Corporate Presentation

August 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 the production growth required to meet future minimum volume commitments can be obtained 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; production, adjusted funds flow and free adjusted funds flow;; Montney well inventory potential; market egress plans, future production and expected future capacity and the timing thereof in NuVista's four main operating areas; NuVista's well and location inventories; 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; 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.

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

August 2020 1

27% 50%75%

90%97%

97%97%

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2013* 2014 2015 2016 2017 2018 2019

Wapiti Montney Wapiti Sweet Other Pipestone Acquisition

Production (MBoe/d)

NuVista Snapshot

August 2020

TSX Trading Symbol: NVA

Basic Shares Outstanding: 225.6 million

Credit Facility Capacity: $475 million

Percent Drawn(1): 90%

Net Debt/Adjusted Funds Flow(2): 3.2x

NuVista Corporate Info

Grande Prairie

Edmonton

Calgary

NuVista Wapiti Montney Project

Non-Core Areas

1 Percent drawn at June 30, 2020 on $475MM facility 2 Q2 2020 Net Debt to trailing twelve month Adjusted Funds Flow See "Non-GAAP Measurements" * Pro-forma 2013 Divestitures

Guidance 2020

Full Year Production (BOE/d) ~50,000

H220 Production (BOE/d) 48,000 – 50,000

Full Year Capital Investment ($MM) $165 – $175

H220 Capital Investment ($MM) $15 – $25

2

Flexibility, Financial Strength and Calm in the

Eye of the Storm… with Decisive Action

August 2020 3

What's Next? Minimize spending through H220 to maximize Free Adjusted Funds Flow generation. Liquidity and Balance Sheet strength are our paramount focus.

Dampening the Downside Condensate 70% Hedged* Gas 65% Hedged*

Decisive Move to Flexibility

Capex Scaled down for Remainder of Year

Free Adj. Funds Flow(net of Capex)

for H220

Financial Strength (Bank Line $475MM)

$429MM Drawn at End of 2Q20

Forecast Net Debt Reduction through to Year-

end

Support for Adjusted Funds Flow, Production &

Bank Line

15 New Wells On-Stream in March & April

Managing Production Level Through Turbulent Price

Environment

Opportunity to Observe Where Commodities

Stabilize

No Material Capital Spending Through Breakup

Significant Flexibility Post-Breakup

*H220 hedge position as a proportion of production guidance

Current Events at NVA…

August 2020

• Pipestone South: Q4 2019 First Production – ON-STREAM Q3 2019• 15,000 Boe/d facility startup, first stage is 10,000 Boe/d• Third pad (6 wells) now on-stream (late Q1) – IP30 in-line with previous wells• 17 Wells now on-stream – all 4 developable horizons tested

• Active Q419/Q120 Winter Drilling Season15 wells drilled & on-streamExecuted program for ~10% less than BudgetEncouraging initial performance in all areas

• Pipestone North Development On-track12 well pad drilled for record costs (45% less than 2019 avg.) – awaiting completion

• Facilities & Pipelines – progressing on-time & under budget

• NuVista Production• Well capability of over 60,000 Boe/d• To maximize economic value production levels restricted to +/- 50,000 Boe/d for now

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Wel

ls S

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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”.August 2020

Wembley to Kakwa Drilling Activity(1)Overall activity has

grown and continues to remain strong…

Pipestone poised for further growth

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August 2020

2020 Capital Program HighlightsManaging Capex to Match Adjusted Fund Flows

Material Spending Flexibility

6

Q120 Q220 Q320 Q420

Pipestone South(6-well pad)

Bilbo(2-well pad)

Gold Creek(3-well pad)

Elmworth(4-well pad)

Bilbo(2-well pad)

Pipestone North(12-well pad)

Capital reduced to only essential projects at the present time…

flexibility to complete 14 DUC's when commodity prices warrant

Operations Completed Drilled Uncompleted Wells Timing/Scope Optionality

2020 Montney Activity Schedule

Q1-Q220 YTD Q3-Q420 2020E

Capital Expenditures $149MM $15MM – $25MM$165 – 175

MM

2020 Corporate Outlook

H220 Capital Program and Production levels

will be re-evaluated on an ongoing basis

Building on Solid Foundation

Flexible Line-of-Sight to 68,000 or 90,000+ Boe/dPipestone Build-out Underway

August 2020

Piestone• Pipestone South compressor station and

pipeline online

• Pipestone North infrastructure buildout and first pad underway

• 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

• 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

• Existing NVA owned compression and long-term firm service agreement for 100% of volumes

