INVESTOR UPDATE December 2021 - TSX & NYSE: ERF - Enerplus
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INVESTOR UPDATE
December 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: Enerplus' expected 2021 and 2022 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; expected 2021 and 2022 free cash flow; 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$68.76/bbl WTI, US$3.87/Mcf
NYMEX, and a USD/CDN exchange rate of 1.25. In addition, Enerplus’ preliminary 2022 outlook contained in this news release is based on the following: a WTI price of US$72.88/bbl, a NYMEX price of US$4.44/Mcf and a USD/CDN
exchange rate of 1.24. 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
Over a decade of high-return Bakken drilling inventory CDN
WATERFLOODS
Strong balance sheet and liquidity position
Robust free cash flow outlook
BAKKEN MARCELLUS
Committed to strong ESG performance
2021e production by area 2021e production by product Dual listed: TSX & NYSE
Market capitalization: C$3.0 billion
28% 2021e production: 114,000 BOE/d (61% liquids)
63% 61%
39%
6%
3%
Bakken Marcellus
Liquids Natural Gas
Waterfloods Other
3
TRACK RECORD High return growth, free cash flow and low leverage High return oil growth Focus on free cash flow Return of capital Low financial leverage Production, MBOE/d Free cash flow(1), C$ millions C$ millions Net debt to adjusted funds flow ratio(1) 15% >$900MM $525MM
2021 update
RESILIENT Company production of 123,000 BOE/d in Q3 (+7% qoq, +36% yoy)
PRODUCTION Continued growth in Q4: guidance of 124,500-128,500 BOE/d
FREE CASH Generated $176MM in free cash flow in Q3(1)
FLOW
GENERATION Estimate ~$540MM in free cash flow in 2021(1)(2)
SOLID Sold non-strategic assets in Q4 generating proceeds of US$115MM
FINANCIAL
POSITION Net debt/adjusted funds ratio expected to be
2021 & Q4 operating outlook
Total production Liquids production E&D capital spending
(mboe/d) (mbbl/d) (C$ millions)
+28 +22 +$80
MBOE/d(1) MBBL/d(1) MILLION
124.5-128.5 80-83 $380
113.75-114.75
69.75-70.75 $300
86
48
Pre - Post - Pre - Post - Pre - Post -
acquisitions acquisitions acquisitions acquisitions acquisitions acquisitions
Original annual Current annual Q4 2021 Original annual Current annual Q4 2021 Original 2021 Current 2021
2021 guidance 2021 guidance guidance 2021 guidance 2021 guidance guidance guidance guidance
1) Based on guidance mid-points.
6
2022 preliminary outlook
High rate-of-return, sustainable growth Bakken focused capital budget Protection against cost inflation
Production (mboe/d, mbbl/d)(1) 2022e E&D capital allocation % of North Dakota well cost structure protected/unprotected
~7% yoy liquids production growth
3-5% yoy organic liquids production growth
(after adjusting for 2021 acquisitions)
Williston Basin
Protected
~122
114.25 MBOE/d
MBOE/d Key cost structures
83% 75%
protected:
Drilling rigs
~75
70.25 ~75% Pressure pumping
MBBL/d
MBBL/d
~C$500 OF WELL COSTS
Sand
MILLION Majority of casing
PROTECTED Coil tubing
Drilling fluids
11% Wireline
25%
6% Marcellus Workover rigs
2021e 2022e Canada / DJ Basin Unprotected
Total Production Liquids Production
7
1) Based on the midpoint of 2021 production guidance.
