corporate presentation - nuvista energycorporate presentation november 2019 this presentation...

Corporate Presentation

November 2019

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; 2019 guidance with respect to average production, capital investment; 2019 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 2021-2022 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; 2019 through 2021 capital expenditures, production, adjusted funds flow and free adjusted funds flow; expectations that NuVista will experience measured self-funded growth; 2019 through 2021 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; 2019 capital expenditures, plans, allocation and expectations and the flexibility of NuVista's capital expenditure plans; 2019 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; 2019 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

November 2019 1

27% 50%75%

90%97%

97%97%

28%25%

17%

0

10

20

30

40

50

2013* 2014 2015 2016 2017 2018 2019E

Wapiti Montney Wapiti Sweet Other Pipestone Acquisition

Production (MBoe/d)

NuVista Snapshot

November 2019

TSX Trading Symbol: NVA

Market Capitalization: <$550 million

Basic Shares Outstanding: 225 million

Credit Facility Capacity: $500 million

Percent Drawn(1): 72%

Net Debt/Adjusted Funds Flow(2): 2.4x

NuVista Corporate Info

Grande Prairie

Edmonton

Calgary

NuVista Wapiti Montney Project

Non-Core Areas

1 Percent drawn at September 30, 2019 on $500MM facility 2 Q3 2019 Net Debt to annualized Q3 2109 Adjusted Funds Flow See "Non-GAAP Measurements" * Pro-forma 2013 Divestitures

2019 Guidance

Full Year Avg. Production (Boe/d) 51,000 – 52,000

Q4 19 Avg. Production (Boe/d) 58,000 – 60,000

Capital Investment ($MM) $300 – $310

2

Built-in Control and FlexibilityValue Creation Remains Top-Priority

November 2019

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

November 2019

• Pipestone South: Q4 2019 First Production – ON-STREAM Q3• 15,000 Boe/d facility startup, first stage is 10,000 Boe/d• 11 Wells on-stream – All 4 developable horizons tested at ~10+ MMcf/d and

average CGR of 95+ Bbls/MMcf• Per well costs ~30% below our historical average• Q1 2020 Performance Update Anticipated

• Pipestone North: 2020 Growth10 well pad – 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

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”.November 2019

NuVistaEncanaParamountSinopec-DaylightCNRLSeven GenerationsShellHuskyPipestone

Montney Licensesand Hz Wells

Wembley to Kakwa Drilling Activity(1)

0

50

100

150

200

250

300

350

2015 2016 2017 2018 H1 2019

We

lls S

pu

d

Wembley/Pipestone Wapiti/Kakwa Overall activity has grown and continues

to remain strong… Pipestone poised for

further growth

5

0

150

300

450

600

750

900

1050

1200

1350

0

200

400

600

800

1000

1200

1400

1600

1800P

rod

We

ll C

ou

nt

Cal

Day

Gas

Avg

(M

Mcf

/d)

Cal Gas Rate Prod Well Count

$50

$150

$250

$350

$450

2017A 2018A 2019E 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

November 2019

51.057.0

15

30

45

60

2017A 2018A 2019E 2020E

Capital Expenditure Outlook Range ($MM) Production Outlook Range (MBoe/d)

(1)Assumptions: Oil Price: US$55/Bbl = Q419-2020 US$55/Bbl WTI; -US$4/Bbl C5+ DifferentialGas Price: Q419-2020: US$2.60/MMBtu NYMEX; C$1.90/GJ AECO; Fx: Q419-2020: 1.32:1.0 C$:USD

(2)Adjusted Funds Flow and Free Annual Adjusted Funds Flow. See "Non-GAAP Measurements".

$100

$200

$300

2017A 2018A 2019E 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)

$31052.0

+10-15% Prod/Share… Option to flatten out at ~68K Boe/d or continue

growth to ~110K Boe/d…

$300

$330

$285$320

$275 $290

61.0

$300

6

0 20 40 60

+/- C$0.25/Mcf Corp. Gas Price

+/- US$5/Bbl WTI

+/- US$5/Bbl C5+ Dif

51.0

57.0

15

30

45

60

75

90

2017A 2018A 2019E 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

November 2019

63.0

2021E 2022E 2023E

NuVista 5-Year Outlook – We Have Choices…

29.8

40.0

52.0

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) 2019E* 2020E*

US$55/Bbl -$25 -$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 = Q419-2023 US$55/Bbl WTI; -US$4/Bbl C5+ Differential; US$65/Bbl = 2020-23 US$65/Bbl WTI; -US$4/Bbl C5+ Differential;Gas Price: Q419-20: US$2.60/MMBtu NYMEX; C$1.90/GJ AECO; 2021-23: US$2.75/MMBtu NYMEX; C$1.95/GJ AECO; Fx: 2019-2021: 1.32:1.0 C$: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

