ENERCOM OIL & GAS CONFERENCEERF: TSX & NYSE
A U G U S T 1 3 , 2 0 1 9
This presentation contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws ("forward-looking information"). The use of any of the words "expect", "anticipate", "continue", “estimate”, “guidance”, "may", "will", "should", "believe", "plans“ 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, on the entire company basis and on an asset-level basis, as applicable: expected 2019 average production volumes, timing thereof as well as the anticipated production mix; targeted 2019 and future production growth and Enerplus’ expected source of funding thereof; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our adjusted funds flow or expected free cash flow in 2019; our drilling program, including future development locations and plans, the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity risk management programs, in 2019 and in the future; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; future efficiencies and reserves and production growth; anticipated cash G&A, share-based compensation and financing expenses; expected operating costs; capital spending levels in 2019 and in the future, along with its components and impact on our production levels and land holdings; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, and our tax pools and the time at which we may pay Canadian cash taxes; net operating income and future adjusted funds flow levels, including on a per share and debt adjusted basis; future debt and working capital levels and net debt-to-adjusted funds flow ratios and adjusted payout ratios, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; our current NCIB and share repurchases thereunder; the amount and timing of future cash dividends that we may pay to our shareholders; and future acquisitions and dispositions, expecting timing thereof and use of proceeds therefrom.
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 low commodity price environment or further volatility; changes in realized prices of Enerplus’ products; changes in the demand for or supply of our products; unanticipated operating results, results from our capital spending activities or production declines; curtailment of our production to retain value, or due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates, incentive programs 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 reserves and contingent 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; constraints on, or unavailability of, adequate pipeline and transportation capacity; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in our Annual Information Form, Form 40-F, and as described under “Risk Factors and Risk Management” in our MD&A for the year ended December 31, 2018).
The forward-looking information contained in this presentation reflects several material factors, expectations and assumptions made by Enerplus including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; 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 our reserves and resources volumes; commodity price and cost assumptions; 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 negotiate debt covenant relief under our bank credit facility and outstanding senior notes if required; the availability of third party services; and the extent of our liabilities. Our updated 2019 guidance herein is based on three months of actual results and the rest of year WTI price of US$56/bbl, a NYMEX gas price of US$2.30/Mcf, and US/CDN exchange rate of 1.31. We believe 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 purpose of our adjusted funds flow disclosure, as well as the net operating income disclosure from both the Corporation’s Marcellus and Canadian Waterflood assets is to assist readers in understanding Enerplus’ expected and targeted financial results, and this information may not be appropriate for other purposes.
Certain measures used in this presentation do not have a standardized meaning under United States GAAP (“U.S. GAAP”). Please refer to “Non-GAAP measures” in the Advisories and to our Second Quarter 2019 MD&A for reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP.
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 such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.
Forward looking information and statements
2
Concentrated position in the Bakken core− >10 years drilling inventory at current pace
High-return oil production growth− 10% to 13% annual liquids growth 2019-2021
Positioned for enhanced free cash flow− Three-year outlook funded within cash flow at $50 WTI(2)
Best in class balance sheet− 0.5x net debt to adjusted funds flow ratio (Q2 2019)(1)
Company overview
3
CDN WATERFLOODS9,200 Boe/d (92% oil)
BAKKEN46,900 Boe/d (83% oil)
MARCELLUS237 MMcf/d (100% gas)
Dual listed: TSX and NYSE
Market capitalization: US$1.3 billion
Net debt(1): US$0.4 billion
Enterprise value: US$1.7 billion
Q2 2019 production: 100,694 Boe/d (52% liquids)
Company Information
1) Non-GAAP measure. See supplemental materials and “Advisories”.2) Adjusted funds flow is expected to be approximately balanced with capex at US$50/bbl WTI and US$3/Mcf NYMEX.3) Production volumes on map are Q2 2019. Map does not include 5.0 mboe/d from other assets.
4
Return on capital employed(1) Cash flow from operationsUS$ Millions
Free cash flow(1)
US$ MillionsReturn of capitalUS$ Millions
10%
18%
23%
2016 2017 2018
$237
$366
$568
2016 2017 2018
$73
$51
$123
2016 2017 2018
$27$22 $23
$61
2016 2017 2018
Dividends Share buybacks
17% 3-year average ROCE
17% 3-year cash flow CAGR (2015-2018)
~$250MMCumulative free cash flow
since 2016
>$80MMReturned to shareholders in 2018
1) Non-GAAP measure. See supplemental materials and “Advisories”.
