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Corporate Presentation February 2018

Presenter

Presentation Notes

Picture is of Ryan Roe, NVA Wapiti Contract Operator. Reports to Jade, Lead Operator

Advisory Regarding Forward-Looking Information and Statements

February 2018 1

This presentation contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “will”, “expects”, “believe”, “plans”, “potential” and similar expressions are intended to identify forward-looking statements or information. More particularly and without limitation, this presentation contains forward-looking statements and information concerning: NuVista's future strategy, focus and opportunities; 2017 and 2018 full-year production guidance (including mix of production from different areas); 2017 and 2018 full-year capital investment guidance; expectation of ability to grow production to 60,000 Boe/d; expectation of wellhead-to-market egress plans; expectation of firm egress for 100% of up to 60,000 Boe/d of production; expectation of 60% of revenue from condensate; expectation of facilities construction and the timing and capacity thereof; expectation that well inventory is expected to be sufficient to produce at facility capacity for at least 10 years; expected 2017 and 2018 funds from operations ranges and net debt to funds from operations ratios; expected expenditures associated with 2018 capital plans and ability to adjust such plans without impacting annual production; expected year-over-year production growth; NuVista's projected future drilling inventory; certain well economics and sensitivities associated with certain type curves; expected timing for additional drilling and initial production results; expected egress and processing plans for production from NuVista's development blocks; expectation that majority of development will not require compression infrastructure; intent to continue to evaluate future opportunities for diversification; and percentage of 2017 fourth quarter expected production hedged. 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. The forward-looking statements and information in this presentation are based on certain key expectations and assumptions made by NuVista, including prevailing commodity prices and exchange rates; applicable royalty rates and tax laws; future well production rates; reserve and resource volumes; the performance of existing wells; the success obtained in drilling new wells; the type curves and economics associated with current and future wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; continuing access to capital and debt markets; the availability and cost of labour and services; debt service requirements and operating costs and the receipt, in a timely manner, of regulatory and other required approvals. Although NuVista believes that the expectations and assumptions on which such forward-looking statements and information are based are reasonable, undue reliance should not be placed on the forward-looking statements and information because NuVista can give no assurance that they will prove to be correct. There is no certainty that NuVista will achieve commercially viable production from its undeveloped lands and prospects. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to the risks associated with the oil and gas industry in general such as: operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to reserves, production, well type curves and economics, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; marketing and transportation of petroleum and natural gas and loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to realize the anticipated benefits of acquisitions; ability to access sufficient capital from internal and external sources; stock market volatility; and changes in legislation, including but not limited to tax laws, royalty rates and environmental regulations. Management has included the above summary of assumptions and risks related to forward-looking statements in order to provide a more complete perspective on NuVista's future operations. Readers are cautioned that this information may not be appropriate for other purposes. The foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the operations or financial results of NuVista are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). This presentation also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about our prospective results of operations and funds from operations, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in above. 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 on FOFI and forward-looking statements. NuVista’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI and forward-looking statements, or if any of them do so, what benefits NuVista will derive therefrom. NuVista has included the FOFI and 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. The FOFI and forward-looking statements and information contained in this presentation are made as of the date hereof and NuVista undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

http://www.sedar.com/





NuVista Snapshot

February 2018 2

TSX Trading Symbol: NVA Market Capitalization: ~$1.5 billion Basic Shares Outstanding(2): 174.0 million Credit Facility Capacity(1): $310 million Percent Drawn(2): 45% Net Debt/Annualized Funds from Operations(2): 0.6x

2018 Guidance FY Average Production: 35,000 – 40,000 Boe/d FY Capital Investment: $270 – $310 million FY Funds from Operations(3): $210 – $240 million

NuVista Corporate Info

Grande Prairie

Edmonton

Calgary

NuVista Wapiti Montney Project

Non-Core Areas

1 As at Dec. 31, 2017 2 Dec 31, 2017 estimated net debt to Q417 Unaudited Annualized Funds from Operations. See "Non-GAAP Measurements". 3 2018 Pricing Assumptions: US$3.00/MMBtu NYMEX and US$55/Bbl WTI * Pro-forma 2013 Divestitures

Production (MBoe/d)

27% 50%

75% 90%

97% 99%

28% 25%

17%

0

10

20

30

40

2013* 2014 2015 2016 2017E 2018EWapiti Montney Wapiti Sweet Other

Why Buy NuVista? Trusted Repeatable Value Growth

February 2018 3

Pure-Play Montney Company – In The Right Neighborhood Balance Sheet Strength - Funded Growth Plan with Great Economics Clear Line-of-Sight to 60,000 Boe/d Inventory Underpinned by Four Established Development Blocks Wellhead-to-Market Egress Plan In-Place + Rolling Hedging Program 30%+ Condensate Production – Torque to Oil Price Proven Track Record of Execution & Continuous Improvement

Challenges with Canadian Energy? NVA Has Managed the Risk

February 2018 4

Can't get the oil out? Not enough gas egress? AECO Volatility? Can't get government permits? Need more facilities?

