012 2013
Reserves/share(2)
Pro
du
ctio
n P
er
Th
ou
sand S
ha
res
Rese
rve
s P
er
Th
ou
sa
nd S
ha
res
Competitive Reserve Addition Costs
$26.26 $24.21
$11.28
$0
$5
$10
$15
$20
$25
$30
2011 2012 2013
$/B
OE
F&D Costs*
* Based on proved plus probable company interest reserves at December 31, including future development costs. FD&A is
defined as finding, development & acquisitions (net of dispositions).
$17.89
$22.92
$8.36
$0
$5
$10
$15
$20
$25
$30
2011 2012 2013
FD&A Costs*
$/B
OE
3 year:
$19.25 3 year:
$14.66
5
$3.19 $3.29
$3.76
$4.45
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
2011 2012 2013 2014E*
$ p
er
Sh
are
Delivering Funds Flow Growth per Share
6
• Higher production volumes
and oil weighting has helped
drive funds flow growth over
past three years
• Q1 funds flow of $221 million
* Analyst consensus at June 11, 2014.
APO 212%
APO 174%
APO 114%
APO* 113%
SPO 59%
SPO 40%
SPO 23%
SPO 24%
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
2011 2012 2013 2014E
Adjusted Payout (APO) Simple Payout (SPO)
Improved Sustainability
7
D/FF
1.7x
D/FF
1.4x
D/FF*
1.3x
D/FF
1.6x
Pa
yo
ut %
* Analyst consensus at June 11, 2014. Adjusted payout ratio is calculated as the sum of dividends paid to
shareholders, net of participation in the Stock Dividend Plan, plus capital expenditures divided by funds flow.
Debt
to F
unds F
low
Ratio
Funds Flow Protection
* As of April 24, 2014, based on weighted average price (before premiums), expected mid-point annual average
production of 98,000 BOE/day, less royalties of 23.5%.
** includes 10% (25 MMcf/day) protected at $4.17/Mcf with upside participation to $5.00/Mcf
64%
36%
Rest of 2014
WTI Crude Oil Hedges* Natural Gas Hedge Positions*
8
12%
C$4.125
10%
90%
2015
9%
8%
30%
53%
Rest of 2014
18%
1%
81%
2015
US$94.24/bbl
AECO Swaps $4.23/Mcf
US$91.82/bbl
NYMEX Collars
US$4.30 - $5.08/Mcf
NYMEX Swaps US$4.14/Mcf**
NYMEX Swaps US$4.21/Mcf
Q1 NYMEX Collars
US$4.50 - $5.54/Mcf
Core Oil Assets
Operated Light Oil Assets in the Williston Basin
Fort Berthold
Sleeping Giant 20%
80%
2013 2P Reserves*: 131 MMBOE
Fort Berthold
Sleeping Giant
10 * Company interest reserves at December 31.
20%
80%
Fort
Berthold
Sleeping Giant
(Elm Coulee)
2014E Production: 28,000 BOE/day
Dunn
Enerplus lands
Top Tier Oil Asset: Fort Berthold, North Dakota
Key Facts
OOIP 20 – 42 MMbbls/1280 DSU
OOIP (W.I.) 1.5 billion bbls
Net Acreage 73,000
(114 sections)
2P Reserves at Dec 31, 2013 105 MMBOE
Best Est. Contingent Resource 136 MMBOE
Future Net Drilling Locations 330 wells
Q1 2014 Production 18,300 BOE/day
Net Locations Drilled to Date 110 wells
(84 Bakken/26 Three Forks)
11
• 2014 Focus: Down spacing tests
Lower Three Forks delineation
Continued cost control
~90% W.I.
Bakken
Three Forks
Drilling/ WOC
Fort Berthold: 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
12 * Per 1,280 acre drilling spacing unit (DSU)
Fort Berthold Well Density Schematic
13
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
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
14
Fort Berthold:
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
Fort Berthold: 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
15
• 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 Capital Efficiencies*
16
$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
Improving Productivity through Completion Enhancements
17 17
Cum.