November 2019

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 (~10 wells drilled in PSN)

• The Pipestone North compressor station capital is not included our Budget as we have midstreamed 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) $245MM

Water, Facilities/Pipelines & Maintenance

$45MM

Corporate & Other $10MM

Total ~$300-$330MM

Building on Solid Foundation

Flexible Line-of-Sight to 68,000 or 110,000+ Boe/dPipestone Ramping up in 2019 & 2020

November 2019

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

November 2019

Montney 'A' Reserves & Resource Montney 'B' Reserves & Resource

(Gross) Bilbo West Bilbo Elmworth Gold Creek Pipestone South Pipestone North Total NVA

NuVista Developed Wells 74 1 43 18 3 29 168

Undeveloped 2P Locations 79 4 83 75 43 83 367

Undeveloped 2C Locations 164 45 155 198 42 194 798

Total Wells + Locations 317 50 281 291 88 306 1,333

Montney Well and Location Count Breakdown

See "Advisory Regarding Oil and Gas Information"

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 Wells

Montney Lands

Montney C HZ Wells

Montney 2P Reserves


Montney 'D' Reserves & Resource

Montney Wells

Montney Lands

Montney D HZ Wells

Montney 2P Reserves


Pipestone ~30% of Existing Inventory & Poised to Increase

10

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

First two pads now on

production

PSN Compressor Construction Underway

On-stream Q420

8-well Cube Dev. Test

Inventory & Infrastructure Plans in Place for ~45,000+ Boe/d

Compressor & Water

Infrastructure Complete

On-Stream

40 MMcf/d

PipestoneSouth (PSS)

PipestoneNorth (PSN)

+20 MMcf/d

On-Stream

50 MMcf/d +25 MMcf/d +25 MMcf/d

• Current production of ~200 MMcf/d from 3 area operators (NVA/ ECA/ CNRL)

• 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 under construction

• NVA growth plans in place for 160 MMcf/d by Q421 in a low cost, condensate-rich areaNVA Current

Condensate WeightingProjected Pipestone

Condensate Weighting

~30%35+%

HighlightsCondensate Driving Value

ECA/ CNRL Core Development

Area

November 2019 11

Pipestone South Development BlockValue Enhancement Through Execution and Cost Reduction

LOW

ERM

IDD

LEU

PP

ER

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 for next pad

Value Focused Cube Development

• Initial test results from 4 layer cube positive (10+ MMcf/d & 95 Bbls/MMcf CGR)

• Zones to be high graded based on commodity price outlook

• Well design and spacing optimization based on tech pad results already being realized

Continued Efficient and Reliable Execution

• First 8 well pad executed under budget and ahead of schedule

• PSS compressor station executed on budget and ahead of schedule

• Production on-stream in late-Q319

$0

$2

$4

$6

$8

$10

NVA Historical Average Pipestone South 3 WellPad Actual

Pipestone South 8 WellPad Actual

Projected PipestoneSouth

*DC

ET C

ost

($

MM

)

Drill & Complete Equip &Tie-In

8 Well Pad - 4 Layer Cube Pilot

2019 Pads in Pipestone South Decreasing Costs in a High Value Development Area

8 well, 4 layer cube dev. Test –On-stream

3 well, 2 layer pad –On-stream

New Compressor Station – On-

stream

*DCET figures based on 2,200m lateral length. Pipestone South wells completed at 2 T/mNovember 2019

Line of Sight to Additional

+10%

12

0

5

10

15

20

25

30

35

40

45

Pro

du

ctio

n (

Mb

oe

d)

C5+ NGL's Sales Gas

November 2019

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

NVA Montney New IP's

NVA In-Progress Wells

NVA Montney IP30

Montney Hz Wells

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"

Q419/Q120 Activity Focused on Higher CGR area – IP360

CGR ~85 Bbls/MMcf

4-Well PadIP60 in-line with historical avg. for ~35% less capex

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

13

4-Well PadIP30 420 Bbls/d C5+ (~200 Bbls/MMcf) for ~30% less

capex than hist. avg.

