Post on 16-Jul-2020
Corporate Presentation
March 2020
This presentation contains forward-looking statements and forward-looking information (collectively, forward-looking statements") within the meaning of applicable securities laws. The use of any of the words "will", "may", "expects", "believe", "plans", "potential", "continue", "guidance", and similar expressions are intended to identify forward-looking statements. More particularly and without limitation, this presentation contains forward looking statements, with respect to: management's assessment of: NuVista's future focus, strategy, plans, priorities, opportunities and operations; the quality and growth potential of NuVista's Montney assets; 2020 guidance with respect to average production, capital investment; 2020 total production and the percentage of such production to be obtained from the Montney and other areas; expectations that NuVista has the ability and the flexibility to grow production to 110,000 Boe/d or flatten production at 68,000 Boe/d by 2021-20232 while generating free adjusted funds flow; expectations regarding initial production at Pipestone South and that it will become NuVista's highest return area; the timing of the start-up and future capacity of the Pipestone South facility; expectations that Elmworth economics will continue to improve and that HiFi drilling and focus on CGR ratios will result in Elmworth returns becoming towards the top of NuVista's portfolio; plans to focus on high-grading activities such as longer wells and frac design at Gold Creek; plans to optimize learnings and results in all areas leading to cost and productivity improvements; expectations that the production growth required to meet future minimum volume commitments can be obtained by 2021 and within adjusted funds flow and that free adjusted funds flow or growth can be obtained thereafter; expectations that future condensate-rich Montney industry growth will continue; 2020 through 2023 capital expenditures, production, adjusted funds flow and free adjusted funds flow; expectations that NuVista will experience measured self-funded growth; 2020 through 2023 capital expenditures, production, adjusted funds flow and free adjusted funds flow; NuVista's five-year outlook for production and free adjusted funds flow; the pace of development and that this will result in production per share growth returns of approximately 0-15% per year, all within anticipated adjusted funds flow; Montney well inventory potential; market egress plans, optionality and impact; future production and expected future capacity and the timing thereof in NuVista's four main operating areas; NuVista's well and location inventories; plans to ramp-up volumes at Pipestone, timing of the completion of the Pipestone South compressor station and pipeline, future growth at Pipestone, forecast production mix and production at Pipestone; expectations that well inventory at Elmworth is sufficient to produce at facility capacity for at least 10 years; expectations that the Bilbo, Elmworth and Gold Creek areas will generate free adjusted funds flow; plans to ramp up volumes at Gold Creek, future forecast production mix and expected facility capacity and well inventory at Gold Creek; expectations with respect to Bilbo, Elmworth and Gold Creek future production, operating income and stay flat capital requirements and associated free adjusted funds flow and excess cash; expectations that NuVista's record of execution and improvement will continue and that Pipestone development will further improve overall returns; Pipestone development and infrastructure plans and costs; future Pipestone condensate weighting, future production and processing capacity; future DCET costs and Pipestone South and the timing of bringing future production on-stream; existing and future processing options; future condensate demand and pricing; natural gas pricing diversification plans and results; NuVista's ESG plans; expectations that NuVista's returns will increase as a result of Pipestone operations, future cost reductions and technology advancements; the impact of NuVista's commodity hedging program and financial basis hedges; annual adjusted funds flow, stay-flat capital expenditures and production mix at NuVista's near-term production target and the associated CGRs, commodity prices, operating and transportation expenses, decline rates and capital efficiencies; 2020 capital expenditures, plans, allocation and expectations and the flexibility of NuVista's capital expenditure plans; 2020 production and product mix, free adjusted funds flow, operating income, stay-flat capital expenditures and production mix at Bilbo and Elmworth and the associated CGRs, commodity prices, operating and transportation expenses, decline rates, capital efficiencies and capital returns; Bilbo, Elmworth, Gold Creek and Pipestone type curves; payouts, rates of return, NPV10 and other economics and anticipated associated DCET, EURs, CGRs, operating expenses and drilling plans; expectations with respect to improving capital efficiencies at Elmworth and that this will result in payout periods toward one year; 2020 estimated production and production mix at Gold Creek and Pipestone; anticipated drilling results for lower Montney wells currently being drilled; expectations with respect to future reserve upside; and future reservoir optimization plans.
Statements relating to "reserves" and "resources" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves or resources described exist in the quantities predicted or estimated and that the reserves or resources can be profitably produced in the future.
By their nature, forward-looking statements are based upon certain assumptions and are subject to numerous risks and uncertainties, some of which are beyond NuVista's control, including the impact of general economic conditions, industry conditions, current and future commodity prices and differentials, currency and interest rates, anticipated production rates, borrowing, operating and other costs and adjusted funds flow, the timing, allocation and amount of capital expenditures and the results therefrom, anticipated reserves and resources and the imprecision of reserve and resource estimates, the performance of existing wells, the success obtained in drilling new wells, the sufficiency of budgeted capital expenditures in carrying out planned activities, access to infrastructure and markets, competition from other industry participants, availability of qualified personnel or services and drilling and related equipment, stock market volatility, effects of regulation by governmental agencies including changes in environmental regulations, tax laws and royalties; the ability to access sufficient capital from internal sources and bank and equity markets; obtaining the necessary regulatory approvals to complete the acquisition and other transactions referred to herein on the terms and timing contemplated and including, without limitation, those risks considered under "Risk Factors" in NuVista's Annual Information Form. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed onforward-looking statements. NuVista's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements, or if any of them do so, what benefits NuVista will derive therefrom. NuVista has included the forward-looking statements in this presentation in order to provide readers with a more complete perspective on NuVista's future operations and such information may not be appropriate for other purposes. NuVista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
