INVESTOR UPDATE September 2021 - TSX & NYSE: ERF - Enerplus
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INVESTOR UPDATE
September 2021
TSX & NYSE: ERF
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”, "ongoing", "may", "will", "project", "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: anticipated completion of the Acquisition, including expected purchase price, terms, timing and completion thereof; expected benefits of the Acquisition; expected impacted of the Acquisition on
Enerplus' operations and financial results, including inventory of drilling locations, expected accretion to Enerplus' metrics (including expected free cash flow in 2021 and beyond and year-end net debt to adjusted funds flow ratio); Enerplus'
expected 2021 average production volumes and expected capital levels to support such production; anticipated production mix and Enerplus’ expected source of funding thereof; expected operating plans; oil and natural gas prices and
differentials; anticipated impact of the Acquisition on Enerplus' future costs and expenses; expected increase in the size of Enerplus’ credit facility; Enerplus' five year outlook, including expected capital spending levels and resulting
production, production growth and free cash flow, and plans for excess cash flow, including potential share repurchases.
The forward-looking information contained in this presentation reflects several material factors, expectations and assumptions including, without limitation: that we will conduct our operations and achieve results of operations as anticipated,
including considering the Hess asset and Bruin acquisitions; that our development plans will achieve the expected results; that lack of adequate infrastructure and/or low commodity price environment will not result in curtailment of
production and/or reduced realized prices beyond our current expectations ; current and estimated commodity price, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions,
including expectations regarding the duration and overall impact of COVID-19; the continued ability to operate DAPL and lack of court order restricting its operation; that our development plans will achieve the expected results; the
continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund
our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our adjusted funds flow and availability under our bank credit facility to fund our working capital
deficiency; our ability to comply with our debt covenants; the availability of third party services; the extent of our liabilities; the rates used to calculate the amount of our future abandonment and reclamation costs and asset retirement
obligations; the availability of technology and processes to achieve environmental targets. In addition, Enerplus’ 2021 outlook contained in this presentation is based on the following rest of year prices: US$69/bbl WTI, US$3.92/Mcf NYMEX,
and a USD/CDN exchange rate of 1.26. Enerplus’ five-year outlook contained in this presentation is based on the following prices for 2022-2025: US$50/bbl and US$55/bbl WTI, US$2.75/Mcf NYMEX, and a USD/CDN exchange rate of 1.27.
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: continued instability, or further deterioration, in global economic and market environment, including
from COVID-19; continued low commodity prices environment or further volatility in commodity prices; changes in realized prices of Enerplus’ products; changes in the demand for or supply of our products; failure to realize the anticipated
benefits of the Hess assets or Bruin acquisitions; unanticipated operating results, results from our capital spending activities or production declines; the legal proceedings in connection with DAPL; curtailment of our production due to low
realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in our capital plans or by third party operators of our 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 our oil and gas reserve and contingent resource 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 third party service providers; changes in law or government programs or policies in Canada or the United
States; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks and contingencies described under "Risk Factors and Risk Management" in Enerplus’ 2020 MD&A and in
our other public filings).
The purpose of our estimated free cash flow disclosure, is to assist readers in understanding our expected and targeted financial results, and this information may not be appropriate for other purposes. Information in this presentation is
provided as of the date hereof and Enerplus assumes no obligation to update any forward-looking statements, unless otherwise required by law.
2
Enerplus overview
Concentrated acreage position in the Bakken core
Strong balance sheet and liquidity position CDN
WATERFLOODS
Robust free cash flow outlook
Disciplined returns-based capital allocation
BAKKEN MARCELLUS
Committed to strong ESG performance
2021e production by area (1) 2021e production by product(1) Dual listed: TSX & NYSE
Market capitalization: C$2.0 billion
28% 2021e production: 113,500 BOE/d (62% liquids)(1)
63% 62%
6% 38%
3%
Bakken Marcellus
Liquids Natural Gas
Waterfloods Other
3
1) Production is based on the guidance mid-point. Not adjusted for Williston Basin divestment announced Aug 30, 2021.
2021 update
STRONG Company record production of 115,350 BOE/d in Q2, up 26% q-o-q
PRODUCTION 2021 annual average guidance now 112,000 to 115,000 BOE/d(1)
FREE CASH FLOW Generated ~$55MM in free cash flow in Q2
GENERATION Estimate >$450MM in free cash flow in 2021(2)
FINANCIAL Allocating ~90% of FCF, after dividends, to debt reduction in near term
FLEXIBILITY $400MM debt target expected to be achieved by end of Q1 2022(3)
Dividend increased 15%, share buyback program reinitiated
INCREASING
RETURN OF CAPITAL Expectation of further increasing capital returns to shareholders once debt
target achieved
SOLID Averaging >30% improvement in ND completions efficiency YTD vs 2020
EXECUTION Tracking 25% improvement in total ND well costs in 2021 vs 2019
1) Not adjusted for Williston Basin divestment announced Aug 30, 2021. Divestment expected to close end of October 2021.