0.0

0.2

0.4

0.6

0.8

1.0

1.2

pre

-20

14

20

15

20

16

20

17

20

18

pre

-20

14

20

15

20

16

20

17

20

18

pre

-20

14

20

15

20

16

20

17

20

18

(Cas

h F

low

$M

M/C

apex

$M

M)

Bilbo Elmworth Gold Creek

Robust and Improving Wapiti Well EconomicsPipestone Results Anticipated to Drive Next Leg of Improvement

November 2019(1) Total well Drill, Complete ,Equip and Tie-in Capital / IP360 Sales Production(2) Revenue (assuming US$65/Bbl WTI; -US$4/Bbl C5+ Dif; $2.75/MMBtu NYMEX) 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

$0

$5

$10

$15

$20

$25

pre

-20

14

20

15

20

16

20

17

20

18

pre

-20

14

20

15

20

16

20

17

20

18

pre

-20

14

20

15

20

16

20

17

20

18

($M

/Bo

e/d

)

Bilbo Elmworth Gold Creek

• 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

14

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

November 2019

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

15

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

November 2019

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

16

November 2019

• 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 Canadian Condensate Production (MB/d)

Condensate PricingStrong Demand and Premium Price for the Long-Term

Western Canadian Condensate Supply and Demand (MB/d)

Sources: Peters & Co. Limited estimates, Government data (Note: March 2019 production data for B.C. is not available yet; March production shown for B.C. assumes a 2% increase MoM), AER, geoSCOUT, and Company Reports.

100

150

200

250

300

350

400

450

500

Ja

n-1

4

Apr-

14

Ju

l-14

Oct-

14

Ja

n-1

5

Apr-

15

Ju

l-15

Oct-

15

Ja

n-1

6

Apr-

16

Ju

l-16

Oct-

16

Ja

n-1

7

Apr-

17

Ju

l-17

Oct-

17

Ja

n-1

8

Apr-

18

Ju

l-18

Oct-

18

Ja

n-1

9

B.C. Alberta

0

50

100

150

200

250

300

350

400

450

500

550

600

650

700

750

800

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

20

21

Demand (Blending) Supply (WCSB Production) FORECAST

17

Natural Gas Sales Points Q3 2019Diversification Counts

November 2019 18

AECO

Chicago

Dawn

Henry Hub

$1.04

$2.68

$2.81

$2.94

Grande Prairie

* All prices in C$/mcf* Market Netback = Market Price less tolls (including fuel)* FX at C$/US$ at 1.3219* Based on Q319 average prices* Percentages reflect proportion of physical gas volumes delivered to the respective market in the period

Market Price

Market Netback

Malin

$2.61

$1.94$1.82

$1.77

1% 2%1% 2%

17%

2%

75%

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

November 2019 19

• 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

November 2019

SOCIAL

20

0

1

2

3

4

5

6

7

0

20

40

60

80

100

120

140

2012 2013 2014 2015 2016 2017 2018

Liab

ility

Man

agem

ent

Rat

ing

(LM

R)

An

nu

al W

ell C

ou

nt

Annual Reclamation Certificates Annual Well Abandonments

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

November 2019

Managing Abandonment and Reclamation Liability

NuVista GHG Reduction Projects

Total Recordable Injury Frequency Falling

Total Annual Greenhouse Emissions & Intensity are Way Down

LMR Rating Excellent & Improving

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

71 Hectares of land was reclaimed in 2018, equivalent to 135 NFL

football fields

21

Acquisition of the

WembleyAssets

November 2019

NuVista Operating Results2019 and 2020 Guidance & Actuals Recap

Corporate Production (Boe/d)

Adjusted Funds flow

96%

$19.69

$14.11

$18.17

$14.01 $12.54

$0

$5

$10

$15

$20

$25

$0

$20

$40

$60

$80

$100

Q3 '18 Q4 '18 Q1 '19 Q2 '19 Q3 '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)

Q1 '19 43,839 43,000 – 46,000

Q2 '19 50,391 48,000 – 51,000

Q3 '19 51,819 49,000 – 52,000

Q4 '19 n/a 58,000 – 60,000

FY 2019 n/a 51,000 – 52,000

FY 2020 n/a 57,000 – 61,000

Q3 2019 YTDCapex($MM)