Alberta is the condensate market We have firm egress for 100% of our 60,000 Boe/d Plan 60-70% of revenue from condensate, strong hedging program and natural gas sales to all points North America Midstream plant to take us to 60,000 Boe/d already approved… … and under construction for 2019 startup

Challenge NuVista Solution

February 2018 5

• High level of industry activity continues

• > 900 Montney HZ wells licensed and/or drilled to date

• Montney gas production exceeding 1.0 Bcf/d

Elmworth to Kakwa Montney HZ Activity Update*

Elmworth to Kakwa Production Growth*

NuVista Encana Paramount Sinopec-Daylight CNRL Seven Generations Shell Montney Licenses and Hz Wells R6W6 R4W6 R2W6 R8W6

T65

T62

T67

T69

T70

T68

T66

T64

T63

R5W6 R3W6 R7W6

Montney – In The Right Neighborhood Condensate-Rich Montney Industry Growth Continues

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Prod

Wel

l Cou

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ay G

as A

vg (M

Mcf

/d)

Cal Gas Rate Prod Well Count

* 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”.

Funded Growth Plan Strong Growth with Managed Net Debt to Funds from Operations

February 2018 6

35.0

10

20

30

40

2015A 2016A 2017E 2018E

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

(1)Assumptions: 2018: US$55/Bbl WTI; US$3.00/MMBtu NYMEX; 1.25:1.0 C$:USD (2) Funds from Operations. See "Non-GAAP Measurements".

$100

$200

$300

$400

2015A 2016A 2017E 2018E

Funds from Operations Guidance Range(1)(2) ($MM)

$210

$50

$100

$150

$200

$250

2015A 2016A 2017E 2018E

$189

$273

22.4 24.6

$315

29.8

$125 $138

$200

0.0x

1.0x

2.0x

3.0x

2015A 2016A 2017E 2018E

$310

$270

$240

40.0

Net Debt/Annual Funds from Operations(1)(2)

February 2018 7

2018 Capex Range ($MM)

$160

$60

$85

2018 Capex Guidance: $270 – $310MM

Highlights:

• ~3-4 Active rigs in 2018 maintain production ahead of gas plant start-up • Significant flexibility in activity allows NVA to respond to prevailing

commodity prices and prudently manage the Balance Sheet • ~25-30% production growth YoY 2018 vs. 2017

2018 Production Guidance: 35,000 – 40,000 Boe/d

2018 Guidance Strong Year-over-Year Growth and Capital Flexibility

2018 Production Adds Activity

2019 Growth Activity Long Term Investment, Maintenance and Other

Flexibility to adjust ~$120M of 2018 capex without

impacting annual production

Flexibility to adjust capex without impacting 2018

production

*Long term investments include Pipestone long lead-time compression, water sourcing and disposal infrastructure, and science projects

Line-of-Sight to 60,000+ Boe/d Four Development Blocks Established

February 2018 8

Piestone • Four layer development potential in the

Montney • Initial type-curve 5.0 Bcf, 60+

Bbls/MMcf condensate (range 45 to 150+ Bbls/MMcf)

• First Well Successfully tested • Forecast production ~27% condensate • 10,000 Boe/d expected facility capacity

and well inventory(1)

Pipestone – Emerging Dev Block

Elmworth

• Hi-Fi Type-Curve 7.0 Bcf, 40 Bbls/MMcf condensate

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

• Current Production up to 16,000+ Boe/d with ~23% condensate

• 16,000+ Boe/d existing facility capacity and well inventory(1)

Elmworth – Free Cashflow Generation

• Hi-Fi Type-Curve 6.0 Bcf, 60 Bbls/MMcf

condensate (range 40 to 150+Bbls/MMcf)

• NVA footprint provides optionality in well length (ERH)

• Full Development into 2019 SemCAMS Wapiti Gas Plant

• Current Production ~4,000 boe/d • Forecast production ~27% condensate • 18,000 Boe/d expected facility capacity

and well inventory(1)

Gold Creek – On Production

• Hi-Fi Type-Curve 5.0 Bcf, 75 Bbls/MMcf

condensate • Existing NVA owned compression and

long-term firm service agreement for 100% of volumes

• Current Production ~18,000 Boe/d with over 1/3 condensate

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

Bilbo – Free Cashflow Generation

(1) Well inventory is expected to be sufficient to produce at facility capacity for at least 10 years; refer to slides 24 & 25 for our existing midstream capacity and licensed Wapiti area gas plants.