2) Non-GAAP measure, see “Advisories”. Based on forward strip commodity prices at July 21, 2021 . 4
3) Based on current commodity price environment.
2021 operating outlook
2021e total production 2021e liquids production E&D capital spending
(mboe/d)
+27.5 (mbbl/d)
+22.5 (C$ millions)
+$80MM
MBOE/d(1) MBBL/d(1)
112-115 69.5-71.5 $360-400
86 $300
48
Original guidance Current guidance Original guidance Current guidance Original guidance Current guidance
(post acquisitions) (post acquisitions) (post acquisitions)
1) Based on guidance mid-points. Guidance has not been adjusted for Williston Basin divestment announced Aug 30, 2021.
5
Strong liquidity position and line of sight to leverage target
Significant liquidity Debt reduction target
Estimated liquidity position at June 30, 2021 (US$ millions) From Q2 2021 (C$ millions)
Enerplus was the first North American E&P to transition its principal credit facility to a Debt target expected to be achieved by end of Q1
Sustainability Linked Credit Facility, incorporating ESG performance targets $1,200 2022 based on current commodity price environment
$1,130
~US$700
$1,000
TERM FACILITY $800
Avg. interest rate: 2.15%(1)
~$730
Cash and $600
$400
undrawn portion SLL FACILITY
of US$900 SLL
Credit Facility
Avg. interest rate: 2.15%(1)
$400
~$400MM
$270
Debt reduction target
SENIOR NOTES
Avg. interest rate: 4.4% $200
$101 $81 $81 $21
$0 $21 $0
Liquidity H2 2021 2022 2023 2024 2025 2026 Debt net of Debt net of
cash cash
SLL Credit Facility Senior Notes Term Facility SLL Drawn Amount Q2 2021 target
6
1) Drawn fees are expected to be approximately 2.15% based on an underlying 3-month LIBOR rate of 0.1%
Capital allocation principles and framework
Principles Framework Execution
~90% of free cash flow, after dividends, to debt
MAINTAIN Long term ND/AFF ratio(1) target: 1.0x or less assuming reduction until leverage target achieved
LOW LEVERAGE US$50 WTI price environment Targeting $400MM debt reduction from Q2 2021
(estimated to be achieved by end Q1 2022(2))
On track to generate >$450MM in free cash flow
GENERATE Long term capital spending reinvestment rate(1) of less in 2021(1)(2)
FREE CASH FLOW than 75% of adjusted funds flow
2021 estimated reinvestment rate ~45%(1)(2)
Dividend increased 27% YTD
RETURN Sustainably grow base dividend supported by an increasing ~10% of free cash flow, after dividends, to
CAPITAL TO cash flow base. Consider share repurchases to further incremental shareholder returns in near term.
SHAREHOLDERS enhance the return of capital to shareholders Allocation of free cash flow to shareholders
expected to increase once debt target achieved
The key principles above and the macro environment will drive Enerplus’ disciplined approach to growth,
maximizing free cash flow and shareholder returns
1) Non-GAAP measure. See “Advisories”. 7
2) Based on current commodity price environment.
Five year outlook focused on free cash flow growth
HIGHLIGHTS OF THE FIVE YEAR OUTLOOK
(assumes constructive oil price: ~US$50-55+/bbl WTI)
ANNUAL CAPITAL SPENDING ~$500 MM
(2022-2025)
CUMULATIVE FREE CASH FLOW(1) ~$1.5 to $2.0 Bn
(2021-2025)
AVERAGE REINVESTMENT RATE(1) ~55% to 60%
(2021-2025)
ANNUAL LIQUIDS PRODUCTION GROWTH RATE ~3% to 5%
(2022-2025)
1) Non-GAAP measure, see “Advisories”. 2021 is based on year to date commodity prices and forward strip for the remainder of the year. Years 2022- 8
2025 are based on WTI oil prices of US$50-$55/bbl and NYMEX natural gas prices of US$2.75/Mcf.