Oil
Per
1000
Lateral
Feet
30 60 90 120 150 180 210 240 270 300 330 Days
360 390 420 450
,
Bakken Wells
18
Fort Berthold Completion Performance Improving Economics
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
Core Natural Gas Assets
• Concentrated, non-op
position in NE Pennsylvania
• Marcellus production
represents 55% of corporate
natural gas volumes in 2014
• 70% of core acreage held by
production
U.S. Core Gas: Marcellus
20
Key Facts
Net Acreage 57,500 acres
2P Reserves Dec 31,
2013
601 Bcf
Best Est. Contingent
Resource (Dec 31, 2013)
1,340.3 Bcf
Future Net Drilling
Locations
240 wells
Q1 2014 Production 180 MMcf/day
28% average non-operated working interest
Enerplus Land
Marcellus Well
Th
ickn
ess
Marcellus: Superior Dry Gas Performance and Competitive Economics
21
Assumptions:
Capex: $7MM/well.
Differentials: US$4.00/Mcf - 2014 & 2015: -$0.75/Mcf
US$4.50/Mcf - 2014 & 2015: -$1.00/Mcf
2016 & beyond: -$0.30/Mcf
US$4.50/Mcf
EUR EUR EUR
13 Bcf 12 Bcf 10 Bcf
NPV10 ($MM) $10.5 $7.9 $4.3
IRR (%) 72 51 28
US$4.00/Mcf NPV10 ($MM) $8.3 $5.8 $2.8
IRR (%) 60 41 22
2013 - 2014 Gross On-Streams
Tighter stage spacing and increased
proppant continues to improve performance
Core Canadian Natural Gas—Deep Basin
• Core growth area with
approximately 450
potential net future
drilling locations in the
Wilrich and Duvernay
• 160,000 net acres of
high working interest
land
• Successful drilling
results to date in
Wilrich—moving to
development
• Advancing appraisal on
Duvernay lands
Stacked Mannville
76,000 net acres of land
(60,000 net acres of land
in the Wilrich, majority
100% WI)
Duvernay
85,000 net acres of
undeveloped land,
100% WI
22
Our Competitive Advantage
• Focused portfolio in top tier resource plays: Bakken, Marcellus, Deep
Basin & Waterfloods
• Continued focus on capital discipline—delivering approximately 10%
production growth in 2014 with a target capital efficiency of
<$30,000/BOE/day
• Low corporate decline rate of 25%
• Significant inventory of economic growth prospects: ~830 future
drilling locations* & sizeable upside
• Affordable growth supported by a strong balance sheet
• Delivering profitable growth with an attractive yield
23 * 2P reserves and contingent resource locations at December 31, 2013, except for Fort Berthold where a new
contingent resource assessment was completed on June 1, 2014.
Supplemental Information
5
12
17
22
0
5
10
15
20
25
2011 2012 2013 2014E
MB
OE
/da
y
• 2014E annual production growth of 33% to +22,000
BOE/day
• Generated ~$40 million of free cash flow* in Q1
2014
Fort Berthold Delivering Growth
25
• Replaced 400% of 2013 production adding 24.9 MMBOE
of reserves at F&D cost (incl. FDC) of $19.74/BOE
• Three year F&D cost of $21.56/BOE
• 98 net future drilling locations in 2P reserves report
Annual Production Reserves
0
20
40
60
80
100
2010 2011 2012 2013
MM
BO
E
Total Proved Probable
2P:
22.5
2P:
56.2
1P:
28.0
2P:
86.1
1P:
43.7
2P:
105.4
1P:
11.7
1P:
49.6
Fort Berthold Completion Evolution Increasing Production Rates
26
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
21
41
95
-
20
40
60
80
100
120
140
160
180
2011 2012 2013 2014E
MM
cf/
da
y
180
• Marcellus production continues to exceed
expectations
• 90% production increase year-over-year
Generated ~$15 million in free cash flow* in Q1
2014
Marcellus Delivering Growth
27
Annual Production Reserves
• 2013 proved plus probable reserves increased by 168%
• 50% of corporate 2P natural gas reserves
• 37 net future drilling locations
• 2013 2P F&D of $0.58/Mcf & FD&A of $0.91/Mcf
0
100
200
300
400
500
600
2010 2011 2012 2013
Bcf o
f N
atu
ral G
as
Probable Total Proved
1P:
52
2P:
225
2P:
117
2P:
154
1P:
93
1P:
146
2P:
601
1P:
411
* Free cash flow is calculated as NOI less capital expenditures.