Disciplined capital allocation and strong returnsT R A C K R E C O R D
$0
$20
$40
$60
$80
$100
$120
$0
$200
$400
$600
$800
$1,000
$1,200
2014 2015 2016 2017 2018
WT
I oil
pric
e (U
S$
/b
bl)
Ad
just
ed f
und
s flo
w a
nd
deb
t n
et o
f ca
sh (U
S$
MM
)
Adjusted funds flow Debt net of cash
Significant debt reduction and accelerating cash flowS T R O N G F I N A N C I A L F L E X I B I L I T Y
1) Non-GAAP measure. See supplemental materials and “Advisories”.5
Adjusted Funds Flow vs Debt Net of Cash(1)
WTI oil price
DEBT REDUCTION>US$500MM in non-
core asset sales MARGIN EXPANSIONLower cost structure & improved
differentials accelerating cash flow
1.3x
2.5x
1.2x0.6x 0.4x
0.0x
1.0x
2.0x
3.0x
4.0x
2014 2015 2016 2017 2018
Net
deb
t /
ad
just
ed fu
nd
s flo
w ra
tio(1
)
Q2 2019 Update
1) Based on the mid-point of production guidance ranges. Per share growth based on share repurchases through August 7, 2019.2) 2019 capital budget of C$610 to C$630 million translated into US$ at 1.33 FX rate.3) Non-GAAP measure. See supplemental materials and “Advisories”.4) Share repurchases YTD through August 7, 2019. Enerplus’ plans to repurchase additional shares are subject to market conditions.
6
Profitable growth 2019 production guidance increased to 99-102 Mboe/d
YoY liquids production growth of 10% (14% on per share basis)(1)
Capital discipline 2019 capital range narrowed to US$460-$475MM(2)
Prioritizing free cash flow over incremental E&D capital spending
Financial flexibility Net debt/adjusted funds flow ratio was 0.5x(3)
Strong free cash flow outlook in H2 2019
Return of capital Returned ~US$85MM of capital through dividends and share repurchases YTD
Expect to maximize share repurchases under the approved NCIB(4)
2019 OUTLOOK ON TRACK
Affordability and value driving share repurchasesR E T U R N O F C A P I T A L - S H A R E R E P U R C H A S E S
1) Based on market conditions as at August 7, 20192) Includes share repurchases up to and including August 7, 2019. Existing NCIB authorization expires March 25, 2020.3) 2019 liquids production growth based on the midpoint of the Company’s guidance. Per share growth based on share repurchases through August 7, 2019.
7
5.9
24.29.4
8.9
0
5
10
15
20
25
30
2018 2019YTD
Remainingauthorization
Total
Sh
are
rep
urch
ases
(MM
)
Share Repurchases(2)
Normal Course Issuer Bid
Enhancing per share metrics
10% LIQUIDS PRODUCTION GROWTH(3)
14% LIQUIDS PRODUCTION PER SHARE GROWTH(3)2019e
Share repurchases represent compelling capital allocation opportunity− Enerplus believes shares are trading at a discounted
value currently(1)
− Ability to acquire increased portion of Company’s reserves at significant discount to F&D costs
Strong liquidity position and free cash flow provides flexibility and affordability for share repurchases
Repurchased >US$130MM in stock since Q3 2018(2)
− >15 million shares repurchased and cancelled
− Plan to repurchase maximum remaining shares under existing NCIB authorization: additional 8.9 million(1)
~10% of shares outstanding
Returns-focused oil growth and positioned for free cash flow2 0 1 9 C A P I T A L A L L O C A T I O N
1) Production growth based on the midpoint of guidance range. Per share growth based on share repurchases through August 7, 2019.2) 2019 capital budget of C$610 to C$630 million translated into US$ at 1.33 FX rate. Includes allocation for maintenance and optimization spending and capitalized G&A expenses.3) Includes operated activity only, except for Marcellus, which is 100% non-operated.