Strategic acquisitions improve Bakken scale
HIGHLIGHTS OF ACQUISITIONS ENERPLUS NORTH DAKOTA POSITION
3.5x increase in acreage position; now 238,000 net acres(1) Legacy Enerplus
Bruin
Dunn co. – op
− 98,000 net acres (Bruin acquisition)(1) Williams Dunn co. – non op
− 74,000 net acres (Dunn county acquisition acquired from Hess Corporation)(1) Mountrail
Fort Berthold
340 net identified economic drilling locations(1) added
− Bruin: 111 locations (FBIR, eastern Williams), additional upside potential
− Dunn county: 110 tier 1, 120 MB upside, TF upside potential McKenzie
~30,000 BOE/d current production added
− Bruin: 24,000 BOE/d (low 30% decline rate)
− Dunn county production: 6,000 BOE/d (18% decline rate)
Dunn
Billings DIVESTMENT
Bruin acquisition Dunn county acquisition Announced Aug 30,
CLOSED March 10, 2021 CLOSED April 30, 2021 2021
1) Excludes the acreage sold in connection with the Williston Basin divestment announced Aug 30, 2021. 9
2) See “Advisories – Drilling Inventory” for a reconciliation of undrilled locations between those associated with reserves and those not associated with any reserves.
Acquisitions have extended high quality inventory
Drilling inventory expansion(1)
Net locations
Non-FBIR development plan
~675
120 5-6 wells per spacing unit
MB
110 TF 1 Upside
60
51
FBIR development plan per spacing unit
333 Bruin acquisition Dunn co. acquisition ~10 wells per spacing unit
MB
TF 1
UPSIDE UPSIDE TF 2 TF2 locations in select areas
POTENTIAL POTENTIAL
10
1) See “Advisories – Drilling Inventory” for a reconciliation of undrilled locations between those associated with reserves and those not associated with any reserves. As at 1 Jan 2021. Includes drilled uncompleted wells.ENVIRONMENTAL, SOCIAL & GOVERNANCE
Material focus areas
Water Management
2020
TARGETS (1)
PERFORMANCE (1)
GHG emissions intensity reduction targets(2) 24%
2022 target: 20% reduction in methane emissions Emissions intensity Community
2030 target: 50% reduction reduction in 2020 Greenhouse Gas
Emissions Engagement
ESG
Freshwater use reduction targets MATERIAL
23%
2021 target: 25% reduction/well comp. in FBIR Freshwater use reduction
FOCUS
2025 target: 50% reduction/well comp. corporately per completion in 2020 AREAS
Health & Safety target Board Constitution Culture
67% & Culture
Reduce LTIF(3) by 25% on average, between 2020- LTIF(3) reduction in 2020
2023
Health & Safety
1) Targets and 2020 performance are relative to a 2019 baseline.
2) Enerplus’ GHG emissions reduction targets address scope 1 and 2 emissions. Scope 1 emissions are direct emissions from owned and operated facilities. Scope 2 emissions are indirect emissions from the generation of purchased
energy for the Company’s owned and operated facilities. Targets are relative to a 2019 baseline. 11
3) Lost Time Injury Frequency.TRACK RECORD
High return growth, free cash flow and low leverage
High return oil growth Focus on free cash flow Return of capital Low financial leverage
Production, MBOE/d Free cash flow(1), C$ millions C$ millions Net debt to adjusted funds flow ratio(1)
8% >$380MM >$370MM 1.0x
3-year liquids Cumulative free cash Returned to shareholders Leverage ratio at Dec 31, 2020
production CAGR since 2017 flow since 2017 since 2017 3x
101 $382
93 91 $67
85
46 $90
43 2x
40
44
$179
$160
1.0x
$79 1x
55
0.6x 0.6x
50 51
41 $3 0.4x
$66
$29 $29 $28 $27
0x
2017 2018 2019 2020 2017 2018 2019 2020 Total 2017 2018 2019 2020 2017 2018 2019 2020
Liquids Natural gas Dividends Share repurchases
12
1) Non-GAAP measureOPERATIONS UPDATE
13ENERPLUS NORTH DAKOTA WELL COST PERFORMANCE
Solid execution delivering capital efficiency gains
Drilling efficiency gains
Drilling days vs. depth (spud to rig release)(1)
Days
0 2 4 6 8 10 12 14
0 Total well costs
3,000 2018 Avg (US$MM)(1)(2)
6,000 2019 Avg