NuVista Montney Portfolio Increasing Rate-of-Change in Value

February 2018 9

Establishing Type-Curve Improving Type-Curve Maintenance

Pipestone

Gold Creek

Elmworth

Bilbo

Lower Montney

West Bilbo Valued on Potential

Valued on Production

DELINEATION EARLY DEVELOPMENT FULL DEVELOPMENT

February 2018 10

Inventory (Based on Zones Tested to date)

Pipestone (C) Elmworth (B&C) Gold Creek (B) Bilbo (B&C) Lower Montney Total NVA

NVA Producers 0 30 8 55 1 94

Remaining Inventory 40 120 115 130 Still establishing Type Curve 405

Pipestone

Gold Creek

Bilbo

Elmworth

24 Producers

6 Producers 8 Producers

Not Tested 5 Producers

50 Producers

Middle Montney 'D' Middle Montney 'C'

Middle Montney 'B' Lower Montney

Not Tested

NVA Test and

Offsetting Production

Multiple Industry Tests – Significant Future Potential

Tested

200m

+

Inventory Underpinned by Established Development Blocks

1 Producer

*Inventory only includes Montney intervals with current production or with direct offset production (i.e. Pipestone). Inventory represents NuVista's view of the development potential of each zone using current estimates for achievable well length. For comparison, year-end 2017 Proved Plus Probable locations (including producers) was 364. Certain information in this slide constitutes “analogous information”. See "Advisory Regarding Oil and Gas Information".

February 2018 11

NuVista Reserves Solid And Growing Underlying Reserves Foundation

• Significant growth in PDP reserves and NPVBT10, a YoY increase of 43% to 54 MMBoe and 36% to $530MM, respectively, which serves as a solid foundation for near-term production and cashflow generation

• TP+PA reserves and NPVBT10 increased materially YoY, up 35% to 347 MMBoe and 53% to $1.8Bn, respectively, a recognition of the inventory that backstops our growth plan to 60,000 Boe/d

• Robust PDP and TP+PA F&D at $11.35/Boe and $6.95/Boe – driven by positive technical revisions and continued improvement in our Montney development drilling

• Condensate now 27% of NuVista's PDP reserves (up from 25% last year)

• Total Montney PDP Wells increased to 96 (gross) – TP+PA well count (incl. PDP) now 379 (gross)

NuVista PDP Reserves (MMBoe) NuVista PDP NPVBT10 ($MM)

2017 Year-end Reserve Highlights

See Advisory Regarding Reserve Disclosure

0

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40

50

60

2012 2013 2014 2015 2016 2017

Non-Montney Bilbo Elmworth Gold Creek

$0

$100

$200

$300

$400

$500

$600

2012 2013 2014 2015 2016 2017

Non-Montney Bilbo Elmworth Gold Creek

NuVista Reserves 2017 Year-end Reserves Report

February 2018 12

Gross Montney Well and Location Count by Year

Montney 'C' Reserves* NuVista F&D Costs ($/Boe) Montney 'B' Reserves*

$0

$5

$10

$15

$20

$25

2014 2015 2016 2017

PDP F&D TP+PA F&D

(Gross) Bilbo Elmworth Gold Creek Pipestone Total NVA

Proved Developed 60 36 10 1 107

Undeveloped Locations 94 89 53 36 272

Total 154 125 63 37 379

Montney Well and Location Count Breakdown

See Advisory Regarding Reserve Disclosure

34 52 79 107

194 223

230

272

0

50

100

150

200

250

300

350

400

2014 2015 2016 2017

Undeveloped Locations Proved Developed Wells

228

275 309

379

* Refers to TP+PA Reserves

February 2018 13

R6W6

T65

South Montney Sales Production 56 Wells on Production (IP30)

Bilbo Well Performance

Bilbo Development Block Free-Cashflow Positive

NVA Montney New IP30's

NVA In-Progress Wells

Montney Horizontal Wells

NVA Compressor Site Connected to Keyera

Lower Montney IP30: 3.6 MMcf/d Raw Gas

665 Bbls/d C5+

2-well Pad – On Production Q1

2-well Pad x2 Drilling/Completing

0

2

4

6

8

10

12

14

16

18

20

Prod

uctio

n (M

boed

)