2021 & 2022 free cash flow outlook and return of capital
Strong year on year free cash flow growth Attractive free cash flow yield
Free cash flow at forward strip prices (C$ millions)(1) Free cash flow yield at forward strip prices(1)(2) ANNOUNCED RETURN OF CAPITAL PLANS
19% >20% $200MM share buyback program
FREE CASH FREE CASH Commencing in Q4 2021
FLOW GROWTH FLOW YIELD $107MM allocated in November
To be funded from Q4 ’21 & Q1 ’22 free cash flow
$640 21%
$540 18% Based on
Dividend increased 37% in 2021
2022e
FCF Most recent increase in Q4 2021
Based on Annual dividend of $39MM(3)
2021e
FCF
2021e 2022e 2021e 2022e
1) Non-GAAP measure. 2021e free cash flow based on guidance midpoints. 2022e free cash flow based on 2022 preliminary outlook. Based on forward strip prices on Nov 3, 2021.
2) Free cash flow yield represents adjusted funds flow less capital expenditures divided by market capitalization. Based on share price of C$12.00. 8
3) Annual dividend of $39MM in 2022 includes the estimated impact of the $200MM share repurchase program.Strong liquidity and low financial leverage
Significant liquidity Track record of low financial leverage
Estimated liquidity position at September 30, 2021 (US$ millions) Net debt to adjusted funds flow ratio(2)
Enerplus was the first North American E&P to transition its principal credit facility to a Sustainability
Linked Credit Facility, incorporating ESG performance targets
~US$774 3x
TERM FACILITY
Avg. interest rate: 1.83%(1)Capital allocation principles and framework
Principles Framework Execution
Debt target expected to be achieved in Q4 2021(2)
MAINTAIN Long term ND/AFF ratio(1) target: 1.0x or less assuming
LOW LEVERAGE US$50 WTI price environment Continuing to reinforce balance sheet with portion
of free cash flow
2021e & 2022e free cash forecast is ~$540MM
GENERATE Long term capital spending reinvestment rate(1) of less and ~$640MM, respectively(1)(2)
FREE CASH FLOW than 75% of adjusted funds flow 2021e & 2022e forecast reinvestment rate ~41%
and 44%, respectively(1)(2)
RETURN Sustainably grow base dividend supported by an increasing Dividend increased 37% YTD
CAPITAL TO cash flow base. Share repurchases to enhance the return of $200MM share repurchase program commencing
SHAREHOLDERS capital to shareholders Q4 2021
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”. 10
2) Based on forward strip prices on Nov 3, 2021.Five year outlook focused on free cash flow growth
HIGHLIGHTS OF THE FIVE YEAR OUTLOOK
Based on WTI oil price environment of US$50-55/bbl
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- 11
2025 are based on WTI oil prices of US$50-$55/bbl and NYMEX natural gas prices of US$2.75/Mcf.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. 12
3) Lost Time Injury Frequency.ASSET & OPERATIONAL HIGHLIGHTS
13WILLISTON BASIN
Strategic acquisitions increase 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 tier 1 locations, additional upside potential
− Dunn county: 110 tier 1, 120 Middle Bakken upside, Three Forks upside potential McKenzie
~30,000 BOE/d production added
− Bruin: 24,000 BOE/d (~30% decline rate)
− Dunn county production: 6,000 BOE/d (~18% decline rate)
Dunn
Billings DIVESTMENT
Bruin acquisition Dunn county acquisition Closed Nov 2, 2021
CLOSED March 10, 2021 CLOSED April 30, 2021
1) Excludes the acreage sold in connection with the Williston Basin divestment which closed Nov 2, 2021. 14
2) See “Advisories – Drilling Inventory” for a reconciliation of undrilled locations between those associated with reserves and those not associated with any reserves.WILLISTON BASIN
Acquisitions have extended high-quality inventory