Advisory Regarding Forward-Looking
Information and Statements
March 2020 1
27% 50%75%
90%97%
97%97%
97%
0
10
20
30
40
50
60
2013* 2014 2015 2016 2017 2018 2019 2020E
Wapiti Montney Wapiti Sweet Other Pipestone Acquisition
Production (MBoe/d)
NuVista Snapshot
March 2020
TSX Trading Symbol: NVA
Market Capitalization: ~$500 million
Basic Shares Outstanding: 225.6 million
Credit Facility Capacity: $550 million
Percent Drawn(1): 55%
Net Debt/Adjusted Funds Flow(2): 2.0x
NuVista Corporate Info
Grande Prairie
Edmonton
Calgary
NuVista Wapiti Montney Project
Non-Core Areas
1 Percent drawn at December 31, 2019 on $550MM facility 2 Q4 2019 Net Debt to annualized Q4 2019 Adjusted Funds Flow See "Non-GAAP Measurements" * Pro-forma 2013 Divestitures
Guidance 2020
Full Year Avg. Production (Boe/d) 57,000 – 61,000
Q1 Average Production (Boe/d) 50,000 – 54,000
Q2 Average Production (Boe/d) 58,000 – 62,000
Full Year Capital Investment ($MM) $300 – $330
2
Built-in Control and FlexibilityValue Creation Remains Top-Priority
March 2020
Pure-Play Montney Company – In The Right Neighborhood
Flexibility to Grow to 110,000 Boe/d or Flatten at 68,000 Boe/d in 2021-2022 while Generating Free Adjusted Funds Flow ("FAFF")
Wellhead-to-Market Egress Plan In-Place – Material Flexibility in Infrastructure Agreements
Returns Focused – Four Established Development Blocks with Current Growth Tranche coming from Top-Tier Pipestone Area
30%+ Condensate Production – Torque to Oil Price + Rolling Hedging Program
Proven Track Record of Execution & Continuous Improvement
3
Upcoming Catalysts on the Horizon for NuVista
March 2020
• Pipestone South: Q4 2019 First Production – ON-STREAM Q3 2019• 15,000 Boe/d facility startup, first stage is 10,000 Boe/d• 11 Wells now on-stream – all 4 developable horizons tested• Avg IP90 of 6.0 MMcf/d and CGR of 72 Bbls/MMcf – in-line with area type curve • Third pad (6 wells) now on-stream
• Active Q419/Q120 Winter Drilling Season15 wells drilled
• All wells planned to be started up over H1 2020
• Pipestone North: 2020 Growth• 12 well pad – expected to be on-stream Q4 2020
• Bilbo: Material FAFF• Moderating base decline – reduces on-going maintenance capital
• Elmworth: Economics Continue to Improve• Hi-Fi and focus on higher condensate gas ratio ("CGR") areas
• Gold Creek: Focus on High-Grading• Longer wells and frac design optimization to drive returns
4
0
50
100
150
200
250
300
350
2015 2016 2017 2018 2019
Wel
ls S
pu
d
Wembley/Pipestone Wapiti/Kakwa
Wembley to Kakwa Montney HZ Activity Update
Wembley to Kakwa Production Growth(1)
Montney – In The Right NeighborhoodCondensate-Rich Montney Industry Growth Continues
(1) Excludes southern areas of Alberta Condensate-rich Montney (Resthaven and Simonette). Map is an estimate of Industry land positions compiled from public data. The information in this slide constitutes “analogous information”. See “Advisory Regarding Oil and Gas Information”.March 2020
Wembley to Kakwa Drilling Activity(1)Overall activity has
grown and continues to remain strong…
Pipestone poised for further growth
5
0
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600
800
1000
1200
1400
1600
0
250
500
750
1000
1250
1500
1750
2000P
rod
Wel
l Co
un
t
Cal
Day
Gas
Avg
(M
Mcf
/d)
Cal Gas Rate Prod Well Count
$50
$150
$250
$350
$450
2017A 2018A 2019A 2020E
Thoughtfully Measured & Self-Funded GrowthMaximum Shareholder Value Derives from Measured Growth to our 2021 Minimum
Volume Commitments… Followed by Flexibility to Flatten for FAFF Generation
March 2020
57.0
15
30
45
60
2017A 2018A 2019A 2020E
Capital Expenditure Outlook Range ($MM) Production Outlook Range (MBoe/d)
(1)Assumptions: Oil Price 2020: US$55/Bbl WTI; -US$4/Bbl C5+ DifferentialGas Price 2020: US$2.60/MMBtu NYMEX; C$1.90/GJ AECO; Fx: 2020: 1.32:1.0 C$:USD
(2)Adjusted Funds Flow and Free Annual Adjusted Funds Flow. See "Non-GAAP Measurements".
$100
$200
$300
2017A 2018A 2019A 2020E
Adjusted Funds Flow Outlook Range(1)(2) ($MM)
$315
29.8
$200
$345
$300
$265
40.0
2020 Adjusted Funds Flow Price Impact ($MM)
$302
+10-15% Prod/Share… Option to flatten out at ~68K Boe/d or continue
growth to ~110K Boe/d…
$300
$330
$266
$320
$290
61.0
6
0 20 40 60
+/- C$0.25/Mcf Corp. Gas Price
+/- US$5/Bbl WTI
+/- US$5/Bbl C5+ Dif
50.8
Given recent extreme commodity market volatility,
we are closely monitoring and will make capital reduction
decisions if needed later in Q2
57.0
15
30
45
60
75
90
2017A 2018A 2019A 2020E
Thoughtfully Measured & Self-Funded GrowthMaximum Shareholder Value Derives from Measured Growth to our Minimum Volume
Commitments… Subsequent Options for Material FAFF Generation or Continued Growth
March 2020
63.0
2021E 2022E 2023E
NuVista 5-Year Outlook – We Have Choices…
29.8
40.0
50.8
61.068.0
Building up to Minimum Volume Commitments Maximize FAFF GenerationContinue Growth Toward
110,000 Boe/d
Pro
du
ctio
n (
MB
oe
/d)
63.069.0
76.0
2021E 2022E 2023E
Free
Fu
nd
s Fl
ow ($MM) 2020E*
US$55/Bbl -$10
US$65/Bbl +$35
2021E 2022E 2023E
+$20 +$50 +$65
+$100 +$150 +$165
2021E 2022E 2023E
- - -
+$25 +$50 +$50
+10-15% Prod/Share… Option to flatten out at ~68K Boe/d or continue growth to ~110K Boe/d
68.0 68.0 68.0
78.0
90.0
Growth largely managed within Adjusted Funds
Flow
~$135 – ~$415 MM FAFF generated from 2021–23
7
US$55/Bbl WTI US$65/Bbl WTI
*Free Funds Flow calculated at mid point of guidance
(1)Assumptions: Oil Price: US$55/Bbl = US$55/Bbl WTI; -US$4/Bbl C5+ Differential; US$65/Bbl = US$65/Bbl WTI; -US$4/Bbl C5+ Differential;Gas Price: 2020: US$2.60/MMBtu NYMEX; C$1.90/GJ AECO; 2021-23: US$2.75/MMBtu NYMEX; C$1.95/GJ AECO; Fx: 1.32:1.0 C$:USD
(2)Adjusted Funds Flow and Free Annual Adjusted Funds Flow. See "Non-GAAP Measurements".
Oct-19 Nov-19 Jan-20 Mar-20 May-20 Jul-20 Sep-20 Nov-20 Jan-21
Bilbo Elmworth Gold Creek Pipestone South Pipestone North
RIG
1R
2R
3R
IG 4
RIG
5
2020 2021
March 2020
Capital Expenditure Highlights2020 FAFF Generation in Wapiti and Pipestone South Funds
Pipestone North Ramp-up
Internally Funding the PSN Ramp-up
2020 Capex Guidance$300 – $330MM
• Activity focused on development drilling in Wapiti (~12 wells) and Pipestone South (~6 wells) to maintain production at or above area MVC's
• Significant Pipestone North well and infrastructure build-out ahead of the scheduled Q4 2020 on-stream (~12 wells drilled in PSN)
• The Pipestone North compressor station capital is not included our Budget as we have mid-streamed the cost (NVA operates)
• Material flexibility to adjust pace of growth upwards or downwards in response to commodity prices
2020 Drilling Gantt Chart
8
Activity scheduled to provide flexibility while meeting or exceeding MVC's in each asset
Wapiti FAFF
Pipestone South FAFF
Pipestone North Initial
Ramp-up
~$125MM FAFF Generated in Wapiti &
PSS in 2020
~$120MM 2020 Capex to support PSN initial
on-stream
2020 Capital Detail
($MM)