Sales Gas NGL's C5+

87

5 4

Cumulative-to-Date Bbls/MMcf

C5+

Butane

Propane

Raw Gas (Mcf/d)

C5+ (Bbl/d)

Total Sales

(Boe/d)

C5+ Yield (Bbl/

MMcf)

Well Count

IP30 6,037 749 1,655 124 56

IP60 5,445 626 1,447 115 54

IP90 4,998 552 1,307 110 54

IP180 4,389 414 1,086 94 48

IP360 3,344 280 796 84 37

0

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800

1,000

1,200

0

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1,000

1,500

2,000

2,500

3,000

Capi

tal C

osts

/ 1

00m

hz (

$)

Tota

l Sal

es (B

oe/d

)

On Production Year

Condensate (Bbl/d) Total Sales (Boe/d) 10-well Total Sales Mov. Avg. 10-well Capital Cost Mov. Avg. Hi-FI Wells

2017 2016 2015 2013 2014

2012

Bilbo Development Block Performance Update: Getting More for Less

February 2018 14

Bilbo IP90 Production and DCET Capital Cost

Bilbo NE 6-Well Pad 25% shorter hz length vs. Bilbo

2,000m avg. IP90 C5+ prod of 600 Bbl/d

10% above Bilbo avg.

Bilbo Development Block Results To-Date and Type Well Economics

February 2018 15

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

Rate

(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)

Total Sales

(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

NYM

EX

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

NYM

EX

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

WTI

NYM

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

Elmworth Development Block Significant New Results – Hi-Fi Coming Through

February 2018 16

North Montney Sales Production

Elmworth Well Performance

30 Wells on Production (IP30)



Montney Horizontal Wells

NVA Compressor Site Connected to SemCAMS

0

5

10

15

20

Prod

uctio

n (M

boed

)

Sales Gas NGL's C5+

43

9

9

Cumulative-to-Date Bbls/MMcf

C5+

Butane

Propane

Raw Gas (Mcf/d)

C5+ (Bbl/d)

Total Sales

(Boe/d)

C5+ Yield (Bbl/

MMcf)

Well Count

IP30 7,376 418 1,568 57 30

IP60 6,460 335 1,343 52 28

IP90 6,087 294 1,245 48 27

IP180 4,973 210 985 42 22

IP360 3,752 153 739 41 21

4-well pad Drilling Piloting 3T/m

completions and cemented Liners

Elmworth Development Block At a Tipping Point: Encouraging Recent Well Results

February 2018 17

Elmworth IP30 Production and DCET Capital Cost

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es (B

oe/d

)

On Production Year

Condensate (Bbl/d) Total Sales (Boe/d) 10-well Total Sales Mov. Avg. 10-well Capital Cost Mov. Avg. Hi-FI Wells

2014

2010 2017 2016 2015 2012 2013

Elmworth Development Block Results To-Date and Type Well Economics

February 2018 18


$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)

Total Sales

(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

NYM

EX

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

NYM

EX

Rate of Return

$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

WTI

NYM

EX


0

1

10

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

Rate

(MM

cf/d

)


Original Historical Average Hi-Fi


Gold Creek Development Block Initial Type-Curve Established – 2016-18 Early Development

February 2018 19

Gold Creek Highlights

• Up to 3 developable layers

• Condensate yield expected to average 60+ Bbls/MMcf (range 40 to 150+)

• Initial type-curve raw gas EUR average 4.0+ Bcf

• 8 existing producers – ~4 additional wells on-stream through 2018

• 2016-18 Early Development through Elmworth Compressor – Full-field Development into 2019 SemCAMS Wapiti Gas Plant

• Majority of development does not require additional compression infrastructure – Lower Opex

Gold Creek Geology

MN

TN 'C

' M

NTN

'B'

Low

er M

NTN

Gamma Porosity %

20 0

2019 SemCAMS

Wapiti Gas Plant

Activity and Infrastructure



Montney Hz Wells

Gold Creek IP30's

Raw Gas

(Mcf/d)

C5+ (Bbl/d)

Total Sales

(Boe/d)

C5+ Yield (Bbl/

MMcf)

First 5 Well Avg 5,040 408 1,174 81

06-13 Pad Avg 6,305 728 1,723 115

06-13 Hi-Fi + ERH Avg 6,857 863 1,946 126

Gold Creek Step-out Drilled & Tested

Q218 Tie-in

2-well Pad Drilling ERH + Hi-Fi

Gold Creek Development Block Results To-Date and Type Well Economics

February 2018 20


$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)

Total Sales

(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

NYM

EX

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

NYM

EX

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

WTI

NYM

EX


0

1

10

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

Rate

(MM

cf/d

)