Significant Future Drilling Inventory to Support Growth
28
Core Waterfloods 160
Fort Berthold 330
Deep Basin 100
Marcellus 240
~830 Future Drilling Locations
* Based upon 2P reserves and contingent resource locations at December 31, 2013 and as at June 1, 2014 for
Fort Berthold
U.S. Light 58%
Canada Light 9%
Canada Medium 11%
Canada Heavy 22%
2014E Crude Oil Composition
U.S. Liquids 24%
Canada Liquids 20%
Canada Gas 25%
U.S. Gas 31%
2014E Production
29
Production Composition
2014 Differential/Basis Outlook*:
Mixed Sweet Blend (MSW) ($7.00)/bbl
Western Canada Select (WCS) ($25.00)/bbl
U.S. Bakken (at inlet to pipe/rail)** (US$10.00)/bbl
Marcellus Basis (US$1.00)/Mcf
*The differential/basis outlook includes the impact of Enerplus’ marketing and transportation arrangements.
** It costs an average of $3.00/bbl to transport production from the field to market sales points, resulting in an expected field
differential of $13.00/bbl below WTI.
2014 Funds Flow Sensitivities
30 * The sensitivities above reflect our forecasts, outstanding commodity contracts, and are based on forward
markets as at April 24, 2014.
2014 Sensitivities
Est. effect on
2014 Funds Flow
($ Million)
Est. effect on
2014 Funds Flow per Share
($/share)
Change of $5.00/bbl WTI crude oil $20.6 $0.10
Change of $0.50/Mcf NYMEX natural gas $26.2 $0.13
Change of 1,000 BOE/day production $ 4.0 $0.02
Change of $0.01 in the US$/CDN$ exchange rate $ 8.0 $0.04
Debt Composition as at March 31, 2014
Senior Notes US$770MM* CDN$70MM
Credit Facility $187MM
Unused Capacity $813MM
* Canadian dollar equivalent of U.S. dollar denominated notes. FX rate at March 31, 2014 US/CDN of 1.1053.
• Bank Credit Facility - $1 billion
• 11 banks in Enerplus’ bank credit facility
• Unsecured, covenant-based with current
borrowing rate of less than 3%
• Credit facility matures October 31, 2016
• Senior Unsecured Notes - $840 MM
• Notes are rated NAIC 2 and rank equally
with bank credit facility; average interest
rate of 5.5%
31
Senior Notes Maturities*
* As at March 31, 2014. US$ amounts converted at US/CDN 1.1053.
** Including impact of Cross Currency Interest Rate Swaps
$51
$96
$50
$643
$0
$100
$200
$300
$400
$500
$600
$700
2014 2015 2016 2017 2018 andbeyond
$ M
illi
on
s
32
Average interest rate of 5.5%**
Enerplus Share Ownership
As of April 22, 2014
Investor Composition Geographic Composition
Total Retail
65% Total Institutional
35%
33
44%
21%
14%
21%
US & Other Retail Canadian Retail
US & Other Institutional Canadian Institutional
58%
42%
United States & Other Canada
Board of Directors
Elliott Pew, Chairman of the Board(1)(2)
Mr. Pew, Chairman of Enerplus, is a co-founder of Common Resources and served as its Chief Operating Officer until the company was sold in May, 2010. He is
currently a Director for the newly formed Common Resources II located in The Woodlands, Texas. Previously, Mr. Pew was Executive Vice President -
Exploration at Newfield Exploration Company in Houston where he led Newfield’s diversification efforts onshore in the late 1990’s in addition to leading the
company’s exploration program, including the formation of the deep water GOM business unit. Prior to Newfield, Mr. Pew was Senior Vice President - Exploration
with American Exploration Corp. Mr. Pew is a Geology graduate of Franklin and Marshall College and holds an M.A. in Geology from the University of Texas.
David H. Barr, Director (12)
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 Culbert, Director (3)(9)
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.
Edwin V. Dodge, Director (9)(11)
Mr. Dodge is currently a corporate director following a 35-year career with Canadian Pacific Railway Limited ("CPR", a Canadian national rail carrier), where he
was Chief Operating Officer from 2001 until his retirement in March 2004. Prior to 2001, Mr. Dodge held other senior roles with CPR including Executive Vice
President of Operations for Canada and the U.S., as well as Chief Executive Officer of a Minneapolis-based railroad. Mr. Dodge holds a Civil Engineering degree
and an MBA from the University of Western Ontario.