Drilling inventory expansion(1)
Net locations >10 years of tier 1 drilling inventory
(at development pace assumed in 5-year plan)
~675
120
110
Non-FBIR development plan
60 5-6 wells per spacing unit
51 MB
333 Bruin acquisition Dunn co. acquisition TF 1 Upside
FBIR development plan per spacing unit
~10 wells per spacing unit
UPSIDE UPSIDE
POTENTIAL POTENTIAL MB
TF 1
TF 2 TF2 locations in select areas
15
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.WILLISTON BASIN
Significant inventory and inventory upside in the core/extended core
Acreage in core & extended core Largely undrilled; substantial inventory
Significant acreage in the established Productivity: 6 month BOE/1K foot lateral Drilling density: wells per spacing unit
economic core of the play Williams
− FBIR, parts of Little Knife/Williams
Large remaining opportunity set
− More than a decade of tier 1 inventory FBIR
Opportunity to extend core inventory
through modern stimulation/well
Little
design Knife
− Lightly drilled acreage in Murphy Creek,
southern Little Knife and central Williams
offers substantial inventory upside
− Pre-existing wells largely completed before
advances in well stimulation
Murphy Creek
Outlines are Enerplus operated units Outlines are Enerplus operated units
16
1) Source: Productivity mapping from Tudor, Pickering, Holt & Co. Drilling density based on internal mapping.WILLISTON BASIN
Strong well results offsetting Enerplus’ lightly drilled southern acreage
NOTABLE OFFSET OPERATOR WELLS (2018+)
Enerplus operated acreage
Continental Gordon Federal 9-5H Enerplus non-op acreage
2-Mile Middle Bakken Lateral
Completed Nov 2020 Williams
6-month oil production: 106 MBBL
Mountrail
ConocoPhillips Franklin 34-36MBH Marathon Drake 44-16H
Fort Berthold
2-Mile Middle Bakken Lateral 2-Mile Middle Bakken Lateral
Completed Dec 2019 Completed Nov 2018
6-month oil production: 124 MBBL 6-month oil production: 154 MBBL
McKenzie
Continental Nadia 7-19H Marathon Reiss Lily 41-14H
2-Mile Three Forks 1 Lateral 2-Mile Middle Bakken Lateral
Completed Oct 2020 Completed Sep 2019
6-month oil production: 130 MBBL 6-month oil production: 118 MBBL
Marathon Ruggles 14-33H
Continental Marshall 8-24H 2-Mile Middle Bakken Lateral
2-Mile Middle Bakken Lateral Completed Nov 2020
Dunn
Completed Feb 2020 Billings 6-month oil production: 112 MBBL
6-month oil production: 79 MBBL
17
1) Source: NDIC.WILLISTON BASIN - FORT BERTHOLD WELL PERFORMANCE
Maintaining strong well performance at lower cost
Enerplus well performance Total well costs
Cumulative oil production per well (Mbbl)
(US$MM)(1) 34%
600 $8.6 WELL COST
REDUCTION
SINCE 2018
US$2.9MM
500 $5.7
REDUCTION
IN WELL COSTS
400 SINCE 2018
300
2018 2019 2020 2021e
200
EFFICIENCY GAINS
Drilling days (spud to rig release) Completions (stages/day)
100 Normalized to 20,700 ft depth
IMPROVEMENT IMPROVEMENT
16% SINCE 2018 160% SINCE 2018
-
0 100 200 300 400 500 600
14.6
Producing days 12.2 13.0
2017 wells 2018 wells 2019 wells 2020 wells 2021 wells 4.9
2017 Avg 2018 Avg 2019 Avg 2020 Avg 2021 Avg
2018 2021 2018 2021 18
1) Total well cost includes drilling, completion and facilities costs.MARCELLUS OVERVIEW
Core acreage position in the Marcellus dry gas window
MARCELLUS POSITION – NE PENNSYLVANIA
Non-operated position in Marcellus dry gas core Bradford Susquehanna
− 32,600 net acres, ~200 MMcf/d production(1)
Capital efficient and highly productive well performance
− >10 year drilling inventory(2) Wyoming
Sullivan
High quality exposure to robust natural gas prices
Lycoming
− Consistent free cash flow generation
Marcellus production & capex Marcellus pricing exposure Marcellus unhedged annual net operating income