>20% IMPROVEMENT
Depth (ft)
9,000 2020 Avg SINCE 2018 $7.6
12,000 2021 H1
15,000 Pacesetter
18,000
21,000
$5.7
Completion efficiency gains
Stages per day
12.8
15.3
25%
9.5 WELL COST
6.7 >90% IMPROVEMENT
SINCE 2019
REDUCTION
2019 2020 2021 Pacesetter 2019 2021e
Average Average Average YTD pad
1) Based on two-mile lateral wells. 14
2) Total well cost includes drilling, completion and facilities costs.FORT BERTHOLD WELL PERFORMANCE
Maintaining strong well performance at lower cost
Enerplus Fort Berthold well performance ENERPLUS FBIR RECENT COMPLETIONS
Cumulative oil production per well (Mbbl)
500 US$2.4MM
REDUCTION
400 IN WELL COSTS
SINCE 2017(1)
300
200 BELFORD PAD
Onstream Q2 2021 (6 wells)
100
- IGNEOUS PAD
0 100 200 300 400 500 600 METAMORPHIC PAD Onstream Q2 2021 (9 wells)
Onstream Q2 2021 (5 wells)
Producing days
2017 wells 2018 wells 2019 wells 2020 wells 2021 wells
2017 Avg 2018 Avg 2019 Avg 2020 Avg 2021 Avg
15
1) Well costs in 2017 averaged US$8.1mm compared to US$5.7mm expected in 2021.MARCELLUS OVERVIEW
Core acreage position in the Marcellus dry gas window
MARCELLUS POSITION – NE PENNSYLVANIA
Non-operated position in Marcellus dry gas core Bradford Susquehanna
− 32,600 net acres, ~200 MMcf/d production(1)
Capital efficient and highly productive well performance
− >10 year drilling inventory(2) Wyoming
Sullivan
High quality exposure to improving natural gas prices
Lycoming
− Consistent free cash flow generation
Marcellus production & capex Marcellus pricing exposure Marcellus unhedged annual net operating income
MMcf/d and US$ millions Approx. % of natural gas sales Sensitivity to NYMEX (US$ millions) $122
26%
300 $75 $96
$45 $51 Leidy
200 $37 $50 $70
$35-$40 TZ6 Non-NY
$24 US$0.65/Mcf $43
100 $25 Gulf Coast 2021e portfolio
198 208 227 193 195-200 differential below 19%
0 $0 Other NYMEX
2017 2018 2019 2020 2021e 52% $2.50 $3.00 $3.50 $4.00
Production Capex 3%
NYMEX Benchmark Price (US$/Mcf)
16
1) Enerplus working interest production.
2) 56 net future drilling locations as at December 31, 2020. Includes 23.7 proved plus probable undeveloped reserves locations and drilled uncompleted wells, and 32.6 best estimate contingent resources locations. See “Advisories”.MARCELLUS WELL RESULTS
Capital efficient and highly productive drilling inventory
Marcellus well performance 2018-2021(1)
Average cumulative well production per 1,000 ft lateral
Avg.
0.8 8,200 ~20% INCREASE
lateral ft IN 6-MONTH CUMULATIVE PRODUCTION /
0.7
Avg. LATERAL FT IN 2021 VS 2018
0.6 9,200
Avg. 10,600 lateral ft
Bcf/1,000 ft lateral
0.5 lateral ft Avg.
6,300
0.4 lateral ft
0.3
0.2
0.1
0
1 2 3 4 5 6 7 8 9 10 11 12
Months on production
2018 2019 2020 2021
17
1) Enerplus’ average working interest in the Marcellus wells is 4.4% in 2021, 3.3% in 2020, 9.7% in 2019, 9.2% in 2018 (production weighted).APPENDIX
182021 guidance, operating statistics and well economics
2021 GUIDANCE(1) WELL ECONOMICS
E&D capital spending (C$MM)(2) $360-400 BAKKEN - FORT BERTHOLD(1)
Total production (Mboe/d) 112-115 WTI oil price US$50/bbl US$60/bbl
Liquids production (Mbbl/d) 69.5-71.5 Payout 1.5 years 0.9 years
IRR: 60% 100%+
Avg. royalty & production tax rate 26%
Breakeven (10% IRR) US$38/bbl WTI
Operating expense ($/boe) $8.25
MARCELLUS(2)
Transportation expense ($/boe) $3.85
NYMEX natural gas price US$3.00/Mcf US$3.50/Mcf
Cash G&A expense ($/boe) $1.25
Payout 2.0 years 1.4 years
Current income tax expense (US$MM) $5-7
IRR 50% 90%
Bakken oil price differential compared to WTI (US$/bbl) $(2.35) Breakeven (10% IRR) US$2.30/Mcf NYMEX
Marcellus natural gas price differential compared to NYMEX (US$/Mcf) $(0.65) 1) Fort Berthold well economics are based on the average 2P reserves booked per undeveloped location for
a 2-mile lateral (~730 mboe) and a total well cost of US$5.7MM.