Historical Average ERH ERH + HiFi


February 2018 21

Pipestone Highlights Pipestone Geology

• Up to 4 developable layers

• Acreage to the West extensively developed by EnCana

• Condensate yield expected to average 60+ Bbls/MMcf (Range of 45 to 150+)

• Type-curve raw gas EUR expected to average 5.0 Bcf (Range of 3.0 to 7.0 Bcf)

• NVA successfully tested first Pipestone well in 2017

• 2019-20 full-field development including compressor station and pipeline to new SemCAMS Wapiti plant

MN

TN 'C

' M

NTN

'D'

MN

TN 'B

' Lo

wer

MN

TN

Gamma Porosity 20 0

ECA Pipestone 'Super-Condensate'

ECA Pipestone Condensate-rich Development

Future NVA Compressor and Pipeline to SemCAMS

Wapiti Gas Plant

Pipestone Activity

*Map of activity at Pipestone is compiled from public data

CNOR 13-22 Hz Initial Test

278 Bbls/MMcf C5+

Pipestone Development Block Facilities in Planning Phase for 2019-20 Development

NVA 13-27 Hz Successful Test Final 24-hr rate: 6 MMcf/d Gas

>100 Bbls/MMcf C5+

Certain information in this slide constitutes “analogous information”. See "Advisory Regarding Oil and Gas Information".

Pipestone Development Block Robust Initial Type-Curve Economics

February 2018 22

Offsetting Well Production vs. NVA Type Well(1)

Pipestone Base Type Well Production Profile

Pipestone Dev. Type Curve Inputs and Economics

Half-Cycle Inputs Base Type Curve



EUR (MMBoe) 1.1


Opex ($/Boe) $10.00


Stage Count 25

Economics Base Type Curve

NPV10 ($MM) $7.5

PIR 1.1

Payout (Years) 1.2

ROR (%) 85%

Netback ($/Boe) $22.00

F+D ($/Boe) $6.50

Cap. Efficiency ($/Boed) $8,000

0

300

600

900

1,200

1,500

1,800

0 6 12 18 24

Sale

s Pro

duct

ion

(Boe

/d)

Time (Months)

Pipestone TC Total Prod

Pipestone TC Condensate Prod

Offsetting wells restricted by operator to ~3-4 MMcf/d

* Refer to the "Advisory Regarding Oil and Gas Information" and "Economic Input Assumptions". * Pricing Assumptions: WTI (USD/Bbl): $60.00; NYMEX (USD/MMBtu): $3.10; Fx (CAD:USD): 1.25:1

Source: GeoSCOUT

Certain information in this slide constitutes “analogous information”. See "Advisory Regarding Oil and Gas Information".

0

10

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30

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50

60

$0

$100

$200

$300

$400

$500

$600

2013 2014 2015 2016 2017E 2018E

Num

ber o

f Sta

ges

($00

0)

Cost per Stage No. of Stages

$0

$2

$4

$6

$8

$10

$12

$14

2013 2014 2015 2016 2017E 2018E

($M

M)

0

1,000

2,000

3,000

4,000

5,000

6,0000 5 10 15 20 25 30 35

2013 2014 2015 2016 2017

Proven Track Record of Execution Improving Efficiency and Well Costs

February 2018 23

Average Annual Montney Drilling Curves Montney Well Cost (DCET) By Year

• Executed a Gold Creek 3 well pad with 164 stages: longest well was drilled to 3,850m lateral length (6,700m MD) and a 71 stage completion

• Elmworth in 2017 drilled and completed 9 wells (5 Hi-Fi) for ~$215k/stage

• Successful transition to plug & perf – 12 wells completed with over 40 stages

• For 2017 Plan, assumed some service cost pressures would continue offset by continued annual efficiency gains

• Well designs continue to evolve longer, more frac stages, more production with less cost per stage

Montney Drilling & Completion Cost per Stage Operational Highlights

Dept

h (m

)

Wellhead-to-Market Egress Plan In-Place Firm Egress Counts: Long-Term Growth Secured

February 2018 24

CNRL Gold Creek Plant

Keyera Simonette Plant

SemCAMS K3 Plant

SemCAMS Raw Gas Pipeline

Keyera Raw Gas and C5+ P/L

Alliance Sales Line

TCPL Sales Line

Grande Prairie SemCAMS Wapiti Sour Gas Plant Status: Under Construction – 2019 Startup

Raw Gas Capacity: 200 MMcf/d Condensate Capacity: 20,000 Bbl/d

Keyera Wapiti Sour Gas Plant Status: Under Construction


NuVista North Compressor Station (50% WI)