• Current production ~40% condensate

• 18,000+ Boe/d existing facility capacity and well inventory(1)

Bilbo

(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. 7

Development Underpinned by Robust

Established and Emerging Inventory

August 2020 8

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"

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Pipestone North/ Wembley Base Pipestone South Growth Pipestone North Growth

Greater Pipestone Area Poised for Startup 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 value during challenging commodity prices

• Pipestone South compressor station now online – brought third pad on-stream in Q120

• Pipestone North:

• First 12 well pad drilled – awaiting completion

• Facility construction progressing on schedule & budgetNVA Current

Condensate WeightingProjected Pipestone

Condensate Weighting

~30%35+%

HighlightsCondensate Driving Value

August 2020 9

Compressor Construction Underway

Q420 Completion

6-Well PadQ1IP30

Compressor & Water

Infrastructure Complete

ECA/ CNRL Core Development

Area

First Three Pads now on

Production

12-well PadDrilled Uncompleted

H120 production ~17K Boe/d

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Normalized Production Days

PSS 11 Wells Rich Type Curve

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$4

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$10

NVA Historical Average Pipestone South First 11wells Actual

Pipestone South 6 WellPad Actual

Projected PipestoneSouth

1 DC

ET C

ost

($

MM

)

Drill & Complete Equip and Tie-In

Pipestone South Development BlockReducing Costs Through Execution

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

• Continued positive initial results as new 6-well pad avg. IP30 of 6.7 MMcf/d & 96 Bbls/MMcf CGR – inline with first 11 wells

• Future zones to be high graded based on commodity price outlook

Pipestone South Drilling Activity 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. 2Type-Curve Production figures are scaled down to 2,000m actuals from 3,000m August 2020

Line of Sight to Additional +10% savings

10

PSS 11 Well Aggregate Performance vs. Pipestone Rich Type Curve

Increased Hz length (+5%) and ProppantIntensity (+40%) vs.

first 11-wells

New 6 Well Pad

3 Layers

Initial Well Performance ahead of

Expectations

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C5+ NGL's Sales Gas

August 2020

Wapiti Sales ProductionWapiti Activity (Bilbo, Elmworth & Gold Creek)

Wapiti Development AreaStable Production Base & Significant Remaining Inventory

Focus on Value and Free Adjusted Funds Flow Generation

Established Base Production ~30% C5+ Weighting

11

NVA Montney New IP's

NVA In-Progress Wells

NVA Montney IP30

Montney Hz Wells

2-Well PadDrilled

Uncompleted

2-Well Pad Strong IP30

3-Well PadOn-stream

4-Well PadIP90 Exceeding

Historical avg by 25% with 25% Less Capex

• Bilbo • Moderating base decline; 2020 drilling was focused on

high-CGR areas

• Elmworth• Potential step-change in value proposition from ERH,

Hi-Fi and focus on higher CGR areas

• Gold Creek• Application of learnings & optimization showing

through

4-Well PadRestricted IP30 in-line

with Hist. avg; CGR's up to 90 Bbls/MMcf

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Pipestone Secured Capacity Gold Creek Secured Bilbo Secured Elmworth Secured Minimum Take-or-Pay

Three Clear Choices

August 2020

Well over 110,000 Boe/d Montney Well Inventory Potential

Market Egress PlanCapacity Secured – With Flexibility

Minimum Volume Commitment

Firm Capacity Secured Now

Capacity available to go and getonly if and when desired

12

Midstream MVC

Q220 Production

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Total Demand WCSB Production

August 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

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

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Total Imports Condensate Production

Natural Gas Sales Points Q2 2020Diversification Reduces Risk

August 2020 14

AECO

Chicago

Dawn

Henry Hub

$1.91

$2.27

$2.28

$2.40

Grande Prairie

* All prices in C$/mcf* Market Netback = Market Price less tolls (including fuel)* FX at C$/US$ at 1.3979* Based on Q220 average prices* Percentages reflect proportion of physical gas volumes delivered to the respective market in the period

Market Price

Market Netback

Malin

$2.13

$1.43$1.36

$1.23

1%0%2%

4%

26%

6%

61%

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

August 2020 15

• 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

Natural Gas Price Diversification

48%

15%

24%

32%

43%

10%

27%28%

7%

9% 11%

10%12% 13%

1%5% 5%

0%

25%

50%

75%

100%

2020 Q3-Q4 2021 2022

Pct

. of

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cast

Gas

Pro

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Hedged NYMEX Floating Chicago Floating California Floating Dawn Floating AECO Floating

Commodity Price Risk ManagementContinuing Rolling Hedging Program

August 2020 16Natural gas hedges include some NYMEX and Dawn hedges converted to an AECO equivalent price.