2019 FY Capex Guidance Range

($MM)

2020 FY Capex Guidance Range

($MM)

$249 $300 – $310 $300 – $330

Q3 2019 YTD Adjusted Funds Flow

($MM)

2019 FY Adjusted Funds Flow Guidance Range

($MM)

$196 $275 – $285

99%91%

95%

95% 94%

40,080

49,060

43,839

50,391 51,819

-

10,000

20,000

30,000

40,000

50,000

60,000

Q3 '18 Q4 '18 Q1 '19 Q2 '19 Q3 '19

Wapiti Montney Other Properties

22

Why Buy NuVista Energy Stock?Value Creation Remains Top-Priority

November 2019

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

23

Advisory Regarding Oil and Gas

Information

November 2019

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, 2018 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.

24


Information

November 2019


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, 2018 (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, 2018 ("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.

25


Information

November 2019


The reserves estimates for 2018 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, 2018 and are based on an independent evaluation by GLJ using January 1, 2018 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 not represent

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 net revenue for allproperties, 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): 1.25:1 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/BblGas price offset reflects NuVista's aggregate egress pipeline tolls and a $US1.05/MMBtu AECO to NYMEX basisRecovered liquids unit transportation cost: C$6/Bbl

26

Slide 22 – Footnotes* 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

Advisory Regarding Non-GAAP Measurements

November 2019

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 any standardizedmeaning 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 on a comparablebasis 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 2019 2020 2021 2022 2023

Net revenues* $29.50 $28.00 $28.00 $28.00 $28.00

Operating & Transport expenses $12.25 $11.75 $12.00 $12.00 $12.00

G&A & Interest expenses $2.50 $2.00 $2.00 $2.00 $2.00

Adjusted funds flow $14.75 $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

27

November 2019

APPENDIX

28

Commodity Price Risk ManagementContinuing Rolling Hedging Program

November 2019 29Natural gas hedges include some NYMEX and Dawn hedges converted to an AECO equivalent price.

65.00

70.00

75.00

80.00

85.00

90.00

95.00

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2019 Q4 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

175,000

2019 Q4 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 $78.31/Bbl on ~70% of

2019 Q4 net production

Floor AECO price of $2.34/Mcf on ~66% of

2019 Q4 net production

Crude Oil Hedge Position

Natural Gas Hedge Position

Floor C$ WTI price of $77.24/Bbl on ~57% of

2020 net production

Floor AECO price of $1.98/Mcf on ~46% of 2020 net production

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

November 2019

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

#2Announced X

SemCAMS Pipestone Proposed X

CSV Albright Proposed X

Keyera Pipestone Constructing X

30

Future Gas Plants

0

15

30

45

60

75

90

2013 2014 2015 2016 2017 2018

Non-Montney Pipestone Gold Creek Elmworth Bilbo

November 2019

NuVista 2018 Year-end Reserves Solid Foundation…Pipestone Acquisition Lengthens the

Runway for Growth

• Record growth in PDP reserves and NPVBT10, a YoY increase of 55% to 84 MMBoe and 66% to $880MM

• Record increase in TP+PA reserves and NPVBT10, up 55% to 538 MMBoe and 92% to $3.4Bn

Material growth in our legacy assets and the addition of the Pipestone North assets

• PDP and TP+PA F&D costs of $14.90/Boe and $6.43/Boe

• Robust recycle ratios of 1.4x and 3.3x for PDP and TP+PA reserves

• Total Montney developed wells increased to 168 (gross)

• TP+PA well count up 40% to 535 (gross) Strong backstop to our 110,000+ Boe/d growth plan

NuVista PDP Reserves (MMBoe) NuVista TP+PA BTAX NPV10 ($MM)

2018 Year-end Reserve Highlights

See Advisory Regarding Reserve Disclosure

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

2013 2014 2015 2016 2017 2018

Non-Montney Pipestone Gold Creek Elmworth Bilbo

31

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

November 2019

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

0.0

0.5

1.0

1.5

2.0

Cas

h F

low

($

MM

) /

Cap

Ex (

$M

M)

Bilbo IP360 Capital Returned

IP360 Capital Returned 10-well Mov Avg Hi-FI Wells

Bilbo Development Block

First-Year Capital Efficiency & Capital ReturnedStrong Condensate Yields Driving Cash Generation