Well Capital (DCET) $245
Water, Facilities/Pipelines & Maintenance
$45
Corporate & Other $10
Total ~$300 – $330
Building on Solid Foundation
Flexible Line-of-Sight to 68,000 or 110,000+ Boe/dPipestone Ramping up in 2019 & 2020
March 2020
Piestone• Pipestone South Compressor station
and pipeline On-Stream late-Q319
• Infrastructure agreements in place for late-2020 Pipestone North growth
• Forecast production ~35-40% condensate or 80-90 Bbls/MMcf
• Well Inventory for full field development to 60,000+ Boe/d
Pipestone – Phase 1 On-Stream
Elmworth
• Area production at capacity – Hi-Fi well results exhibiting step-change in economics
• Existing NVA owned compression and long-term firm service agreement for 100% of volumes
• Current production ~22% condensate
• 19,000+ Boe/d existing facility capacity and well inventory(1)
Elmworth – FAFF Generation
• SemCAMS Wapiti Gas Plant construction complete, on-Budget and ahead of schedule
• Maintaining volumes through 2020 with focus on optimization
• NVA footprint provides optionality in well length (ERH)
• Forecast production ~30% condensate
• 18,000 Boe/d expected facility capacity and well inventory(1)
Gold Creek – 2020+ FAFF Generation
• Area production at capacity – continuing to delineate the Lower Montney
• Existing NVA owned compression and long-term firm service agreement for 100% of volumes
• Current production ~40% condensate –driving robust free adjusted funds flow
• 18,000+ Boe/d existing facility capacity and well inventory(1)
Bilbo – FAFF Generation
(1) Well inventory is expected to be sufficient to produce at facility capacity for at least 10 years; refer to slide 10 for disclosure on reserves and resources location inventory. 9
Development Underpinned by Robust
Established and Emerging Inventory
March 2020 10
Montney 'A' Reserves & Resource Montney 'B' Reserves & Resource
(Gross) Bilbo West Bilbo Elmworth Gold Creek Pipestone Total NVA
NuVista Developed Wells 80 1 46 24 48 199
Undeveloped 2P Locations 78 4 75 75 144 376
Undeveloped 2C Locations 159 33 159 195 243 789
Total Wells + Locations 317 38 280 294 435 1,364
Montney Well and Location Count Breakdown
Montney 'C' Reserves & Resource
Montney Wells
Montney Lands
Montney A HZ Wells
Montney 2P Reserves
Montney 2C Resources
Montney Wells
Montney Lands
Montney B HZ Wells
Montney 2P Reserves
Montney 2C Resources
Montney Wells
Montney Lands
Montney C HZ Wells
Montney 2P Reserves
Montney 2C Resources
Montney 'D' Reserves & Resource
Montney Wells
Montney Lands
Montney D HZ Wells
Montney 2P Reserves
Montney 2C Resources
See "Advisory Regarding Oil and Gas Information"
NuVista PDP Reserves (MMBoe) NuVista TP+PA Reserves (MMBoe)
2019 Year-end Reserves Highlights
11
NuVista 2019 Year-end ReservesContinuing to Build on our Solid Foundation… Pipestone Now
a Material Component of NuVista's Overall Reserves
March 2020
• Solid growth in PDP and TP+PA reserves, a YoY increase of 13% to 95 MMBoe and 10% to 594 MMBoe, respectively
• Material growth in Pipestone South – Pipestone North and South growth to continue in 2020+
• PDP and TP+PA F&D costs of $10.26/Boe and $8.94/Boe
• Robust recycle ratios of 1.7x and 1.9x for PDP and TP+PA reserves
• 2019 reserves replacement ratio of 160% and 400% on a PDP and TP+PA basis – resulting TP+PA RLI of >27 years
• Montney TP+PA well count up 7% to 575 (gross)
• TP+PA reserve liquids weighting remains strong at 36%
0
20
40
60
80
100
120
2014 2015 2016 2017 2018 2019
Non-Montney Pipestone Gold Creek Elmworth Bilbo
0
100
200
300
400
500
600
700
2014 2015 2016 2017 2018 2019
Non-Montney Pipestone Gold Creek Elmworth Bilbo
See Advisory Regarding Reserve Disclosure
Emerging Light Oil Play at PipestoneRobust Industry Activity with Encouraging Well Results
March 2020 12
Charlie Lake Activity Map • The Charlie Lake (CLLK) is a carbonate reservoir with
interbedded anhydrite & clay beds
• Primary target has up to 25 MMBbls oil per section with multi-
layer development potential
• NVA holds 111,000 gross acres; large portions at high WI
(75+% WI)
• Reserves & Contingent Resource booked on 58% of NVA lands;
247 undeveloped locations assigned
• Infrastructure solution in place via NVA Wembley gathering
system and gas plant
NVA 13-18IP25: 386 Bbls/d
Oil
CLLK HZ and Vert Wells
NVA CLLK 2C Resources
New Licenses
CLLK Penetrations
NVA CLLK Lands
NVA 08-30 IP17: 458 Bbls/d
Oil
Charlie Lake Production vs. GLJ Type Curve
0
50
100
150
200
0 5 10 15 20 25 30
Cu
m O
il (M
Bb
ls)
Normalized Producing Month
CLLK Offset Wells GLJ Type Curve* Average
EUR: 363 Mboe (51% Oil)DCET Capital Cost:
$4.2MM
See Advisory Regarding Resource Disclosure *Represents the undeveloped CLLK locations as booked in the 2019YE GLJ Report
GLJ 2P Booking*
0
10
20
30
40
50
Jun-19 Jun-20 Jun-21 Jun-22 Jun-23
Pro
du
ctio
n C
apac
ity
(MB
oe/
d)
Pipestone North/ Wembley Base Pipestone South Growth Pipestone North Growth
Greater Pipestone Area Poised for Sustained Growth Driven by Focus on Value
Inventory & Infrastructure Plans in Place for ~45,000+ Boe/d
On-Stream
40 MMcf/d
PipestoneSouth (PSS)
PipestoneNorth (PSN)
+20 MMcf/d
On-Stream
50 MMcf/d +25 MMcf/d +25 MMcf/d
• Area continues to be a focus for growth despite challenging commodity prices
• Production set to triple by 2021 with over 400 MMcf/d of area processing capacity recently on-stream or under construction
• NVA growth plans in place for 160 MMcf/d in a low cost, condensate-rich area
• Pipestone South compressor station now online – bringing third pad on-stream in Q120
• Activities underway at Pipestone North to bring on 50 MMcf/d of capacity in Q420NVA Current
Condensate WeightingProjected Pipestone
Condensate Weighting
~30%35+%
HighlightsCondensate Driving Value
March 2020 13
First two pads now on
production
PSN Compressor Construction Underway
On-stream Q420
6-Well PadQ1 On-Stream
Compressor & Water
Infrastructure Complete
ECA/ CNRL Core Development
Area
First Two Pads now on
Production
PSN 12-well PadDrilling
0
1
2
3
4
5
6
0 10 20 30 40 50 60 70 80 90 100
2 Cu
m. R
eco
mb
ined
Gas
(b
cf)
Normalized Production Days
PSS 11 Wells Rich Type Curve
$0
$2
$4
$6
$8
$10
NVA HistoricalAverage
Pipestone South 3Well Pad Actual
Pipestone South 8Well Pad Actual
Pipestone South 6Well Pad Actual
Projected PipestoneSouth
1 DC
ET C
ost
($
MM
)
Drill & Complete Equip and Tie-In
Pipestone South Development BlockValue Enhancement Through Execution and Cost Reduction
Low Cost Development Area
• D&C costs ~30% lower than assets south of the river
• Realized technologically driven cost reduction
• Line of sight to additional 10% cost reduction
Strong Well Performance to-date
• Positive results from all layers in first 4 bench cube development test in the area – Avg. IP90 of 6.0 MMcf/d & 72 Bbls/MMcfCGR across all 4 layers
• Future zones to be high graded based on commodity price outlook
2019 Pads in Pipestone South Decreasing Costs in a High Value Development Area
8 Well Pad 4 Layers
3 Well Pad 2 Layers
1Projected Pipestone South DCET figures based on 2,200m lateral length. 2Production figures are scaled to 2,000m March 2020
Line of Sight to Additional
+10%
14
PSS 11 Well Aggregate Performance vs. Pipestone Rich Type Curve
Increased Hz length (+5%) and ProppantIntensity (+20%) vs.