Gross Raw Gas Capacity: 35 MMcf/d

NuVista Elmworth Compressor Station (100% WI)


NuVista Bilbo Compressor Station (100% WI)


0

10,000

20,000

30,000

40,000

50,000

60,000

0

50

100

150

200

250

300

2014 2015 2016 2017 2018 2019 2020 2021

Mon

tney

Cap

acity

(Boe

/d)

Mon

tney

Raw

Gas

Cap

acity

(MM

cf/d

)

Min. Midstream TOP Commitment Downstream Firm Gas Service

February 2018 25

TOP = NuVista Minimum take-or-pay volume commitment Downstream Firm Gas Service includes priority interruptible service

Elmworth

Bilbo

Gold Creek

Pipestone

60,000+ Boe/d Montney Processing Capacity Secured

Market Egress Plan In-Place Wapiti Montney Processing Capacity…Material Running Room

February 2018 26

• 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-Place Natural Gas Price Diversification

62%

10%

20%

7%

10%

12%

13%

18%

27%

1%

20%

0%

25%

50%

75%

100%

2018 2019

Pct.

of F

orec

ast G

as P

rodu

ctio

n

Hedged NYMEX Floating Chicago Floating California Floating Dawn Floating AECO Floating

Natural Gas Price Diversification

Above percentages are based on the mid-point of NuVista current production guidance.

Commodity Price Risk Management Continuing Rolling Hedging Program

February 2018 27 Natural gas hedges include some NYMEX and Dawn hedges converted to an AECO equivalent price.

50.00

52.50

55.00

57.50

60.00

62.50

65.00

67.50

70.00

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2018 Q1 2018 Q2 2018 Q3 2018 Q4 2019 Q1 2019 Q2 2019 Q3 2019 Q4

Pric

e, C

$/Bb

l

Hedg

ed V

olum

e, B

bl/d

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

0.75

1.50

2.25

3.00

3.75

25,000

50,000

75,000

100,000

125,000

2018 Q1 2018 Q2 2018 Q3 2018 Q4 2019 Q1 2019 Q2 2019 Q3 2019 Q4

Pric

e, C

$/G

J

Hedg

ed V

olum

e, G

J/d

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

Floor C$ WTI price of $69.57/Bbl on ~65% of

2018 net production

Floor AECO price of $2.70/Mcf on ~62% of 2018 net production

Crude Oil Hedge Position

Natural Gas Hedge Position

Natural Gas Sales Points Q4 2017 Diversification Counts

February 2018 28

AECO

Chicago

Dawn

Henry Hub

$1.96

$3.70

$3.75

$3.73

Grande Prairie

• All prices in C$/mcf • Market Netback = Market Price less tolls (including fuel) • FX at C$/US$ at 1.2701 • Based on Q417 average prices • *NVA service commences early-mid 2018

Market Price

Market Netback

Malin* $3.34

$2.66 $2.85

$2.69

February 2018 29

NuVista Operating Results 2017 Guidance Delivered

Corporate Production (Boe/d)

Corporate Funds from Operations

96% 96% 96% 97%

98%

99%

24,716 26,731 25,454

29,405

37,400

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

Q4 '16 Q1 '17 Q2 '17 Q3 '17 Q4 '17E

Wapiti Montney Other Properties

$17.90 $17.98 $16.98 $15.36

$22.06

$0

$5

$10

$15

$20

$25

$0

$20

$40

$60

$80

Q4 '16 Q1 '17 Q2 '17 Q3 '17 Q4 '17E

($/B

OE)

($M

M)

Funds from Operations ($MM) Funds from Operations ($/Boe)

Actual Production (Boe/d)

Guidance (Boe/d)

Q1 '17 26,731 26,000 – 29,000

Q2 '17 25,454 22,500 – 25,000

Q3 '17 29,405 26,000 – 29,000

Q4 '17E 37,400 35,000 – 38,000

FY2017E 29,800 28,000 – 31,000

2017E FY Capex ($MM)

2017 Capex Guidance Range ($MM)

$315 $280-$300

2017E FY Funds from Operations

($MM)

2017 Funds from Operations Guidance

Range ($MM)

$200 $160-$180

NuVista Looking Forward Flexibility and Strength …Growth in a Volatile Environment

February 2018 30

Pure-Play Montney Company – In The Right Neighborhood Balance Sheet Strength – Funded Growth Plan with Great Economics Clear Line-of-Sight to 60,000 Boe/d Inventory Underpinned by Four Established Development Blocks Wellhead-to-Market Egress Plan In-Place + Rolling Hedge Program 30%+ Condensate Production – Torque to Oil Price Proven Track Record of Execution & Continuous Improvement