Bilbo First Year Capital Returned(2)Bilbo Capital Efficiency per Well(1)

Wells Sorted Chronologically by On-stream Date →

November 2019

2010 2019 Wells Sorted Chronologically by On-stream Date →2010 2019

(1) Total well Drill, Complete and Equip Capital / IP360 Sales Production(2) Revenue (assuming US$65/Bbl WTI; -US$4/Bbl C5+ Dif; $2.75/MMBtu NYMEX) less royalties, opex and transportation / Total well Drill, Complete and Equip Capital

Additions since last update

0%

10%

20%

30%

40%

50%

60%

70%

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Co

nd

en

sate

% (

Co

nd

bo

e/T

ota

l bo

e)

Cap

ital

Eff

icie

ncy

($

/To

tal

bo

e/d

)

Capital Efficiency ($/Total boe/d) 10-well Cap Eff Mov Avg

Hi-FI Wells 10-well Avg Cond %

33

Bilbo Development BlockResults To-Date and Type Well Economics

November 2019

Hi-Fi Type Curve Economic Sensitivities

$55/Bbl $60/Bbl $65/Bbl

$2.70/MMBtu 1.3 1.1 1.0

$3.10/MMBtu 1.1 1.0 0.9

$3.50/MMBtu 1.0 0.9 0.8

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

NY

MEX

Payout (Years)

$55/Bbl $60/Bbl $65/Bbl

$2.70/MMBtu 65% 85% 110%

$3.10/MMBtu 85% 110% 130%

$3.50/MMBtu 110% 135% 160%

WTI

NY

MEX

Rate of Return

$55/Bbl $60/Bbl $65/Bbl

$2.70/MMBtu $6.5 $7.9 $9.3

$3.10/MMBtu $8.0 $9.5 $10.8

$3.50/MMBtu $9.5 $11.0 $12.3

WTIN

YM

EX

Net Present Value @ 10% ($MM)

* Refer to the "Advisory Regarding Oil and Gas Information" and "Economic Input Assumptions".* Pricing Assumptions: WTI (USD/Bbl); NYMEX (USD/MMBtu); Fx (CAD:USD): 1.25:1

34

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

Cas

h F

low

($

MM

) /

Cap

Ex (

$M

M)

Elmworth IP360 Capital Returned

IP360 Capital Returned 10-well Mov Avg Hi-FI Wells

0%

5%

10%

15%

20%

25%

30%

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Co

nd

en

sate

% (

Co

nd

bo

e/T

ota

l bo

e)

Cap

ital

Eff

icie

ncy

($

/To

tal

bo

e/d

)

Capital Efficiency ($/Total boe/d) 10-well Cap Eff Mov Avg

Hi-FI Wells 10-well Avg Cond %

Elmworth Development Block

First-Year Capital Efficiency & Capital ReturnedImproving Capital Efficiencies Driving Payouts toward One Year

Elmworth First Year Capital Returned(2)Elmworth Capital Efficiency per Well(1)

November 2019

Wells Sorted Chronologically by On-stream Date →2010 2018 Wells Sorted Chronologically by On-stream Date →2010 2018

Hi-Fi wells results continue to drive capital returns at

Elmworth

Additions since last update

(1) Total well Drill, Complete and Equip Capital / IP360 Sales Production(2) Revenue (assuming US$65/Bbl WTI; -US$4/Bbl C5+ Dif; $2.75/MMBtu NYMEX) less royalties, opex and transportation / Total well Drill, Complete and Equip Capital 35

Elmworth Development BlockResults To-Date and Type Well Economics

November 2019


$55/Bbl $60/Bbl $65/Bbl

$2.70/MMBtu 2.4 1.9 1.5

$3.10/MMBtu 1.7 1.4 1.2

$3.50/MMBtu 1.3 1.2 1.1



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




EUR (MMBoe) 1.4


Opex ($/Boe) $10.50


Stage Count 40

WTI

NY

MEX

Payout (Years)

$55/Bbl $60/Bbl $65/Bbl

$2.70/MMBtu 30% 40% 50%

$3.10/MMBtu 40% 55% 65%

$3.50/MMBtu 60% 75% 90%

WTI

NY

MEX

Rate of Return (Pct.)