8-well pad
6 Well Pad 3 Layers
Initial Well Performance ahead of
Expectations
0
5
10
15
20
25
30
35
40
45
Pro
du
ctio
n (
Mb
oe
d)
C5+ NGL's Sales Gas
March 2020
Wapiti Sales ProductionWapiti Activity (Bilbo, Elmworth & Gold Creek)
Wapiti Development AreaStable Production Base, Generating Free Adjusted Funds Flow
& Significant Remaining Inventory
Wapiti Op. Income Less Stay-Flat Capex at Midstream Take-or-Pay
This tornado chart is provided by NuVista for illustrative purposes and is based on a field capacity of 220 MMcf/d and the assumptions outlined within. See Advisory regarding "Non-GAAP Measurements"
Minimum Take-or-Pay Capacity
Stay Flat Capex Estimate
Op. Income Less Stay-Flat Capex at US$55/Bbl
<40,000 Boe/d
$175MM
$40MM
Established Base Production ~30% C5+ Weighting
Op. Income Less Stay-Flat Capex at US$65/Bbl
$100MM
15
NVA Montney New IP's
NVA In-Progress Wells
NVA Montney IP30
Montney Hz Wells
Q419/Q120 Activity Focused on Higher CGR area – IP360
CGR ~85 Bbls/MMcf
4-Well PadDrilling
H2 On-stream
2-Well PadCompleting
H1 On-stream
3-Well PadCompleting
H1 On-stream
4-Well PadIP90 exceeding
historical avg by 25% with 25% less capex
4-Well 3,000m+ Hz PadCompleting
H1 On-Stream
0.0
0.2
0.4
0.6
0.8
1.0
1.2
Ad
j. Fu
nd
s Fl
ow
($
MM
/Cap
ex $
MM
)
Bilbo Elmworth Gold Creek
Robust and Improving Wapiti Well EconomicsPipestone Results Anticipated to Drive Next Leg of Improvement
March 2020(1) Total well Drill, Complete ,Equip and Tie-in Capital / IP360 Sales Production(2) Revenue (assuming US$60/Bbl WTI; -US$2/Bbl C5+ Dif; $2.00/GJ AECO) less royalties, opex and transportation / Total well Drill, Complete , Equip & Tie-in Capital
His
tori
cal A
vg. C
apit
al E
ffic
ien
cy(1
)
His
tori
cal A
vg. F
irst
Yea
r C
apit
al R
etu
rned
(2)
High-Liquids Elm Wells
• Focus on execution and continuous improvement has translated into superior capital efficiency and returns across our Wapiti Development Blocks
• Through the application of these learnings and top-tier reservoir we anticipate Pipestone further improving our overall returns
Demonstrated Improvement Across All Development Blocks
16
$0
$5
$10
$15
$20
$25
($M
/Bo
e/d
)
Bilbo Elmworth Gold Creek
0
20,000
40,000
60,000
80,000
100,000
120,000
0
100
200
300
400
500
600
2017 2018 2019 2020 2021 2022 2023 2024
Mo
ntn
ey C
apac
ity
(Bo
e/d
)
Mo
ntn
ey R
aw G
as C
apac
ity
(MM
cf/d
)
Pipestone Expected Future Capacity Pipestone Secured Capacity Gold Creek Secured
Bilbo Secured Elmworth Secured Minimum Take-or-Pay
Three Clear Choices
March 2020
Well over 110,000 Boe/d Montney Well Inventory Potential
Market Egress PlanCapacity Secured – Near-Term 2021 Production Target of ~68,000 Boe/d with
Complete Optionality for Free Adjusted Funds Flow Generation or Growth Thereafter
Minimum Volume Commitment
Firm Capacity Secured Now
Capacity available to go and getonly if and when desired
17
0
100
200
300
400
500
600
700
800
900
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
Total Demand WCSB Production
March 2020
• Condensate is used in Alberta as a diluent to ship heavy oil on pipelines
• Condensate in Alberta is typically priced at a premium to crude oil but in the short term there can be some volatility
• Condensate must be transported to Alberta – "we're on the right end of the pipe"
• Long term, the premium for condensate should always reflect the cost of transportation to deliver to Alberta while demand outstrips local Canadian production
• Canadian condensate production growth has moderated
• Q4 2018 condensate price blowout was a one-time event driven by heavy oil pipelines becoming full
Western Canada Condensate Production & Imports (MB/d)
Condensate PricingStrong Demand and Premium Price for the Long-Term
Western Canada Condensate Supply and Demand (MB/d)
Sources: Peters & Co. Limited estimates, Government data, AER, geoSCOUT, and Company Reports.
FORECAST
18
100
200
300
400
500
600
700
800
Feb
-15
Ap
r-15
Jun
-15
Au
g-15
Oct
-15
Dec
-15
Feb
-16
Ap
r-16
Jun
-16
Au
g-16
Oct
-16
Dec
-16
Feb
-17
Ap
r-17
Jun
-17
Au
g-17
Oct
-17
Dec
-17
Feb
-18
Ap
r-18
Jun
-18
Au
g-18
Oct
-18
Dec
-18
Feb
-19
Ap
r-19
Jun
-19
Au
g-19
Oct
-19
Total Imports Condensate Production
Natural Gas Sales Points Q4 2019Diversification Reduces Risk
March 2020 19
1% 2%3%
3%
18%
4%
69%
Chicago Nat Gas Dawn Nat GasMalin Nat Gas AECO Nat GasNat Gas Hedges NGL'sCondensate
Net Revenue by Product & Gas Sales Point(1)
(1) Net Revenue = Revenue (includes realized gains/losses on financial derivatives) less transportation expenses
AECO
Chicago
Dawn
Henry Hub
$2.34
$3.23
$2.96
$3.30
Grande Prairie
* All prices in C$/mcf* Market Netback = Market Price less tolls (including fuel)* FX at C$/US$ at 1.3227* Based on Q419 average prices* Percentages reflect proportion of physical gas volumes delivered to the respective market in the period
Market Price
Market Netback
Malin
$3.51
$2.79$2.34
$1.86
March 2020 20
• NuVista has contracted for firm transportation on export pipelines to diversify pricing exposure
• We continue to evaluate future opportunities for diversification
• Ongoing rolling hedging program and financial basis hedges further diversify price exposure
Market Egress Plan In-PlaceNatural Gas Price Diversification
66%
46%
3%
22%
59% 56%
4% 7% 20% 21%
6%8%
7% 8%8%9%
9% 10%13% 8% 5% 5%
0%
25%
50%
75%
100%
2019 Q4 2020 2021 2022
Pct
. of
Fore
cast
Gas
Pro
du
ctio
n
Hedged NYMEX Floating Chicago Floating California Floating Dawn Floating AECO Floating
Natural Gas Price Diversification
ENVIRONMENTAL SOCIAL GOVERNANCE
Canada and Alberta have among themost stringent regulatoryrequirements in the world; theseensure the safe, responsible andtransparent development of ourhydrocarbon resources.
Our HSE Policy mandates ourcommitment to minimizing ourimpact on the environment.
We are continually seeking out andimplementing opportunities toreduce methane emissions andlower our carbon intensity – cut by>40% since 2012.
We are working with industry andstakeholders to find innovativeapproaches to reducing freshwateruse – RRR.
We remain focused on annualprogress in the abandonment andreclamation of inactive wells andfacilities.
Safety is our priority. Our HSE Policyoutlines our commitment to conductingour activities in a manner that protectsthe health and safety of our workers andthe public.
We believe in contributing to thecommunities in which we operate. Wemake substantial contributions to avariety of charities and First Nationsthrough employee volunteering,sponsorships and donations. In 2018,we donated over $380,000. We provideFirst Nations business opportunities.
We consult respectfully with FirstNations and local communities on everyproject including through the AboriginalConsultation Office of the Governmentof Alberta.
Our people drive our success. We offeran inclusive work environment where weembrace diversity of people, thinkingand ideas. Virtues like fair labor lawsand clean drinking water are "Givens" inCanada and in NuVista.
Sound corporate governance isfundamental to protecting the long-term interests of all stakeholders. In2018, we implemented a third partymaintained whistleblower site. Allstaff review & sign Code of EthicsPolicy annually.
We have an engaged, diverse andaccountable Board of Directors.Currently we have 1 woman on ourBoard with a stated objective of 20%membership by 2021.