MMcf/d and US$ millions Approx. % of natural gas sales Sensitivity to NYMEX (US$ millions) $199
26%
300 $75 $168
$45 $51 Leidy $138
200 $37 $35-$40 $50
$24 TZ6 Non-NY US$0.55/Mcf $108
100 $25 Gulf Coast 2021e portfolio $77
198 208 227 193 195-200 differential below 19%
0 $0 Other NYMEX
2017 2018 2019 2020 2021e 52% $3.00 $3.50 $4.00 $4.50 $5.00
Production Capex 3%
NYMEX Benchmark Price (US$/Mcf)
19
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”.APPENDIX
202021 guidance, operating statistics and well economics
2021 ANNUAL GUIDANCE(1) Q4 2021 GUIDANCE WELL ECONOMICS
E&D capital spending (C$MM)(2) $380 BAKKEN - FORT BERTHOLD(1)
Total production (Mboe/d) 113.75-114.75 Total production (Mboe/d) 124.5-128.5 WTI oil price US$50/bbl US$60/bbl
Liquids production (Mbbl/d) 69.75-70.75 Liquids production (Mbbl/d) 80-83 Payout 1.5 years 0.9 years
Operating expense ($/boe) $8.80 Operating expense ($/boe) $8.80 IRR: 60% 100%+
Cash G&A expense ($/boe) $1.15 Breakeven (10% IRR) US$38/bbl WTI
Transportation expense ($/boe) $3.85
MARCELLUS(2)
Avg. royalty & prod. tax rate 26%
NYMEX natural gas price US$3.00/Mcf US$3.50/Mcf
Current income tax expense (US$MM) $3
Payout 2.0 years 1.4 years
Bakken oil price diff. vs WTI (US$/bbl) $(2.00)
IRR 50% 90%
Marcellus natural gas price diff. vs NYMEX (US$/Mcf) $(0.55)
Breakeven (10% IRR) US$2.30/Mcf NYMEX
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.
2021 ASSET DETAILS(3) BAKKEN MARCELLUS CANADA DJ BASIN 2) Marcellus well economics are based on the average 2P reserves booked per undeveloped location
(~18 Bcf/well, 7,400 ft lateral) and a total well cost of US$6.3MM.
Capital allocation (approx.)(2) 80% 10% 5% 5%
18-20 66-72 2
Wells drilled (gross) -
(~99% WI) (~4% WI) (~15% WI)
50 77-83 2 3
Wells online (gross)
(~80% WI) (~6% WI) (~15% WI) (~87% WI)
1) Guidance has been adjusted for Williston Basin divestment which closed Nov 2, 2021 . 21
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.Bakken egress and oil price differential outlook
Bakken oil production & takeaway capacity(1)
Millions of bbl/d
2.8 DAPL expansion to
750 mb/d Aug BAKKEN DIFFERENTIAL
2.4 2021 (BELOW WTI)
2.0
US$2.00/BBL
2021 OUTLOOK
1.6
Excess rail loading capacity(3) Production(2)
1.2 Strong pricing supported by
DAPL significant spare pipeline capacity
0.8 ~400,000 BBL/d of estimated
Pipelines (ex DAPL) spare pipeline capacity currently
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.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 25% INCREASE
lateral ft IN 6-MONTH CUMULATIVE PRODUCTION /
0.7
Avg. LATERAL FT IN 2021 VS 2018
0.6 Avg. 10,000 9,200
lateral ft lateral ft
Bcf/1,000 ft lateral
0.5 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
23
1) Enerplus’ average working interest in the Marcellus wells is 2.9% in 2021, 3.3% in 2020, 9.7% in 2019, 9.2% in 2018 (production weighted).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 free cash flow generating assets Low decline production GILTEDGE − Q3 2021 production was ~7,562 BOE/d (94% oil) CADOGAN Saskatchewan −
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
25COMMODITY 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)
Oct 1 – Dec 31, 2021 - - 7.179 $43.01 23.0 $36.39 $46.39 $56.70 - - -
Jan 1 – Jun 30, 2022 - - - - 12.5 $58.00 $75.00 $87.63 - - -
Jan 1 – Sep 30, 2022 - - 4.500 $42.31 - - - - - - -
Oct 1 – Dec 31, 2022 - - 1.834 $42.65 - - - - - - -
Jan 1 – Dec 31, 2022 - - - - 17.0 $40.00 $50.00 $57.91 - - -
Jan 1 – Dec 31, 2023 - - 0.208 $42.10 - - - - 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)
Oct 1 – Oct 31, 2021 60,000 $2.90 40,000 $2.15 $2.75 $3.25