2) Marcellus well economics are based on the average 2P reserves booked per undeveloped location (~18
2021 ASSET DETAILS(3) BAKKEN MARCELLUS CANADA DJ BASIN Bcf/well, 7,400 ft lateral) and a total well cost of US$6.3MM.
Capital allocation (approx.)(2) 76% 12% 6% 6%
Wells drilled (gross) 19-23 54-66 2 -
(~99% WI) (~5% WI) (~15% WI)
Wells online (gross) 42-50 64-72 2 3
(~80% WI) (~7% WI) (~15% WI) (~87% WI)
1) Guidance has not been adjusted for Williston Basin divestment announced Aug 30, 2021 (~3 MBOE/d). Closing end of October 2021. 19
2) Capital spending includes capitalized G&A.
3) Wells drilled and completed are based on operated activity only except for the Marcellus and Canada which include non-operated activity.BRUIN ACQUISTION
Strong well performance in FBIR & Williams Co. acreage
Enerplus and Bruin North Dakota well performance ENERPLUS NORTH DAKOTA POSITION
Average cumulative oil production per well since 2019
Legacy Enerplus
250 Bruin
Dunn co. – op
62 WELLS Dunn co. – non op
30 WELLS Williams
200 12 WELLS
Oil production (mbbl)
150 Fort Berthold
Line of sight to lower cost structures in
Williams Co. acreage due to shallower
100 depths and lower ancillary costs McKenzie
50
0
0 50 100 150 200 250 300 350
Producing days
Enerplus - FBIR Bruin - FBIR Bruin - Williams Co.
20DUNN COUNTY ACQUISITION
Active proximal development delivering strong results
OFFSET OPERATOR DEVELOPMENT (2018+) Active DSU development in Middle Bakken and Three Forks by offset operators(1)
2 Continental Resources-Carus Pad: 4 MB / 5 TF
Fort Berthold
1 ExxonMobil-Jorgenson Pad: 2 MB / 3 TF
Development Spacing (wells/mi) 6 MB / 6 TF Development Spacing (wells/mi) 6 MB / 6 TF
1 Completion Date: 2019 Completion Date: 2019
Avg. Proppant Loading (lbs/ft): 799 Avg. Proppant Loading (lbs/ft): 1249
Avg. Fluid Loading (Bbs/ft): 38 Avg. Fluid Loading (Bbs/ft): 26
Avg MB / TF 6 Month Oil Cum (MBbl) 100 / 86 Avg MB / TF 6 Month Oil Cum (MBbl) 166 / 149
2
3 3 ConocoPhillips-Franklin Pad: 2 MB / 3 TF 4 Continental Resources-Nadia Pad: 4 MB / 4 TF
Development Spacing (wells/mi) 5 MB / 5 TF Development Spacing (wells/mi) 6 MB / 7 TF
Completion Date: 2019 Completion Date: 2020
Avg. Proppant Loading (lbs/ft): 833 Avg. Proppant Loading (lbs/ft): 949
Avg. Fluid Loading (Bbs/ft): 18 Avg. Fluid Loading (Bbs/ft): 20
4 Avg MB / TF 6 Month Oil Cum (MBbl) 116 / 89 Avg MB / TF 6 Month Oil Cum (MBbl) -
5 5 Marathon Oil-Northrop Pad: 4 MB / 0 TF 6 Continental Resources-Marshal Pad: 2 MB / 1 TF
6 Development Spacing (wells/mi) 6 MB / TF Development Spacing (wells/mi) 6 MB / 6 TF
7 Completion Date: 2018 Completion Date: 2020
Avg. Proppant Loading (lbs/ft): 616 Avg. Proppant Loading (lbs/ft): 734
Avg. Fluid Loading (Bbs/ft): 17 Avg. Fluid Loading (Bbs/ft): 16
Avg MB / TF 6 Month Oil Cum (MBbl) 153 / Avg MB / TF 6 Month Oil Cum (MBbl) 97 / 57
7 Marathon Oil-Pletan Pad: 2 MB / 2 TF
Development Spacing (wells/mi) 6 MB / 5 TF
Completion Date: 2019
Existing Enerplus Avg. Proppant Loading (lbs/ft): 760
Acquired acreage – operated Avg. Fluid Loading (Bbs/ft): 19
Acquired acreage – non operated Avg MB / TF 6 Month Oil Cum (MBbl) 148 / 135 21
1) Source: Enervus.Bakken egress and oil price differential outlook
Bakken oil production & takeaway capacity(1)
Millions of bbl/d
DAPL
2.8 expansion to
~400 mb/d of incremental rail capacity would be 750 mb/d BAKKEN DIFFERENTIAL
2.4 required to clear the basin if DAPL cannot flow. Aug 2021 (BELOW WTI)
Estimated that:
2.0 ~300 mb/d available in the near term 2021 OUTLOOK
~100 mb/d available per month thereafter
1.6
US$2.35/BBL
Excess rail loading capacity(3) Production(2) (ASSUMES DAPL OPERATIONAL)
1.2
DAPL
0.8
Pipelines (ex DAPL)
0.4
Rail volumes(3)
0.0
Jun-14
Jun-15
Jun-16
Jun-17
Jun-18
Jun-19
Dec-20
Dec-21
Dec-13
Dec-14
Dec-15
Dec-16
Dec-17
Dec-18
Dec-19
Jun-20
Jun-21
1) Source: NDIC, company estimates.