Our Executive compensationprogram is aligned withshareholders’ interests – tied tosafety, environment, shareholderreturns, and corporate performance.We have a Say on Pay vote.
The World Needs More Canadian EnergyOur Industry's and NuVista's ESG is Tops
Just our Most Recent:
$13K Raised
March 2020
SOCIAL
21
Safety and Environment – Important aspects of ESG
NVA is proud… and Canada should be proud of its industry record
of corporate responsibility versus other countries
March 2020
NuVista GHG Reduction Projects
Total Recordable Injury Frequency Falling
Total Annual Greenhouse Emissions & Intensity are Way Down
Implemented Projects Under Consideration or Design Phase
Waste heat recovery units on compressors• 7 x $400k = $2.8MM• 1,000 tpa CO2 reduction per unit
Centralized instrument air for new pad-sites
Annual methane emissions reporting and fugitive emissions surveys being completed
Swap hi bleed for low bleed controllers plus tie some fields into flare (nil methane release)
5 solid oxide fuel cells deployed to pad-sites (nil methane release)
Tie chemical pumps to flare (nil methane release)
Low-Bleed pneumatic device conversion program
Solar Chemical Pumps
22
Acquisition of the
WembleyAssets
* North American Benchmark GHG Intensity (tCO2E/BOE): we have taken the weighted average of a relevant gas benchmark and a relevant oil benchmark to reflect our production (1/3 liquids, 2/3 natural gas). The two benchmarks that contribute to our NVA benchmark are identified below.
1. Average "production and upgrading" emissions for oil in USA refineries: ARC Energy Research Institute: Crude Oil Investing in a Carbon Constrained World: 2017 Update. October 2017 = 0.059 x 1/32. Average upstream emissions for Canadian shale gas: Natural Resources Canada, “Shale Gas Update for GHGenius”, August 2011, Prepared by S&T2 Consultants = 0.059 x 2/3
**2017 NVA + 3rd Party Midstream: 3rd party processing emissions added-in to provide an "apples to apples" comparison with benchmarks = 0.037
LMR Rating Excellent & Improving
71 Hectares of land was reclaimed in 2018,
equivalent to 135 NFL football fields
Managing Abandonment & Reclamation Liability
March 2020
NuVista Operating Results2019 and 2020 Guidance & Actuals Recap
Corporate Production (Boe/d)
Adjusted Funds flow
96%
$14.11
$18.17
$14.01 $12.54
$13.37
$0
$5
$10
$15
$20
$25
$0
$20
$40
$60
$80
$100
Q4 '18 Q1 '19 Q2 '19 Q3 '19 Q4 '19
($/B
OE)
($M
M)
Adjusted Funds Flow ($MM) Corporate Netback ($/Boe)
See Advisory regarding "Non-GAAP Measurements"
*Refer to our MD&A for the applicable period for a reconciliation to cash provided by operating activities
Actual Production (Boe/d)
Guidance (Boe/d)
Q4 2019 57,010 58,000 – 60,000
FY 2019 50,803 51,000 – 52,000
Q1 2020 n/a 50,000 – 54,000
Q2 2020 n/a 58,000 – 62,000
FY 2020 n/a 57,000 – 61,000
2019 FY Capex($MM)
2019 FY Capex Guidance Range
($MM)
2020 FY Capex Guidance Range
($MM)
$302 $300 – $325 $300 – $330
2019 FY Adjusted Funds Flow
($MM)
2019 FY Adjusted Funds Flow Guidance Range
($MM)
$266 ~$270
91% 95% 95%94% 96%
49,06043,839
50,391 51,819
57,010
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
Q4 '18 Q1 '19 Q2 '19 Q3 '19 Q4 '19
Wapiti Montney Other Properties
23
Why Buy NuVista Energy Stock?Value Creation Remains Top-Priority
March 2020
Best Address + Best Execution = Best Returns
Returns Inflection Point as we Grow into Pipestone, Cost Reductions & Technology Advancements
Energy Equity Valuations at Historic Lows
Adjusted Funds Flow and Production near Historic High – Balance Sheet Strong
Reliable Growth Path to 68,000 Boe/d then Option to Grow or FAFF
At 68,000 Boe/d, FAFF ~$150 – $450 million over 3 years at WTI US$55-65/Bbl
We have the Assets We have the Will We have the Team
We have the Strategy… To Deliver
24
Advisory Regarding Oil and Gas
Information
March 2020
ADVISORY REGARDING OIL AND GAS INFORMATION
Throughout this presentation the terms Boe (barrels of oil equivalent), MBoe (thousands of barrels of oil equivalent), MMBOE (millions of barrels of oil equivalent), Bcfe (billions of cubic feet ofgas equivalent) and Tcfe (trillion of cubic feet of gas equivalent). Such terms may be misleading, particularly if used in isolation. The conversion ratio of six thousand cubic feet per barrel (6 Mcf: 1Bbl) of natural gas to barrels of oil equivalent and the conversion ratio of 1 barrel per six thousand cubic feet (1 Bbl: 6 Mcf) of barrels of oil to natural gas equivalent is based on an energyequivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oilas compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Any references in this presentation to initial production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wellswill continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for NuVista. NuVista haspresented certain type curves and well economics for the Bilbo, Elmworth, Pipestone and Gold Creek development blocks. For each of the Bilbo, Elmworth and Gold Creek areas the type curvespresented are based on NuVista's historical production in the Bilbo, Elmworth and Gold Creek development blocks, in addition to production history from analogous Montney developmentslocated in close proximity to the Wapiti area. For the Pipestone development block the rich and very rich type curves and well economics presented are based partially on initial drilling results but,due to the early stage of development, primarily on drilling results from analogous Montney developments located in close proximity to such area.
Such type curves and well economics are useful in understanding management's assumptions of well performance in making investment decisions in relation to development drilling in theMontney area and for determining the success of the performance of development wells; however, such type curves and well economics are not necessarily determinative of the production ratesand performance of existing and future wells and such type curves do not reflect the type curves used by our independent qualified reserves evaluator in estimating our reserves volumes. Thetype curves used by GLJ Petroleum Consultants Ltd. ("GLJ") for NuVista's most recent independent reserves evaluation as of December 31, 2019 for the Bilbo, Elmworth, Gold Creek and Pipestonedevelopment blocks had a lower estimate of estimated ultimate recovery than the type curves presented herein; however, the production forecasts in such independent reserves evaluation arealso lower than NuVista's current production as well as the production forecasts prepared by management.
The type curves presented fall into several categories: (i) Historical Average; (ii) ERH; (iii) Hi-Fi; (iv) ERH +Hi-Fi; (v) Rich; and (vi) Very Rich. The expectations for each type curve differ as a result ofvarying horizontal well length, stage count and stage spacing. Historical Average is the average type curve achieved from the wells previously drilled by NuVista in the area. The ERH type curvesrepresents NuVista's expected type curve from drilling extended reach horizontal wells. The Hi-Fi type curves represents NuVista's expected type curve from utilizing high fracture intensitytechniques on wells and ERH + Hi-Fi type curves are the expected type curves from combining extended reach horizontal with high-fracture intensity. In addition, with respect to the Pipestonedevelopment block this presentation includes well performance and estimated ultimate recoverable volumes associated with a Rich and Very Rich type curves, which refers to wells that areexpected to have a high and very high relative content of condensate production, respectively. The type curves and well economics associated with Rich and Very-Rich wells have been risked bytaking a reduced expected resource recovery from increased horizontal length and frac intensity based on applicable actual well data and applying our planned well design.