We have the Assets We have the Will We have the Team We have the Strategy… To Deliver

Advisory Regarding Oil and Gas Information

February 2018 31

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 of gas 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: 1 Bbl) 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 energy equivalency 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 oil as 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 wells will 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 has presented certain type curves and well economics for the Bilbo, Elmworth, Pipestone and Gold Creek development blocks. For each of the Bilbo and Elmworth areas the type curves presented are based on NuVista's historical production in the Bilbo and Elmworth development blocks, in addition to production history from analogous Montney developments located in close proximity to the Wapiti area. For each of the Gold Creek and Pipestone development blocks the type curves presented are based primarily on drilling results from analogous Montney developments located in close proximity to such areas as such development blocks are still in the early stages of development. 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 the Montney 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 rates and 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. The type curves used by GLJ for NuVista's most recent independent reserves evaluation as of December 31, 2017 for the Bilbo, Elmworth, Pipestone and Gold Creek development blocks had a lower estimate of estimated ultimate recovery than the type curves presented herein; however, the production forecasts in such independent reserves evaluation are also lower than NuVista's current production as well as the production forecasts prepared by management. The type curves presented fall into several categories: (i) Base (or Initial); (ii) Historical Average; (iii) ERH; (iv) Hi-Fi; and (v) ERH +Hi-Fi; the expectations for each type curve differ as a result of varying horizontal well length, stage count and stage spacing. The Base or Initial type curve represents the average type curve expected. Historical Average is the average type curve achieved from the wells previously drilled by NuVista in the area. The ERH type curves represents 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 intensity techniques on wells and ERH + Hi-Fi type curves are the expected type curves from combining extended reach horizontal with high-fracture intensity. NuVista is still in the early days of piloting extended reach horizontals and high intensity facture techniques and as such there is no certainty that such results will be achieved or that NuVista will be to optimize such drilling results to achieve the optimized type curves described. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented; however, there is no certainty that NuVista will ultimately recover such volumes from the wells it drills. In presenting such type curves, inputs and economics information, NuVista has used a number of oil and gas metrics which do not have standardized meanings and therefore may be calculated differently from the metrics presented by other oil and gas companies. Such metrics include DCET, "EUR", "NPV10", "PIR", "payout", "rate of return" (or "ROR"), "netback", "F&D", "capital efficiency", "recycle ratio" and "reserves life index". Development well capital includes all capital spent to drill, complete, equip and tie-in a well. EUR represents the estimated ultimate recovery 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 the type curves presented. PIR (Profit to Investment Ratio) is the ratio of the NPV 10 relative to the DCET. Payout means the anticipated years of production from a well required to fully pay for the DCET of such well. ROR means the rate of return 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 the type 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 with the 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 such well based on the type curve presented. 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. Reserves life is a measure of the volume of the Company's reserves divided by the annual average production.

Advisory Regarding Oil and Gas Information

February 2018 32

ADVISORY REGARDING OIL AND GAS INFORMATION This presentation discloses NuVista's drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the GLJ Reserves Report and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 405 net drilling locations identified herein, 135 net are proved locations, 123 net are probable locations and 147 net are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves or production. 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 the certain 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 believed to 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 within NuVista'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 that the 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 the actual characteristics and quality of NuVista's Montney assets. It should not be assumed that the future net revenues (NPV10) included in this presentation represent the fair market value of the reserves. 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 all properties due to the effects of aggregation.

Advisory Regarding Non-GAAP Measurements, Reserves Disclosure & Economic Assumptions