8
High-Margin, Profitable Oil Growth2019e liquids production growth rate(1)
2019 Capital AllocationUS$ millions(2)
+10%(vs. 2018)
+14%(vs. 2018)
Liquids productiongrowth
Liquids production pershare growth
2019 Capital Activity (Net)(3)
North Dakota ~47.5 drills, ~35 wells online
Marcellus ~1.5 drill, ~5.6 wells online
Waterfloods 2 prod./inject. wells, polymer
DJ Basin 4.4 drills, 4.4 wells online
$460-475MILLION
CAPITAL PROGRAM FUNDED AT $50/BBL WTI
MARCELLUS
7.5%
NORTH DAKOTA
80%
WATERFLOODS
7.5%
DJ BASIN
5%
Growth outlook underpinned by North Dakota development
2019E liquids production per share growth of 14% at guidance midpoint(2)
2020 to 2021 targeting 10% to 13% annual liquids production growth
High-margin growth positions Enerplus for accelerated free cash flow at prices above US$50/bblWTI
Focused on returns, profitable oil growth and free cash flowO U T L O O K T H R O U G H 2 0 2 1
1) 2020-2021 outlook assumes approximately flat corporate cost structures relative to 2019, Bakken oil differentials below WTI of US$3.50/bbl (2020) and US3.00/bbl (2021) and Marcellus gas differentials of US$0.30/Mcf below NYMEX2) Based on midpoint of 2019e liquids production and year to date share repurchases through August 7, 20193) Adjusted funds flow expected to be approximately balanced with capex at US$50/bbl WTI and US$3/Mcf NYMEX. Adjusted funds flow and free cash flow are Non-GAAP measures. See “Advisories”
9
0
10
20
30
40
50
60
70
80
2017 2018 2019E 2020E 2021E
Light Oil Production Growth(1)
Liquids production (Mbbl/d)
OUTLOOK FUNDED AT $50/BBL WTI(3)
14% Liquids production/share growth(2)
10% Liquids production growth(2)
2019
Acreage position concentrated in the core of the play
− 65,600 net acres
− Top quartile basin well performance
Singularly unique asset in Bakken core
− Low existing well density
− ~450 gross remaining locations(1)
Tier 1 acreage positionF O R T B E R T H O L D – B A K K E N / T H R E E F O R K S O V E R V I E W
1) Inventory as at December 31, 2018. Gross (net) locations includes 167 (143) proved plus probable undeveloped reserves locations (includes drilled uncompleted wells), 161 (136) best estimate contingent resources locations, and 125 (97) unbooked future locations. See “Advisories”.
2) Production in 2016 and prior has been adjusted for divestments.
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ERF BAKKEN POSITION – FORT BERTHOLD, ND
Capital Efficient Production GrowthNorth Dakota production, Mboe/d(2)
39.7
0
10
20
30
40
2014 2015 2016 2017 2018
42% GROWTH(2018 vs 2017)
FOR
T B
ER
THO
LD IN
DIA
N R
ESE
RV
ATI
ON
Mckenzie
Dunn
McleanMountrail
Efficiencies, lower costs and optimizations are reducing well costs by ~10% compared to 2018 levels
Total well costs currently averaging US$7.5mm (drill, complete, tie-in & facilities)
Strong execution delivering capital efficiency gainsF O R T B E R T H O L D C A P I T A L E F F I C I E N C Y I M P R O V E M E N T S
11
0
3,000
6,000
9,000
12,000
15,000
18,000
21,000
0 2 4 6 8 10 12 14 16 18 20
Dep
th (f
t)
Days
2017 Average2018 Average2019 YTD Average2019 Pacesetter
Drilling Efficiencies - Continuing to Drill FasterDrilling days vs. depth (spud to rig release)(1)
4.9
7.0
8.8
2018 2019 YTD 2019 Pacesetter
Completion Efficiency - More Stages Per DayAverage stages per day(1)
80% IMPROVEMENT
43% IMPROVEMENT
>5 days faster(2019 avg vs 2017 avg)
1) Based on two-mile lateral wells
Low existing well density and large remaining opportunity
Significant running room to support high-return growthF O R T B E R T H O L D D R I L L I N G I N V E N T O R Y
1) Inventory as at December 31, 2018. Gross (net) locations includes 167 (143) proved plus probable undeveloped reserves locations (includes drilled uncompleted wells), 161 (136) best estimate contingent resources locations, and 125 (97) unbooked future locations. See “Advisories”.