Ian C. Dundas, Director
Mr. Dundas became President and Chief Executive Officer of Enerplus on July 1, 2013. 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.
Board of Directors continued
Hilary Foulkes, Director (5)(11)
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. 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.
James B. Fraser, Director (7)(11)
Mr. Fraser has over 35 years of energy industry experience, and was the Senior Vice President for the shale division of Talisman Energy Inc.'s North American
operations. From 2006 to 2008, Mr. Fraser was Vice President of operations for the southern division of Chesapeake Energy and prior to this spent over 20 years
at Burlington Resources and its predecessor companies, where he held a number of senior positions including North American Exploration Manager. Mr. Fraser
holds a MBA from Regis College and a Bachelor of Science in Petroleum Engineering from the Montana School of Mines.
Robert B. Hodgins, Director (3)(6)
Mr. Hodgins has been an independent businessman since November 2004. 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 2004. 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 1998. 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 1991.
Susan M. MacKenzie, Director (7)(10)
Ms. MacKenzie has over 25 years of energy sector experience, most recently serving as Chief Operating Officer with Oilsands Quest Inc. in 2010. 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).
Douglas R. Martin, Director
Mr. Martin is President of Charles Avenue Capital Corp., a private merchant banking company, since April 2000. From 1993 until 2000, Mr. Martin was Chairman
and Chief Financial Officer of Pursuit Resources Corp., a public oil and gas corporation that was acquired by EnerMark Income Fund (a predecessor of Enerplus)
in April 2000. From 1972 until 1993, Mr. Martin held positions of increasing importance with N.M. Davis Corp., Dome Petroleum Ltd. and Interhome Energy Inc.
(now Enbridge Inc.), and was the Senior Vice President and Chief Financial Officer of Coho Energy Inc. from 1989 until 1993. Mr. Martin graduated from the
University of Toronto in 1966 with a B.A. in Political Science, and received his Chartered Accountant designation from the Ontario Institute of Chartered
Accountants in 1969. He also graduated with Honours from York University in 1972 with an MBA in Finance.
Board of Directors continued
Donald J. Nelson, Director (3)(9)
Mr. Nelson has over 40 years of experience in the oil and gas industry, and is the president of Fairway Resources Inc., a private consulting services firm. Prior to
this, Mr. Nelson was with Summit Resources from 1996 to 2002, until its acquisition by Paramount Resources Ltd., where he held the position of Vice President
Operations from 1996 to 1998 and President and Chief Executive Officer from 1998 to 2002. He currently serves as Director for Perpetual Energy Inc., Keyera
Corp., as well as three other private companies. Mr. Nelson is a Professional Engineer, a member of the Association of Professional Engineers, Geologists and
Geophysicists of Alberta and of the Society of Petroleum Engineers.
Glen D. Roane, Director (4)(5)
Mr. Roane is a corporate director and currently serves as a director of Enerplus, Badger Daylighting Ltd., Logan International Inc., SilverBirch Energy Corporation
and the GBC American Growth Fund. 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., and Tarpon Energy Services
Ltd. Mr. Roane retired from TD Asset Management Inc., a subsidiary of The Toronto-Dominion Bank in 1997. 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 (5)(8)
Mr. Steeves has over 37 years of experience in the North American oil and gas industry and is currently a Director of Tamarack Valley Energy Ltd., a Canadian oil
and gas company with operations in the Western Canadian sedimentary basin. 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 1997. He holds a Bachelor of Science in Geology from the University of Calgary.
(1) Chairman of the Board
(2) Ex-Officio member of all Committees of the Board
(3) Member of the Corporate Governance & Nominating Committee
(4) Chair of the Corporate Governance & Nominating Committee
(5) Member of the Audit & Risk Management Committee
(6) Chair of the Audit & Risk Management Committee
(7) Member of the Reserves Committee
(8) Chair of the Reserves Committee
(9) Member of the Compensation & Human Resources Committee
(10) Chair of the Compensation & Human Resources Committee
(11) Member of the Safety & Social Responsibility Committee
(12) Chair of the Safety & Social Responsibility Committee
37
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
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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.
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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.
See "Non-GAAP Measures" above.
F&D and 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 reflect total finding, development and acquisition costs related to its reserves additions for
that year. See "Non-GAAP Measures" above.
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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.
Advisories
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
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