NuVista is still in the early days of piloting extended reach horizontals and high intensity facture techniques and in the early stages of development in respect of the Pipestone development block.As such there is no certainty that such results will be achieved or that NuVista will be able to optimize such drilling results to achieve the optimized type curves, well economics and estimatedultimate recoverable volumes described. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented; however, thereis no certainty that NuVista will ultimately recover such volumes from the wells it drills.
25
Advisory Regarding Oil and Gas
Information
March 2020
ADVISORY REGARDING OIL AND GAS INFORMATION
In presenting such type curves, inputs and economics information and in this presentation generally, NuVista has used a number of oil and gas metrics which do not have standardized meaningsand therefore may be calculated differently from the metrics presented by other oil and gas companies. Such metrics include "DCET", "EUR", "NPV10", "NPVBT10", "payout", "rate of return","netback", "F&D", "capital efficiency", "recycle ratio", and "capital returned". DCET includes all capital spent to drill, complete, equip and tie-in a well. EUR represents the estimated ultimaterecovery of resources associated with the type curves presented. NPV 10 represents the anticipated net present value of the future net revenue discounted at a rate of 10% associated with thetype curves presented and NPVBT10 is NPV10 before tax. Payout means the anticipated years of production from a well required to fully pay for the DCET of such well. ROR means the rate ofreturn of a well or the discount rate required to arrive at a NPV equal to zero. Netback equals total revenues on a BOE basis (excluding realized commodity derivative gains/losses) less royalties,transportation and operating costs. F&D is the anticipated full exploration and development costs associated with each barrel of oil equivalent expected to be recovered from a well based on thetype curves and economics presented. Historical F&D is calculated based on exploration and development capital spent in a period plus the change in future development capital associated withthe Company's reserves divided by the reserves additions. Capital efficiency is a measure of expected development well capital divided by average first year production results (IP365) from suchwell based on the type curve presented. First year capital returned is revenue for a given well less royalties, opex and transportation divided by total well drill, complete, equip and tie-in capitalexpenditures. Recycle ratio is a measure of the netback achieved on a barrel of oil equivalent divided by the associated F&D costs for such barrel of oil equivalent.
This presentation discloses NuVista's drilling locations in two categories: (i) undeveloped 2P drilling locations; and (ii) undeveloped best estimate 2C drilling locations. Undeveloped 2P drillinglocations are derived from a report prepared by GLJ, NuVista's independent qualified reserves evaluator, evaluating NuVista's reserves as of December 31, 2019 (the "GLJ Report"), and accountfor undeveloped drilling locations that have associated proved and/or probable reserves, as applicable. Undeveloped 2C drilling locations are derived from a report prepared by GLJ evaluatingNuVista's contingent resources as of December 31, 2019 ("GLJ Contingent Resource Report"). There is no certainty that we will drill all drilling locations and if drilled there is no certainty that suchlocations will result in additional oil and gas production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonalrestrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. Contingent resources are those quantities of petroleumestimated, 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 tobe commercially recoverable due to one or more contingencies. In the case of the contingent resources estimated in the GLJ Contingent Resource Report, contingencies include: (i) furtherdelineation of interest lands; (ii) corporate commitment, and; (iii) final development plan. To further delineate interest lands additional wells must be drilled and tested to demonstratecommercial rates on the resource lands. Reserves are only assigned in close proximity to demonstrated productivity. As continued delineation drilling occurs, a portion of the contingentresources are expected to be reclassified as reserves. Confirmation of corporate intent to proceed with remaining capital expenditures within a reasonable timeframe is a requirement for theassessment of reserves. Finalization of a development plan including timing, infrastructure spending and the commitment of capital. Determination of productivity levels is generally requiredbefore the company can prepare firm development plans and commit required capital for the development of the contingent resources. There is uncertainty that it will be commercially viable toproduce any portion of the contingent resources.
Certain information in this presentation may constitute "analogous information" as defined in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities with respect to thecertain drilling results, total production in the Montney, number of wells drilled, or offset well production from other producers with operations that are in geographical proximity to or believedto be on-trend with NuVista's Montney assets. Management of NuVista believes the information may be relevant to help determine the expected results that NuVista may achieve withinNuVista's lands and such information has been presented to help demonstrate the basis for NuVista's business plans and strategies with respect to its Montney assets. There is no certainty thatthe results of the analogous information or inferred thereby will be achieved by NuVista and such information should not be construed as an estimate of future production levels, reserves or theactual characteristics and quality of NuVista's Montney assets.
26
Advisory Regarding Oil and Gas
Information
March 2020
ADVISORY REGARDING OIL AND GAS INFORMATION
The reserves estimates for 2019 presented herein have been evaluated by independent qualified reserves evaluator in accordance with NI 51- 101 and the Canadian Oil and Gas EvaluationHandbook ("COGE Handbook"), are effective December 31, 2019 and are based on an independent evaluation by GLJ using January 1, 2019 forecast pricing. The contingent resource drillinglocations are derived from the GLJ Contingent Resource Report. The reserves and resources presented herein have been categorized accordance with the reserves and resource definitions as setout in the COGE Handbook. The reserves estimates for prior years have also been evaluated on the same basis, are effective as of December 31 of the applicable year and are based on an
independent evaluation of GLJ using January 1 forecast pricing of the applicable year. The estimate of future net revenue of NuVista's reserves disclosed in this presentation do notrepresent fair market value. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future netrevenue for all properties, due to the effects of aggregation.
ECONOMIC INPUT ASSUMPTIONS
NuVista's type curve based on management's best estimatesCGR yield represents the equivalent constant yield for the full life of the wellPricing Assumptions: Fx (CAD:USD): 1.31:1 used in all pricing scenariosPrice case flat on a real basis; costs inflated at 2% per annumNGL's as % of WTI: C3 = 30%; C4 = 65%; C5+ = WTI -US$2/BblRecovered liquids unit transportation cost: C3/C4 = C$6/Bbl; C5+ = $7/BblGas price offset reflects NuVista's aggregate egress pipeline tolls and a $US0.95/MMBtu AECO to NYMEX basis
27
Advisory Regarding Non-GAAP Measurements
March 2020
NON-GAAP MEASUREMENTSWithin this presentation, references are made to terms commonly used in the oil and natural gas industry. Management uses “adjusted funds flow”, "free adjusted funds flow", "adjusted funds flow pershare", "net debt", "net debt to adjusted funds flow", "stay-flat capex estimate, "operating netback", and "corporate netback", to analyze performance and leverage. These terms do not have anystandardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities. These terms are used by management to analyze performance ona comparable basis with prior periods and to analyze the liquidity of NuVista.
Adjusted funds flowNuVista considers adjusted funds flow to be a key measure that provides a more complete understanding of the Company's ability to generate cash flow necessary to finance capital expenditures, expenditures on asset retirement obligations, and meet its financial obligations. NuVista has calculated adjusted funds flow based on cash flow provided by operating activities, excluding changes in non-cash working capital, asset retirement expenditures and environmental remediation recovery, as management believes the timing of collection, payment, and occurrence is variable and by excluding these items from the calculation, management is able to provide a more meaningful performance measure. More specifically, expenditures on asset retirement obligations may vary from period to period depending on the Company's capital programs and the maturity of its operating areas, while environmental remediation recovery relates to an incident that management doesn't expect to occur on a regular basis. The settlement of asset retirement obligations is managed through NuVista's capital budgeting process which considers its available adjusted funds flow. Adjusted funds flow as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, per the statement of cash flows, net earnings (loss) or other measures of financial performance calculated in accordance with GAAP. Adjusted funds flow per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of net earnings (loss) per share.
Free adjusted funds flowFree adjusted funds flow is forecast adjusted funds flow less stay-flat capex estimate.
Net debtNet debt is used by management to provide a more complete understanding of the Company's capital structure and provides a key measure to assess the Company's liquidity. NuVista has calculated net debt based on cash and cash equivalents, accounts receivable and prepaid expenses, asset under construction, accounts payable and accrued liabilities, long term debt (credit facility) and senior unsecured notes.