2) DSU is a drilling spacing unit. Well locations per DSU is a simple average and may vary by specific DSU.12
High-Return Inventory(1)
Gross operated inventory locations
0
100
200
300
400
500
2019 Program Remaining Inventory
Current Density: ~3 wells/DSU
Ultimate Density: ~10 wells/DSU
Low Existing Well Density(2)
M. BAKKEN
TF 1
TF 2
TF 3
Certain deeper bench locations included in inventory in acreage where these zones are productive
Development Plan per Spacing Unit
~40 operated wells online
~450 operated locations
2 Rigs1 Frac spread
Core acreage and completion design delivering top quartile performanceF O R T B E R T H O L D W E L L P R O D U C T I V I T Y
1) Source: IHS. 2) Well economics based on the average 2P reserves booking/location (2-mile lateral), a total well cost of US$7.5MM and differential to WTI of US$3.25/bbl in 2019, US$3.50/bbl in 2020 and US$3.00/bbl thereafter.
13
Cumulative Oil Production per 1,000 Lateral Feet(1)
Barrels of oil, North Dakota wells since 2014 through 2019WELL ECONOMICS(2)
WTI Oil Price $50/bbl $60/bbl
Payout: 2.3 yrs 1.3 yrs
IRR: 40% 80%
Breakeven (10% IRR): $38/bbl WTI
Days
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
0 200 400 600 800 1,000 1,200 1,400 1,600 1,800
Industry Bakken/Three Forks wells
ERF Three Forks wells
ERF Bakken wells
Aiming to maximize economics through:
− Achieving similar well performance at lower proppant intensity (and lower cost)
− Improving well performance at higher proppant intensity (and higher cost)
Focus on continuous improvement N O R T H D A K O T A C O M P L E T I O N E V O L U T I O N
1) Includes all operated 2-mile lateral wells.2) Source: IHS.
14
0
50,000
100,000
150,000
200,000
250,000
0 40 80 120 160 200 240 280 320 360
Producing Days
Enerplus Operated Well Performance(1)
Cumulative barrels of oil
2012 completions (23 wells)
2013 completions (20 wells)
2014-19 completions (140 wells)
Increasing proppant intensity
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
2012 2013 2014 2015 2016 2017 2018 2019
Enerplus wells
Enerplus Average Proppant Intensity vs ND Peers(2)
Proppant volume (lbs/lateral ft.)
Upper quartile (peer wells)
Lower quartile (peer wells)
Enerplus average
Tes
tin
g an
d o
pti
miz
ing
Improved oil price differentials and constructive outlookB A K K E N P R O D U C T I O N A N D T A K E A W A Y C A P A C I T Y
1) Historical Bakken production is per the NDIC and the forecast per Wood Mackenzie. Production is shown net of local refining.2) DAPL Expansion and Liberty pipelines are proposed projects. In-service dates have been estimated by Enerplus.
15
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
Jan
-10
Jan
-11
Jan
-12
Jan
-13
Jan
-14
Jan
-15
Jan
-16
Jan
-17
Jan
-18
Jan
-19
Jan
-20
Jan
-21
Jan
-22
Jan
-23
Jan
-24-$12.94
-$9.44-$7.46
-$3.72 -$3.78 -$3.25
2014 2015 2016 2017 2018 2019E
Rail loading Rail loading forecast
Pipelines
DAPL
DAPL Expansion
Liberty PipelineExcess rail loading capacity
Bakken Crude Oil Production and Takeaway Capacity(1)
MMbbl/d
Improved Oil Price DifferentialERF realized Bakken oil differential to WTI (US$/bbl)
Bakken differentials have meaningfully strengthened with improved basin egress
Differential outlook is constructive with potential pipeline projects and significant rail capacity
Enerplus continues to manage risk and volatility through marketing arrangements
− 26,300 bbl/d sold at US$2.66/bbl below WTI for H2 2019
Bakken Production
Non-operated position in Marcellus dry gas core− 34,500 net acres
− Q2 2019 production: 237 MMcf/d
Low cost, highly productive inventory− >10 year drilling inventory(1)
Consistent free cash flow generation− Regional infrastructure buildout continuing to improve natural gas
price differential
− Expecting ~20% differential improvement in 2019 compared to 2018
Core acreage position in the Marcellus dry gas windowM A R C E L L U S O V E R V I E W