2) Production on chart is shown net of local refining demand. 22
3) Forecast rail volumes assume 175 mb/d are contracted going forward. Excess rail loading capacity is based on NDIC data.CANADIAN OIL WATERFLOOD PORTFOLIO
Consistent, low decline production
Assets under water or polymer flooding CANADIAN WATERFLOODS
Portfolio optimized to focus on highest return, strong ANTE CREEK
cash flow generating assets
Portfolio consistently generates free cash flow GILTEDGE
− ~$200MM in free cash flow since 2017(1) CADOGAN Saskatchewan
Low decline production
MEDICINE HAT
− Q2 2021 production was ~7,240 BOE/d (95% oil)
British Columbia Alberta FREDA LAKE
−EMERGING OPPORTUNITY – DJ BASIN
Northern extension of Wattenberg field
DJ BASIN
~38,000 net acres in NW Weld County WYOMING
− Low entry price achieved through leasing and farm-in activity COLORADO 2017/2018 - 5 wells online
(4 Codell, 1 Niobrara)
− Significant oil in place through all Niobrara benches and Codell
2019 - 5 wells online
(4 Codell, 1 Niobrara)
Initial well results compare favorably to core DJ oil rates
2020 - 2 wells online
(2 Codell)
Focused on enhancing well economics through further drilling
2021 – 3 wells online
& completion optimization WELD
(3 Codell)
2021 operated activity focused on completing DUCs MORGAN
ADAMS
DENVER
24COMMODITY HEDGING SUMMARY
Price risk management
CRUDE OIL HEDGES (WTI)(1)
ERF Swaps Bruin Swaps(2) ERF Three-way Collars Bruin Collars(2)
Period
Purchased Purchased
Volume Swaps Volume Swaps Volume Sold Put Sold Call Volume Sold Call
Put Put
(Mbbl/d) (US$/bbl) (Mbbl/d) (US$/bbl) (Mbbl/d) (US$/bbl) (US$/bbl) (Mbbl/d) (US$/bbl)
(US$/bbl) (US$/bbl)
Jul 1 – Dec 31, 2021 - - 8.465 $42.52 23.0 $36.39 $46.39 $56.70 - - -
Jan 1 – Dec 31, 2022 - - 3.828 $42.35 17.0 $40.00 $50.00 $57.91 - - -
Jan 1 – Oct 31, 2023 - - 0.250 $42.10 - - - - 2.0 $5.00 $75.00
Nov 1 – Dec 31, 2023 - - - - - - - - 2.0 $5.00 $75.00
NATURAL GAS HEDGES (NYMEX)
ERF Swaps ERF Collars
Period Volume Swaps Volume Sold Put Purchased Put Sold Call
(Mcf/d) (US$/Mcf) (Mcf/d) (US$/Mcf) (US$/Mcf) (US$/Mcf)
Jul 1 – Oct 31, 2021 60,000 $2.90 40,000 $2.15 $2.75 $3.25
Nov 1, 2021 – Mar 31, 2022 - - 40,000 - $3.43 $6.00
1) The total average deferred premium spent on these hedges is US$0.87/bbl from July1, 2021 to December 31, 2021 and US$1.22/bbl from April 1, 2022 to December 31, 2022. Transactions with a common term have
been aggregated & presented at weighted average prices & volumes.