Operating netback and corporate netback ("netbacks")NuVista reports netbacks on a total dollar and per Boe basis. Operating netback is calculated as petroleum and natural gas revenues including realized financial derivative gains/losses, less royalties, transportation and operating expenses. Corporate netback is operating netback less general and administrative, deferred share units, and interest expense. Management feels these netbacks are key industry benchmarks and measures of performance for NuVista that provides investors with information that is commonly used by other petroleum and natural gas producers. The measurement on a Boe basis assists management and investors with evaluating NuVista’s operating performance on a comparable basis.
Operating income equals the total of revenues including realized financial derivative gains/losses less royalties, transportation and operating expenses.The operating netback, corporate netback and adjusted funds flow ($/Boe) assumptions used in this presentation to calculate estimated future adjusted funds flow are as follows:
*Net Revenues = Petroleum & Natural Gas Revenue +/- Realized Hedging Gain/Loss - Royalties
US$55/Bbl Case
$/Boe 2020 2021 2022 2023
Net revenues* $28.00 $28.00 $28.00 $28.00
Operating & Transport expenses $11.75 $12.00 $12.00 $12.00
G&A & Interest expenses $2.00 $2.00 $2.00 $2.00
Adjusted funds flow $14.25 $14.00 $14.00 $14.00
US$65/Bbl Case
$/Boe 2021 2022 2023
Net revenues* $31.50 $31.00 $31.00
Operating & Transport expenses $12.00 $12.00 $12.00
G&A & Interest expenses $1.75 $1.50 $1.50
Adjusted funds flow $17.75 $17.50 $17.50
28
March 2020
APPENDIX
29
Commodity Price Risk ManagementContinuing Rolling Hedging Program
March 2020 30Natural gas hedges include some NYMEX and Dawn hedges converted to an AECO equivalent price.
65.00
70.00
75.00
80.00
85.00
9,000
9,500
10,000
10,500
11,000
2020 Q1 2020 Q2 2020 Q3 2020 Q4
Pri
ce, C
$/B
bl
He
dge
d V
olu
me
, Bb
l/d
Bbl/d Capped Bbl/d Uncapped Avg. Floor Avg. Ceiling
0.00
0.75
1.50
2.25
3.00
3.75
4.50
0
25,000
50,000
75,000
100,000
125,000
150,000
2020 Q1 2020 Q2 2020 Q3 2020 Q4
Pri
ce, C
$/G
J
He
dge
d V
olu
me
, GJ/
d
GJ/d Capped GJ/d Uncapped Avg. Floor Avg. Ceiling
Floor C$ WTI price of $77.24/Bbl on ~57% of
2020 net production
Floor AECO price of $2.01/Mcf on ~46% of 2020 net production
Crude Oil Hedge Position
Natural Gas Hedge Position
From 2015 – 2019 NuVista's hedging program has
realized over $150MM in gains
Tidewater
Pipestone
SemCAMS
Pipestone
CSV
Albright
Keyera
Pipestone
NuVista
Wembley
Keyera
Wapiti #1 & #2
SemCAMS
Wapiti
Planned Gathering Lines (approx.)
Planned Gathering Lines
Now On-Stream
Multiple Existing and Future
Processing Options
March 2020
Existing Gas Plants
Future Gas Plants
SemCAMS Raw Gas Pipeline
Keyera Raw Gas and C5+ P/L
Existing Gas Plant
Proposed or Future Gas Plant
FacilityNuVista Ownership or Firm Capacity In
Place
NuVista Firm Downstream
Capacity
Excess Capacity Available
SemCAMS K3 X
Keyera Simonette X
NuVista Wembley X
SemCAMS Wapiti X
Veresen Hythe
Tidewater Pipestone X
Facility StatusNuVista Ownership
or Firm Capacity Contracted
Excess Capacity Available
Keyera Wapiti Plant#1
On-Stream X XKeyera Wapiti Plant
#2Constructing X
SemCAMS Pipestone Proposed X
CSV Albright Proposed X
Keyera Pipestone Constructing X
31
Future Gas Plants
Pipestone South
Pipestone North
ElmworthGold Creek Bilbo
Stratigraphy & Well PlacementReserves Booked in only 1-2 Layers Across our Lands…
Material Future Upside Remains
Lower Montney
B
C
D
Mid
dle
Mo
ntn
eyLo
we
r Mo
ntn
ey
5 % Gas Filled Porosity
Pipestone area has four well
developed zones
March 2020
Pipestone area has four well
developed zones
(1)Based on the GLJ Report.
NVA Wells on Block Industry Test Near Block Substantial Reserves Booked Across Block
32
0
25
50
75
100
125
150
0 2 4 6 8 10 12 14 16 18 20 22 24
Cu
m C
on
de
nsa
te o
r O
il P
rod
(M
Bb
l)
Normalized Flowing Time (months)
0
200
400
600
800
1000
1200
1400
0 2 4 6 8 10 12 14 16 18 20 22 24
Cu
mu
lati
ve G
as P
rod
uct
ion
(M
Mcf
)
Normalized Flowing Time (months)
Lower Montney Activity Update26 Wells and Counting…Encouraging Results from NVA, POU and VII
March 2020
Highlight Reel Lower Montney Well Gas Production
NuVista Lower Montney Well Condensate Production
NVA 11-18
NVA 2/9-10
POU 4-25 POU 1-7
SCL 6-20
SCL 9-27
26-Well Average
NVA 11-18
POU 01-07
SCL 09-27
SCL 06-20
NVA 2/09-10
POU 04-25
VII 14-26
VII 12-11
Recent NVA LwrMontney wells are performing above
area average
Robust liquids volumes after 12+ months
NVA 11-18
NVA 2/9-10
33
Bilbo Development BlockResults To-Date and Type Well Economics
March 2020
Hi-Fi Type Curve Economic Sensitivities
$55/Bbl $60/Bbl $65/Bbl
$1.75/GJ 1.3 1.0 0.9
$2.25/GJ 1.1 0.9 0.8
$2.75/GJ 0.9 0.8 0.7
0
1
10
0 1,000 2,000 3,000 4,000 5,000 6,000
Rat
e (
MM
cf/d
)
Cumulative Gas (MMcf)
Original Historical Average Hi-Fi
Type Curve Comparison Plot
Hi-Fi Type Curve Production
Raw Gas (Mcf/d)
C5+ (Bbl/d)
TotalSales
(Boe/d)
IP90 7,000 525 1,640
IP180 6,531 490 1,530
IP360 4,848 364 1,136
Hi-Fi Type Curve Inputs
DCET Capital ($MM) $8.6
EUR (Raw Gas) (Bcf) 5.0
EUR (MMBoe) 1.2
CGR (C5+ Bbls/MMcf) 75
Opex ($/Boe) $10.00
Horizontal Length (m) 2,000
Stage Count 40
WTI
AEC
O
Payout (Years)
$55/Bbl $60/Bbl $65/Bbl
$1.75/GJ 60% 80% 105%
$2.25/GJ 80% 100% 130%
$2.75/GJ 100% 130% 160%
WTI
AEC
O
Rate of Return (Pct.)