1) 82.7 net future drilling locations as at December 31, 2018. Includes 29.4 proved plus probable undeveloped reserves locations and 53.3 best estimate contingent resources locations. See “Advisories”2) Net operating income (“NOI”) is a Non-GAAP measure. 2019 forecast based on strip prices. See supplemental materials and “Advisories”
16
MARCELLUS POSITION – NE PENNSYLVANIA
SusquehannaBradford
Sullivan
Lycoming
Wyoming
Enerplus Marcellus ProductionMMcf/d
195198
208
223
2016 2017 2018 2019 H1
Accelerating Free Cash FlowCapex vs Net Operating Income (US$MM)(2)
$0
$25
$50
$75
$100
2016 2017 2018 2019E
Capex NOI
Improved differentials and low transport cost supporting margin despite reduction in NYMEX prices
Expansion of basin pipeline takeaway to continue to support pricing in 2019+
Low cost structure, improved realized pricing and strong capital efficiencies expected to drive continued free cash flow
Cash margin expansion driven by improved regional pricingM A R C E L L U S M A R G I N I M P R O V M E N T
17
Differential Improvement Increasing Cash FlowMarcellus cash margin (US$/Mcf)
$0.29$0.51
$1.06$1.31
$1.05$1.00$1.02
$1.29
$1.34
$1.19
$1.37 $0.93
$0.76$0.43
$0.35
$2.66$2.46
$3.11 $3.08
$2.59
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
2015 2016 2017 2018 2019E
Cash Margin Opex, Gathering, Trans, Royalty
Basis Differential NYMEX Benchmark Price
-
1
2
3
4
5
6
7
8
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22
Bcf
per
wel
l
Months on Production
Lateral Length < 5,000 ft
Lateral Length 5,000 ft - 7,500 ft
Lateral Length > 7,500 ft
Capital efficient and highly productive drilling inventoryM A R C E L L U S W E L L R E S U L T S
1) Based on >145 wells on production since January 20172) Well economics based on the average 2P reserves booking/location and 6,300 ft lateral length for a total well cost of US$6.8MM. Basis differentials to NYMEX: -US$0.35/Mcf in 2019 and -US$ 0.30 in 2020. Transport cost of
approximately US$0.15-$0.20/Mcf
18
Marcellus well performance 2017-2019 Average cumulative production per well(1)
WELL ECONOMICS(2)
NYMEX Gas Price: $2.75/Mcf $3.00/Mcf
Payout: 3.1 yrs 2.4 yrs
IRR: 26% 37%
Breakeven (10% IRR): $2.30/Mcf
40 wells
65 wells
42 wells
~39,000 net acres in NW Weld County
− Low entry price achieved through leasing and farm-in activity during downturn in 2015/16
− Significant oil in place through all Niobrara benches and Codell
Initial five well results compare favorably to core DJ oil rates
~400 gross drilling locations(1) identified in southern portion of acreage at 6-Codell and 6-Niobrara density
− Additional benches with significant oil saturations offer upside
Five (four net) wells drilled in Q2 2019 expected to be completed in H2 2019
Northern extension of Wattenberg fieldE M E R G I N G O P P O R T U N I T Y – D J B A S I N
1) Internally identified future drilling locations. Average working interest expected between 40% - 70%. 19
DJ BASIN
2017/2018 - 5 wells on prod.(4 Codell, 1 Niobrara)
2019 - 5 wells drilled, waiting on completion (H2 2019)
DENVER
WELD
MORGAN
ADAMS
WYOMING
COLORADO
Track record of disciplined capital allocation and strong returns− 17% cash flow CAGR (3-year)
− >US$230 million in cumulative free cash flow(1) (3-year)
− 17% return on capital employed(1) (3-year avg.)
Concentrated position in the Bakken core− >10 years of high-quality drilling inventory at current pace
High-return oil production growth− 10% to 13% annual liquids growth 2019-2021
Positioned for enhanced free cash flow− Three-year outlook funded within cash flow at $50 WTI(2)
Best in class balance sheet− 0.5x net debt to adjusted funds flow ratio (Q2 2019)(1)
Returns and value focused
20
CDN WATERFLOODS9,200 Boe/d (92% oil)
I N V E S T M E N T H I G H L I G H T S
1) Non-GAAP measure. See supplemental materials and “Advisories”.2) Adjusted funds flow is expected to be approximately balanced with capex at US$50/bbl WTI and US$3/Mcf NYMEX.3) Production volumes on map are Q2 2019. Map does not include 5.0 mboe/d from other assets.
BAKKEN46,900 Boe/d (83% oil)
MARCELLUS237 MMcf/d (100% gas)
Assumptions
All amounts are stated in Canadian dollars unless otherwise specified.