2) Upon closing of the Bruin Acquisition, Bruin’s outstanding hedges were recorded at a fair value liability of $96.5 million. At June 30, 2021, the fair value of the Bruin hedges was a liability of $100.0 million. For the three
and six months ended June 30, 2021 we recorded a realized loss of $2.2 million and $1.7 million, respectively, on the settlement of the Bruin hedges. In addition, we recognized an unrealized loss of $52.8 million and 25
$35.4 million, respectively, for the change in the fair value of the Bruin hedges over the same periods. See Note 17 to the Q2 2021 Financial Statements for further detail.The Board of Directors
Hilary A. Foulkes (Director since February 2014) Susan M. MacKenzie (Director since July 2011)
Compensation & Human Resources Committee (Chair)
Board Chair Reserves, Safety & Social Responsibility Committee
Judith D. Buie (Director since January 2020) Elliott Pew (Director since September 2010)
Audit & Risk Management Committee Previous Board Chair
Corporate Governance & Nominating Committee
Reserves, Safety & Social Responsibility Committee
Karen E. Clarke-Whistler (Director since December 2018) Jeffrey W. Sheets (Director since December 2017)
Compensation & Human Resources Committee Audit & Risk Management Committee (Chair)
Corporate Governance & Nominating Committee Compensation & Human Resources Committee
Reserves, Safety & Social Responsibility Committee
Ian C. Dundas Sheldon B. Steeves (Director since June 2012)
Audit & Risk Management Committee
President and CEO Reserves, Safety & Social Responsibility Committee (Chair)
Robert B. Hodgins (Director since November 2007)
Compensation & Human Resources Committee
Corporate Governance & Nominating Committee (Chair)
26ESG & Sustainability reporting
6 YEARS
OF ESG &
SUSTAINABILITY
REPORTING
27Summary of operational and financial metrics
2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019 Q1 2020 Q2 2020 Q3 2020 Q4 2020 2020 Q1 2021 Q2 2021
Average Benchmark Prices
WTI Crude Oil (US$/bbl) $ 64.77 $ 54.90 $ 59.81 $ 56.45 $ 56.96 $ 57.03 $ 46.17 $ 27.85 $ 40.93 $ 42.66 $ 39.40 $ 57.84 $ 66.07
NYMEX Natural Gas (US$/Mcf) $ 3.09 $ 3.10 $ 2.64 $ 2.23 $ 2.50 $ 2.63 $ 1.95 $ 1.72 $ 1.98 $ 2.66 $ 2.08 $ 2.69 $ 2.83
Production(1)
Oil (mbbl/d) 45,424 41,105 48,141 55,023 54,344 49,704 49,044 43,168 46,082 43,405 45,421 42,465 61,803
Natural gas liquids (mbbl/d) 4,486 4,383 4,720 5,098 5,502 4,929 5,346 4,929 6,457 5,790 5,633 6,581 9,890
Natural Gas (MMcf/d) 259,837 258,568 287,000 282,360 285,537 278,451 262,913 235,579 230,895 222,292 237,857 255,749 261,945
Total (MBOE/d) 93,216 88,583 100,694 107,181 107,436 101,042 98,209 87,360 91,022 86,244 90,697 91,671 115,351
% Crude oil and natural gas liquids 54% 51% 52% 56% 56% 54% 55% 55% 58% 57% 56% 54% 62%
Selected Financial Results (C$/BOE)
Oil and natural gas sales(2) $ 47.35 $ 44.70 $ 44.00 $ 40.75 $ 41.64 $ 42.65 $ 31.96 $ 19.53 $ 28.65 $ 30.60 $ 27.82 $ 43.55 $ 48.60
Royalties and production taxes $ (11.92) $ (10.48) $ (11.26) $ (10.80) $ (10.93) $ (10.88) $ (8.16) $ (5.15) $ (7.36) $ (7.67) $ (7.12) $ (10.66) $ (12.58)
Commodity hedging $ (1.05) $ 1.32 $ (0.13) $ 0.53 $ 0.07 $ 0.42 $ 3.69 $ 6.73 $ 2.36 $ 3.12 $ 3.95 $ (2.35) $ (3.53)
Operating expenses $ (7.00) $ (8.75) $ (7.84) $ (7.06) $ (8.05) $ (7.88) $ (8.84) $ (6.84) $ (7.78) $ (8.20) $ (7.94) $ (7.82) $ (8.43)
Transportation costs $ (3.63) $ (3.92) $ (4.02) $ (3.96) $ (3.82) $ (3.93) $ (3.95) $ (4.28) $ (3.85) $ (3.89) $ (3.99) $ (3.98) $ (3.45)
Netback(3) $ 23.75 $ 22.87 $ 20.75 $ 19.46 $ 18.91 $ 20.38 $ 14.70 $ 9.99 $ 12.02 $ 13.96 $ 12.72 $ 18.74 $ 20.61
Cash general and administrative expenses $ (1.47) $ (1.55) $ (1.26) $ (1.19) $ (1.34) $ (1.32) $ (1.37) $ (1.14) $ (1.40) $ (1.46) $ (1.35) $ (1.59) $ (1.04)
Cash share-based compensation $ (0.01) $ (0.17) $ 0.07 - $ 0.01 $ (0.02) $ 0.31 $ (0.15) $ 0.09 $ (0.11) $ 0.04 $ (0.33) $ (0.22)
Interest, FX and other $ (0.92) $ (0.68) $ (0.79) $ (0.49) $ (0.89) $ (0.72) $ (0.97) $ (1.69) $ (0.82) $ (0.81) $ (1.06) $ (1.30) $ (1.39)
Current inome tax recovery $ 0.80 $ 0.69 $ 1.52 - $ 1.41 $ 0.91 - $ 1.81 $ 0.02 $ - $ 0.44 - $ (0.40)