Nov 1 – Mar 31, 2022 - - 40,000 - $3.43 $6.00
Apr 1, 2022 – Oct 31, 2022 40,000 $3.40 - - - -
1) The total average deferred premium spent on these contracts is US$0.87/bbl from Oct 1, 2021 to Dec 31, 2021 and US$1.29/bbl from Jan 1, 2022 to Dec 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 contracts were recorded at a fair value liability of $96.5 million. At September 30, 2021, the fair value of the Bruin contracts was a liability of $82.6 million, including $42.6 million of the original $96.5 million liability acquired. For
the three and nine months ended September 30, 2021 we recorded a realized loss of $10.3 million and $11.9 million, respectively, on the settlement of the Bruin contracts. In addition, we recognized an unrealized loss of $4.6 million and $40.0 million, respectively, for the change in the fair 26
value of the Bruin contracts over the same periods. See Note 17 b) to the Q3 2021 Financial Statements for further detail.The Board of Directors
Hilary A. Foulkes (Director since February 2014) Robert B. Hodgins (Director since November 2007)
Compensation & Human Resources Committee
Board Chair Corporate Governance & Nominating Committee (Chair)
Judith D. Buie (Director since January 2020) Susan M. MacKenzie (Director since July 2011)
Audit & Risk Management Committee Compensation & Human Resources Committee (Chair)
Corporate Governance & Nominating Committee Reserves, Safety & Social Responsibility Committee
Reserves, Safety & Social Responsibility Committee
Karen E. Clarke-Whistler (Director since December 2018) Jeffrey W. Sheets (Director since December 2017)
Compensation & Human Resources Committee Audit & Risk Management Committee (Chair)
Corporate Governance & Nominating Committee Compensation & Human Resources Committee
Reserves, Safety & Social Responsibility Committee
Ian C. Dundas Sheldon B. Steeves (Director since June 2012)
Audit & Risk Management Committee
President and CEO Reserves, Safety & Social Responsibility Committee (Chair)
27Summary of operational and financial metrics
2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019 Q1 2020 Q2 2020 Q3 2020 Q4 2020 2020 Q1 2021 Q2 2021 Q3 2021
Average Benchmark Prices
WTI Crude Oil (US$/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 $ 70.56
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 $ 4.01
Production(1)
Crude 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 67,910
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 10,602
Natural gas (MMcf/d) 259,837 258,568 287,000 282,360 285,537 278,451 262,913 235,579 230,895 222,292 237,857 255,749 261,945 269,652
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 91,671 115,351 123,454
% Crude oil and natural gas liquids 54% 51% 52% 56% 56% 54% 55% 55% 58% 57% 56% 54% 62% 64%
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 $ 58.47
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) $ (15.07)
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) $ (5.50)
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) $ (9.89)
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) $ (3.61)
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 $ 24.40
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) $ (0.95)
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) $ (0.09)
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) $ (0.94)
Current inome tax recovery/(expense) $ 0.80 $ 0.69 $ 1.52 - $ 1.41 $ 0.91 - $ 1.81 $ 0.02 $ - $ 0.44 - $ (0.40) $ 0.10
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 $ 22.52
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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