February 2018 33

NON-GAAP MEASUREMENTS Within this presentation, references are made to terms commonly used in the oil and natural gas industry. Management uses funds flow from operations, net debt to annualized funds from operations and netback to analyze operating performance and leverage. These terms as presented, do not have any standardized meaning prescribed by GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. All references to funds from operations throughout this presentation are based on funds flow from operating activities before changes in non-cash working capital, environmental remediation expenses, note receivable allowance (recovery) and asset retirement expenditures. Netbacks equals total revenues excluding realized commodity derivative gains/losses less royalties, transportation and operating costs. Net debt is calculated as long-term debt plus senior unsecured notes plus current assets less current liabilities and excludes the current portions of the commodity derivative asset or liability. For a reconciliation of these non-GAAP measures with the most directly comparable GAAP measure, please see NuVista's management's discussion and analysis for the year ended December 31, 2016 and three months ended September 30, 2017. This presentation contains preliminary estimates of fourth quarter and 2017 annual funds from operations and funds from operations netback, as well as 2017 net debt and net debt to annualized fourth quarter funds from operations and net debt to 2017 annual funds from operations. Readers are cautioned that these are estimates based on preliminary financial results, which have not yet been finalized or, in the case of annual results, audited and, as such, these estimates could change and a reconciliation to their mostly directly comparable GAAP measure is not available. RESERVES DISCLOSURE The reserves estimates prepared herein have been evaluated by an independent qualified reserves evaluator in accordance with NI 51-101 and the COGE Handbook and is effective December 31, 2017 and is based on an independent evaluation by GLJ using January 1, 2018 forecast pricing. The reserves have been categorized accordance with the reserves and resource definitions as set out in the COGE Handbook, which are set out below: Reserves are estimated remaining quantities of petroleum anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be sub-classified based on development and production status. Proved Reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. Probable Reserves are those additional quantities of petroleum that are less certain to be recovered than Proved Reserves, but which, together with Proved Reserves, are as likely as not to be recovered. ECONOMIC INPUT ASSUMPTIONS (1) NuVista's type curve based on Management's best estimates (2) CGR yield represents the equivalent constant yield for the full life of the well (3) Pricing Assumptions: Fx (CAD:USD): 1.25:1 used in all pricing scenarios (4) Price case flat on a real basis; costs inflated at 2% per annum (5) NGL's as % of WTI: C3 = 30%; C4 = 65%; C5+ = WTI +US$2/Bbl (6) Gas price offset reflects NuVista's aggregate egress pipeline tolls and a $US1.05/MMBtu AECO to NYMEX basis (7) Recovered liquids unit transportation cost: C$6/Bbl

February 2018 34

APPENDIX

Montney – In The Right Neighborhood The Alberta Condensate-Rich Montney: A World Class Play

February 2018 35

1. Scalable/Repeatable • Deposition on the shelf edge – not isolated

pockets • Gas charged top to bottom • Over-pressured – low water saturation

2. Porous and Permeable • Hydrocarbon filled porosity up to 9%

(typically 4-5%) • Sand/silt reservoir exhibits much better

permeability

3. Condensate-rich • High liquids and condensate demonstrated

in all our wells to date

4. Thick Formation • 150 – 200 metres • Multiple developable layers of resource

HIGH QUALITY

RESERVOIR

150-200M THICK

CONDENSATE RICH

OVERPRESSURED

February 2018 36

• 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

• US condensate supply is increasing

• But condensate export restrictions are easing

• Condensate must be transported to Alberta – "we're on the right end of the pipe"

• Premium for condensate will always reflect the cost of transportation to deliver to Alberta while demand outstrips local Alberta production … and it still does

Western Canadian Condensate Pricing

Condensate Pricing Strong Demand and Premium Price for the Long-Term

Western Canadian Condensate Supply and Demand

February 2018 37

• Multiple pilot wells in progress by industry – Early Production Data Emerging

• NuVista has good distribution of vertical wells and cores

• NuVista vertical completion: over pressured, condensate-rich

• NuVista first horizontal test well now drilled and on production

Lower Montney Activity NuVista Data Collection In Progress

Elmworth

South Wapiti

Gold Creek

Bilbo

Kakwa

Karr

Pipestone

SCL 1-33-67-5W6 CTD: 0.1 bcf, Current CGR: 100

7Gen 13-24-65-5W6 CTD: 0.2 bcf, 43 mbbl C5+, CGR: 233

7Gen 12-32-64-5W6 CTD: 0.3 bcf, Current CGR: 305

7Gen 02/9-22-63-3W6 Tested 800 Mcf/d, 428 bpd C5+

NVA Lands Montney Hz Wells LWR Montney 'A' Wells LWR Montney 'A' Cores

ACL 1-7-67-7W6 CTD: 1.1 bcf, Test CGR: 54

SCL 6-20-66-6W6 Confidential until Sep 2017

T70

T68

T66

R9W6 R7W6 R5W6 R3W6

SCL 15-1-69-6W6 Tested: 1.9 MMcf/d and 174 bpd C5+

T64

NVA 15-13-68-7W6 Vertical Over-pressured – 133 Bbls/MMcf C5+

Velvet 12-33-66-2W6 CTD: 0.2 bcf, 42 mbbl C5+

SCL 6-15-63-7W6 Tested: 9 MMcf/d and 302 bpd C5+

SCL 02/9-27-66-7W6 CTD: 0.8 bcf, IP30 CGR: 85

T62

NVA Lower Montney Hz

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