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GJ/d Capped GJ/d Uncapped Avg. Floor Avg. Ceiling

Floor C$ WTI price of $76.12/Bbl on 5,700 bbl/d

And Floating WTI + C$12.83/bbl on 4,250 bbl/d

for 2020 Q3-Q4

Crude Oil Hedge Position

Natural Gas Hedge Position

Floor AECO price of $1.95/Mcf on 96 Mmcf/d

for 2020 Q3-Q4

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

August 2020

SOCIAL

17

0.0350.031

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0.019 0.019 0.018 0.0200.022

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TOTAL INDIRECT GHG EMISSIONS TOTAL DIRECT GHG EMISSIONS

NVA OPERATIONS GHG INTENSITY (CO2e / BOE) 2017 Estimated GHG Intensisty (NVA + 3rd Party Midstream)**

Benchmark GHG Intensity*

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Annual Well Abandonments Annual Reclamation Certificates NuVista YE LMR (AER)

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

August 2020

NuVista GHG Reduction Projects

Total Recordable Injury Frequency (TRIF) Falling

Annual Greenhouse Gas Emissions Intensity Is Down

18

LMR Rating Excellent

63 Hectares of land was reclaimed in 2019, equivalent to 118 NFL

football fields

Managing Abandonment & Reclamation Liability

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Employee + Contractor TRIF (per 200K work hours)

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

Solar powered pad sites

Centralized instrument air for new pad sites

Tie remaining methane vents into flare

5 solid oxide fuel cells deployed to pad-sites (nil methane release)

Expand centralized instrument air toexisting pad sites

Low-Bleed pneumatic device conversion program

Vapor recovery

Est. GHG Intensity + 3rd Pty. Midstream**

Acquisition of the WembleyAssets (Q418)

* See Advisory for Emission sBenchmark calculation methodology

August 2020

NuVista Operating ResultsGuidance & Actuals Recap

Corporate Production (Boe/d)

Adjusted Funds flow

96%

$14.01 $12.54

$13.37

$10.73

$3.27

$0

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$10

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Q2 '19 Q3 '19 Q4 '19 Q1 '20 Q2 '20

($/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

Capex Guidance Range ($MM)

H220 $15 – $25 MM

FY2020 $165 – $175 MM

95% 95% 94% 96%96%

50,391 51,819

57,01052,080 50,922

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60,000

70,000

Q2 '19 Q3 '19 Q4 '19 Q1 '20 Q2 '20

Wapiti Montney Other Properties

19

Production Guidance Range (BOE/d)

H220 48,000 – 50,000

FY2020 ~50,000

Advisory Regarding Oil and Gas

Information

August 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.

20

Advisory Regarding Oil and Gas

Information

August 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.

21

Advisory Regarding Oil and Gas

Information

August 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

EMISSIONS BENCHMARK METHODOLOGY

North American Benchmark GHG Intensity (tCO2E/BOE): the weighted average of a relevant gas benchmark and a relevant oil benchmark to reflect NuVista's 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 1/3

2. 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

NuVista + 3rd Party Midstream: 2017 3rd party processing emissions added-in to provide an "apples to apples" comparison with benchmarks = 0.037

22

Advisory Regarding Non-GAAP Measurements

August 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

23

August 2020

APPENDIX

24

NuVista PDP Reserves (MMBoe) NuVista TP+PA Reserves (MMBoe)

2019 Year-end Reserves Highlights

25

NuVista 2019 Year-end ReservesContinuing to Build on our Solid Foundation… Pipestone Now

a Material Component of NuVista's Overall Reserves

August 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

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

August 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

26

$0

$5

$10

$15

$20

$25

($M

/Bo

e/d

)

Bilbo Elmworth Gold Creek

Tidewater

Pipestone

SemCAMS

Pipestone

CSV

Albright

Keyera

Pipestone

NuVista

Wembley

Keyera

Wapiti #1 & #2

SemCAMS

Wapiti

Planned Gathering Lines (approx.)Gathering Lines

Now On-Stream

Multiple Existing and Future

Processing Options

August 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

27

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

August 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

28

Emerging Light Oil Play at PipestoneRobust Industry Activity with Encouraging Well Results

August 2020 29

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) – manageable land expiry profile

• 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*