$55/Bbl $60/Bbl $65/Bbl

$2.70/MMBtu $2.6 $3.7 $4.8

$3.10/MMBtu $4.4 $5.5 $6.5

$3.50/MMBtu $6.1 $7.2 $8.2

WTIN

YM

EX


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

)


Original Historical Average Hi-Fi


36

Gold Creek Development BlockResults To-Date and Type Well Economics

November 2019


$55/Bbl $60/Bbl $65/Bbl

$2.70/MMBtu 1.8 1.4 1.2

$3.10/MMBtu 1.4 1.2 1.1

$3.50/MMBtu 1.2 1.1 1.0



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




EUR (MMBoe) 1.3


New GP Opex ($/Boe) $8.00


Stage Count 60

WTI

NY

MEX

Payout (Years)

$55/Bbl $60/Bbl $65/Bbl

$2.70/MMBtu 40% 50% 65%

$3.10/MMBtu 50% 65% 80%

$3.50/MMBtu 70% 80% 100%

WTI

NY

MEX

Rate of Return (Pct.)

$55/Bbl $60/Bbl $65/Bbl

$2.70/MMBtu $4.9 $6.3 $7.6

$3.10/MMBtu $6.5 $7.9 $9.2

$3.50/MMBtu $8.1 $9.4 $10.7

WTIN

YM

EX


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

)


Historical Average ERH ERH + HiFi


37

0

1

10

0 1000 2000 3000 4000 5000 6000 7000 8000

Gas

Rat

e (

MM

cf/d

)


Existing Wells (2207m) Existing Wells Norm. (3000m) Risked Type Curve

Pipestone Development BlockRich Type Curves & Well Economics

November 2019


Type Curve Economic Sensitivities

WTI

$60/Bbl $65/Bbl $70/Bbl

AEC

O

$1.50/GJ 1.3 1.1 1.0

$1.75/GJ 1.2 1.1 1.0

$2.00/GJ 1.1 1.0 0.9

Payout (Years)

WTI

$60/Bbl $65/Bbl $70/Bbl

AEC

O

$1.50/GJ 72% 89% 108%

$1.75/GJ 84% 102% 122%

$2.00/GJ 96% 115% 136%

Rate of Return

WTI

$60/Bbl $65/Bbl $70/Bbl

AEC

O

$1.50/GJ $6.7 $8.0 $9.2

$1.75/GJ $7.8 $9.1 $10.3

$2.00/GJ $8.9 $10.1 $11.3


Type Curve Inputs



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

1.1 T/m

* Existing Wells dataset is the average of 45 slick-water wells with an average frac intensity of 1.1 T/m

* Refer to the "Advisory Regarding Oil and Gas Information" and the advisory regarding "Economic Input Assumptions".

Only slick-water MNTN Hz's are included in the

dataset

38

Pipestone Development BlockVery-Rich Type Curves & Well Economics

November 2019


Type Curve Economic Sensitivities

WTI

$60/Bbl $65/Bbl $70/Bbl

AEC

O

$1.50/GJ 1.2 1.0 0.9

$1.75/GJ 1.1 1.0 0.9

$2.00/GJ 1.1 0.9 0.8

Payout (Years)

WTI

$60/Bbl $65/Bbl $70/Bbl

AEC

O

$1.50/GJ 91% 114% 140%

$1.75/GJ 98% 122% 148%

$2.00/GJ 104% 129% 156%

Rate of Return

WTI

$60/Bbl $65/Bbl $70/Bbl

AEC

O

$1.50/GJ $9.1 $10.5 $11.8

$1.75/GJ $9.7 $11.1 $12.4

$2.00/GJ $10.3 $11.7 $13.0


Type Curve Inputs



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

* Refer to the "Advisory Regarding Oil and Gas Information" and the advisory regarding "Economic Input Assumptions".

* Existing Wells dataset is the average of 23 slick-water wells with an average frac intensity of 2.1 T/m

0

1

10

0 1000 2000 3000 4000 5000

Gas

Rat

e (

MM

cf/d

)


Existing Wells (2721m) Existing Wells Norm. (3000m) Risked Type Curve

Only slick-water MNTN Hz's are included in the

dataset

Avg. Frac intensity 2.1 T/m

* Monthly CGR declines over first 6 months then flat

39

corporate presentation - nuvista energycorporate presentation november 2019 this presentation...

Documents