Adjusted Funds Flow(3) $ 22.15 $ 21.16 $ 20.29 $ 17.78 $ 18.10 $ 19.23 $ 12.67 $ 8.82 $ 9.91 $ 11.58 $ 10.79 $ 15.52 $ 17.56
Notes:
(1) Based on Company interest production volumes. See "Basis of Presentation" section in the MD&A.
(2) Before transportation costs, royalties and the effects of commodity price derivatives.
(3) Please see "Non-GAAP Measures" section in the MD&A.
28Advisories
Assumptions
Investor Relations Contacts All amounts in this presentation are stated in Canadian dollars unless otherwise specified. All financial information in this presentation has been prepared and presented in accordance with U.S. GAAP, except as noted below under
“Non-GAAP Measures”.
Drew Mair
Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent
Manager, Investor Relations & This presentation also contains references to "BOE" (barrels of oil equivalent), “MBOE” (one thousand barrels of oil equivalent), and “MMBOE” (one million barrels of oil equivalent). Enerplus has adopted the standard of six thousand
Corporate Planning cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs. BOE, MBOE and MMBOE may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy
403-298-1707 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.
Krista Norlin Non-GAAP Measures
Sr. Investor Relations Analyst In this presentation, Enerplus uses the terms "adjusted funds flow", “free cash flow” (including per share measures), “net debt to adjusted funds flow ratio”, and “reinvestment rate” as measures to analyze operating and financial
403-298-4304 performance. “Adjusted 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 defined as
“Adjusted funds flow less exploration and development capital spending”. “Net debt to adjusted funds flow ratio” is calculated as total debt net of cash divided by a trailing twelve months of adjusted funds flow. “Reinvestment rate”
is calculated as exploration and development capital spending divided by adjusted funds flow..
Email:
investorrelations@enerplus.com Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "adjusted funds flow", “free cash flow” (including per share measures), “net debt to adjusted funds flow ratio”, and
“reinvestment rate” are useful supplemental measures as such provide an indication of the results generated by Enerplus' principal business activities. However, these measures are not 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
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 with the exception of production utilized to calculate reserves replacement ratios which are on a working
interest basis. 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 NI 51-101), are Enerplus' working interest before deduction of any
royalties. Enerplus’ oil and gas reserves statement for the year ended December 31, 2020, 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 (AIF) for the year
ended December 31, 2020 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. All references to “liquids” in
this presentation include light and medium crude oil, heavy oil and tight oil (all together referred to as “crude oil”) and natural gas liquids on a combined basis.
Drilling Inventory
Drilling locations associated with proved plus probable undeveloped reserves have been evaluated or reviewed by Enerplus’ independent qualified reserves evaluators in accordance with the COGE Handbook. Drilling locations associated with unrisked “best estimate” economic
contingent resources in “development pending” project maturity sub-class pertaining to North Dakota have been evaluated by internal qualified reserves evaluators and audited by Enerplus’ independent qualified reserves evaluators, McDaniel & Associates Ltd, in accordance with the
COGE Handbook. Unbooked future drilling locations are not associated with any reserves or contingent resources of Enerplus and have been identified by internal qualified reserves evaluators and have not been audited by Enerplus’ independent qualified reserves evaluators. Existing
Enerplus net locations are as at 1 Jan 2021 and comprise 287 2P undeveloped reserves locations (includes drilled uncompleted wells), 136 best estimate contingent resources locations and 251 unbooked future locations.
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