$55/Bbl $60/Bbl $65/Bbl
$1.75/GJ $5.0 $6.5 $7.9
$2.25/GJ $6.6 $8.0 $9.4
$2.75/GJ $8.1 $9.5 $10.8
WTIA
ECO
Net Present Value @ 10% ($MM)
* Refer to the "Advisory Regarding Oil and Gas Information" and "Economic Input Assumptions".* Pricing Assumptions: WTI (USD/Bbl); AECO (C$/GJ); Fx (CAD:USD): 1.31:1
34
Elmworth Development BlockResults To-Date and Type Well Economics
March 2020
Hi-Fi Type Curve Economic Sensitivities
$55/Bbl $60/Bbl $65/Bbl
$1.75/GJ 2.8 2.0 1.6
$2.25/GJ 1.8 1.4 1.2
$2.75/GJ 1.3 1.1 1.0
Type Curve Comparison Plot
Hi-Fi Type Curve Production
Raw Gas (Mcf/d)
C5+ (Bbl/d)
TotalSales
(Boe/d)
IP90 7,000 280 1,370
IP180 7,000 280 1,370
IP360 6,007 239 1,174
Hi-Fi Type Curve Inputs
DCET Capital ($MM) $8.4
EUR (Raw Gas) (Bcf) 7.0
EUR (MMBoe) 1.4
CGR (C5+ Bbls/MMcf) 40
Opex ($/Boe) $10.50
Horizontal Length (m) 2,000
Stage Count 40
WTI
AEC
O
Payout (Years)
$55/Bbl $60/Bbl $65/Bbl
$1.75/GJ 20% 30% 45%
$2.25/GJ 35% 50% 65%
$2.75/GJ 55% 70% 85%
WTI
AEC
O
Rate of Return (Pct.)
$55/Bbl $60/Bbl $65/Bbl
$1.75/GJ $1.6 $2.8 $3.9
$2.25/GJ $3.4 $4.5 $5.7
$2.75/GJ $5.1 $6.2 $7.3
WTIA
ECO
Net Present Value @ 10% ($MM)
0
1
10
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000
Rat
e (
MM
cf/d
)
Cumulative Gas (MMcf)
Original Historical Average Hi-Fi
35
* Refer to the "Advisory Regarding Oil and Gas Information" and "Economic Input Assumptions".* Pricing Assumptions: WTI (USD/Bbl); AECO (C$/GJ); Fx (CAD:USD): 1.31:1
Gold Creek Development BlockResults To-Date and Type Well Economics
March 2020
Hi-Fi Type Curve Economic Sensitivities
$55/Bbl $60/Bbl $65/Bbl
$1.75/GJ 1.8 1.4 1.1
$2.25/GJ 1.3 1.1 1.0
$2.75/GJ 1.1 1.0 0.9
Type Curve Comparison Plot
Hi-Fi Type Curve Production
Raw Gas (Mcf/d)
C5+ (Bbl/d)
TotalSales
(Boe/d)
IP90 7,000 420 1,545
IP180 7,000 420 1,545
IP360 5,684 341 1,254
Hi-Fi Type Curve Inputs
DCET Capital ($MM) $10.8
EUR (Raw Gas) (Bcf) 6.0
EUR (MMBoe) 1.3
CGR (C5+ Bbls/MMcf) 60
New GP Opex ($/Boe) $8.00
Horizontal Length (m) 3,000
Stage Count 60
WTI
AEC
O
Payout (Years)
$55/Bbl $60/Bbl $65/Bbl
$1.75/GJ 35% 50% 65%
$2.25/GJ 50% 65% 85%
$2.75/GJ 65% 80% 100%
WTI
AEC
O
Rate of Return (Pct.)
$55/Bbl $60/Bbl $65/Bbl
$1.75/GJ $3.8 $5.2 $6.6
$2.25/GJ $5.4 $6.8 $8.2
$2.75/GJ $7.0 $8.4 $9.7
WTIA
ECO
Net Present Value @ 10% ($MM)
0
1
10
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000
Rat
e (
MM
cf/d
)
Cumulative Gas (MMcf)
Historical Average ERH ERH + HiFi
36
* Refer to the "Advisory Regarding Oil and Gas Information" and "Economic Input Assumptions".* Pricing Assumptions: WTI (USD/Bbl); AECO (C$/GJ); Fx (CAD:USD): 1.31:1
Pipestone Development BlockRich Type Curves & Well Economics
March 2020
Type Curve Economic Sensitivities
WTI
$55/Bbl $60/Bbl $65/Bbl
AEC
O
$1.75/GJ 1.3 1.2 1.1
$2.25/GJ 1.1 1.0 0.9
$2.75/GJ 1.0 0.9 0.9
Payout (Years)
WTI
$55/Bbl $60/Bbl $65/Bbl
AEC
O
$1.75/GJ 65% 85% 105%
$2.25/GJ 90% 110% 135%
$2.75/GJ 115% 140% 165%
Rate of Return (Pct.)
WTI
$55/Bbl $60/Bbl $65/Bbl
AEC
O
$1.75/GJ $6.1 $7.5 $8.7
$2.25/GJ $8.2 $9.6 $10.8
$2.75/GJ $10.3 $11.6 $12.8
Net Present Value @ 10% ($MM)
37
0
1
10
0 1000 2000 3000 4000 5000 6000 7000 8000
Gas
Rat
e (M
Mcf
/d)
Cumulative Gas (MMcf)
Existing Wells (2,237m) Existing Wells Norn. (3,000m) Risked Type Curve
Type Curve Comparison Plot Type Curve Inputs
DCET Capital ($MM) $8.4
EUR (Raw Gas) (Bcf) 7.0
EUR (MMBoe) 1,380
CGR* (C5+ Bbls/MMcf) 80↓48
Opex ($/boe) $8.00
Hz Length (m) 3,000
Frac Intensity (T/m) 2.0
* Monthly CGR declines over first 6 months then flat
Initial rates restricted due to facility
constraints
Avg. Frac intensity only
1.2 T/m
* Existing Wells dataset is the average of 48 slick-water wells with an average frac intensity of 1.2 T/m
Only slick-water MNTN Hz's are included in the
dataset
* Refer to the "Advisory Regarding Oil and Gas Information" and "Economic Input Assumptions".* Pricing Assumptions: WTI (USD/Bbl); AECO (C$/GJ); Fx (CAD:USD): 1.31:1
Pipestone Development BlockVery-Rich Type Curves & Well Economics
March 2020
Type Curve Economic Sensitivities
WTI
$55/Bbl $60/Bbl $65/Bbl
AEC
O
$1.75/GJ 1.3 1.1 1.0
$2.25/GJ 1.2 1.0 0.9
$2.75/GJ 1.1 1.0 0.8
Payout (Years)
WTI
$55/Bbl $60/Bbl $65/Bbl
AEC
O
$1.75/GJ 80% 100% 125%
$2.25/GJ 90% 115% 145%
$2.75/GJ 105% 130% 160%
Rate of Return (Pct.)
WTI
$55/Bbl $60/Bbl $65/Bbl
AEC
O
$1.75/GJ $7.9 $9.4 $10.8
$2.25/GJ $8.2 $10.6 $12.0
$2.75/GJ $10.2 $11.7 $13.1
Net Present Value @ 10% ($MM)
38
0
1
10
0 1000 2000 3000 4000 5000
Gas
Rat
e (M
Mcf
/d)
Cumulative Gas (MMcf)
Existing Wells (2,719m) Existing Wells Norn. (3,000m) Risked Type Curve
Type Curve Comparison Plot Type Curve Inputs
DCET Capital ($MM) $8.4
EUR (Raw Gas) (Bcf) 4.5
EUR (MMBoe) 1,110
CGR* (C5+ Bbls/MMcf) 225↓89
Opex ($/boe) $6.00
Hz Length (m) 3,000
Frac Intensity (T/m) 2.0
* Existing Wells dataset is the average of 66 slick-water wells with an average frac intensity of 2.7 T/m
Only slick-water MNTN Hz's are included in the
dataset* Monthly CGR declines over first 6 months then flat
* Refer to the "Advisory Regarding Oil and Gas Information" and "Economic Input Assumptions".* Pricing Assumptions: WTI (USD/Bbl); AECO (C$/GJ); Fx (CAD:USD): 1.31:1