Barrels of Oil Equivalent and Cubic Feet of Gas Equivalent
This presentation contains references to "BOE" (barrels of oil 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. BOEs 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 “adjusted funds flow", “net debt to adjusted funds flow ratio”, “netback”, “net operating income”, and "free cash flow" as measures to analyze leverage, liquidity and operating performance. These measures do not have any standardized meaning
under United States GAAP (“U.S. GAAP”) and are therefore, considered Non-GAAP measures. “Adjusted funds flow” is calculated as cash flow from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. “Net debt
to adjusted funds flow ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The net debt to adjusted funds flow ratio is calculated as total debt net of cash, divided by a trailing 12 months of funds flow. “Netback” and “net
operating income” are calculated as oil and gas revenues after deducting royalties, operating costs and transportation expenses. “Free cash flow” is calculated as “adjusted funds flow” less exploration and development capital spending (refer to “Non-GAAP Measures” in the Second
Quarter 2019 MD&A).
Enerplus believes that, in addition to cash flow, net earnings and other measures prescribed by U.S. GAAP, the terms “adjusted funds flow", “net debt to adjusted funds flow ratio”, “netback”, “net operating income”, and "free cash flow“ 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 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. For reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about these measures, see additional disclosure and reconciliations to
certain of these “Non-GAAP Measures” in the MD&A.
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. To remain 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. In addition, initial test results and production
performance referenced should be considered preliminary data and such data is not necessarily indicative of long-term performance, or of ultimate recovery.
Readers are cautioned that the average initial production rates contained in this presentation are not necessarily indicative of long-term performance or of ultimate recovery.
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 “gross reserves" using forecast prices and costs. “Gross reserves" (as defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101")), being Enerplus’ working interest before deduction of any royalties. Our oil and gas
reserves statement for the year ended December 31, 2018 includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, and is contained within our Annual Information Form for the year ended December 31, 2018 ("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 for more complete disclosure on our operations.
Discovered Petroleum Initially-In-Place, Discovered Original Oil-In-Place and Discovered Original Gas In Place
Discovered Original Oil in Place (“OOIP” ) is not defined in NI 51-101 and does not have a standardized meaning under NI 51-101. Discovered OOIP as used in this presentation is the crude oil portion of discovered PIIP. Discovered OOIP pertaining to our Canadian waterflood assets
are estimates by internal qualified reserves evaluators, combined for all Canadian waterflood assets.
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Contingent Resources Estimates
This presentation contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with oil and gas reserves. The estimates of contingent resources included in this presentation pertaining to Canadian waterflood assets and Fort Berthold were
evaluated by Enerplus’ internal qualified reserves evaluators and audited by independent reserves evaluators, McDaniel & Associates Ltd. The estimates of “contingent resources” included in this presentation pertaining to the U.S. Shale Gas-Marcellus were evaluated by independent
reserves evaluators, Netherland, Sewell & Associates, Inc. "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 quantities associated with a project in the early evaluation stage. All of our “contingent resources” estimates are economic using established
technologies and based on January 1, 2018 forecast prices of McDaniel & Associates Ltd. 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 it will be commercially viable for us to produce any portion of the volumes currently classified as “contingent resources”. “Development pending contingent resources” refer to a “contingent resources” project maturity sub-class for a project where resolution of the final
conditions are being actively pursued (there is a high chance of development) and the project is expected to be developed in a reasonable timeframe. The “contingent resources” estimates contained herein are presented as the "best estimate" of the quantity that will actually be
recovered. “Contingent resources” estimates are effective as of December 31, 2018. 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 Marcellus shale gas properties, our Fort Berthold properties, and a portion of our Canadian waterflood properties as
reserves, and the positive and negative factors relevant to the "contingent resource” estimates, see Appendix A to the most recent 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 at www.sec.gov.
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 Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”). Drilling locations
associated with unrisked “best estimate” economic contingent resources in “development pending” project maturity sub-class pertaining to Canadian waterflood assets and Fort Berthold 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. Drilling locations associated with unrisked “best estimate” economic contingent resources in “development pending” project maturity sub-class pertaining to the U.S.
Shale Gas-Marcellus been evaluated by Enerplus’ independent qualified reserves evaluators, Netherland, Sewell & Associates, Inc, 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.
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 with respect to production information, "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 Resources Estimates” above.
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