CORPORATE PRESENTATION JUNE 2016 All amounts in Canadian dollars unless indicated otherwise

1

Advisory Regarding Forward-Looking Information and Statements

June 2016

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; plans to maintain NuVista's balance sheet strength; profitably grow production and funds from operations and develop NuVista's resource base, plans to focus on and improve processing and infrastructure; the benefits of NuVista's risk management program; the anticipated benefits of NuVista's asset base; expected supply cost reductions; NuVista's exploration and development program; drilling, testing and completion plans, the timing thereof and the results therefrom; anticipated inventory of drilling locations and type of wells; estimated liquid yields; anticipated well economics including drilling, completion and equipping and tie-in costs; anticipated well performance and type curves; and other estimated operating, transportation, G&A and other costs; estimated liquid yields; netbacks, payouts, finding and development costs, capital efficiencies, recycle ratio and estimated rates of return; NuVista's ability to fulfill all TOP obligations; guidance with respect to NuVista's capital expenditure program, production mix, netback, funds from operations, targeted net debt levels and net debt to funds from operations ratios; commodity pricing and exchange rates and industry conditions. 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 sufficiency of budgeted capital expenditures in carrying out planned activities; 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 estimates; the uncertainty of estimates and projections relating to reserves, production, 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.

2

NuVista Snapshot

Production (MBoe/d)

27% 50%

75% ~90%

95+%

28%

25%

17%

0

5

10

15

20

25

30

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

TSX trading symbol: NVA Market capitalization: ~$1.0 billion Basic shares outstanding: 156.6 million Bank revolver capacity: $200 million Percent Drawn: 45% Net Debt:Cashflow1: 1.5x

2016 Guidance Production: 23,500 – 24,500 Boe/d Capital investment: $165 – $175 million Funds from operations2: $110 – $120 million

1 June 2016 est. debt to Q116 Annualized Funds from Operations 2 Pricing Assumptions: $2.10/GJ AECO and US$50/Bbl WTI * Pro-forma 2013 Divestitures

Operating areas

WAPITI

EDMONTON

CALGARY

GRANDE PRAIRIE

June 2016

NuVista Corporate Info (June 30, 2016E)

3

NVA Principles and 2016 Guidance Focused on the Long Term… Flexibly managing the short term

June 2016

• Well costs down an additional 30% since 2014

• Continued improvement versus type curve

• Infrastructure spend complete for growth through 2018+

• Capex focused on well development in 2016-17, not on facilities

• G&A reduced by 1/2 over last 3 years, to $1.75/Boe for 2016

Reducing Costs & Improving Performance

• Net debt/funds flow from operations target under 2x and falling as strip pricing rises

• Flexibility to dial spending quickly down or upwards as commodity prices change

• Disciplined approach to capital spending

Maintain Balance Sheet Strength

• Short term pace of spend minimized while preserving long term take-away plans

• Result is 10% to 20% production per share growth with ~flat debt

• 2017 cash flow per share growth 15 to 50%(1)

• Optimized 2016 development well economics 30% to 60% IRR and 1.5 to 3.0 year payout(1)

Profitable Growth Tuned to Market Environment

Efficiency and Flexibility

(1)Range refers to Strip and Upside pricing cases, refer to Slide 7 for detailed assumptions

4

The Alberta Condensate-Rich Montney … A sweet spot in a "world class" play

High Quality

Reservoir

Overpressured 150-200 m thick

Condensate Rich

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

June 2016

The Alberta Condensate-Rich Montney Industry Drilling and Production growth continues…

*Excludes southern areas of Alberta Condensate-rich Montney (Resthaven and Simonette). Map is an estimate of Industry land positions compiled from public data

• High level of industry activity continues

• > 850 Montney HZ wells licensed and/or drilled to date

• Montney gas production exceeding 0.8 Bcf/d

Elmworth to Kakwa Montney HZ Activity Update*

June 2016

R9 W6 R10 W6

NuVista Encana Paramount Sinopec-Daylight CNRL Seven Generations Shell Apache Montney Licenses and Hz Wells

5

R6W6 R4W6 R2W6 R8W6

T65

T62

T61

T67

T69

T70

T68

T66

T64

T63

Elmworth to Kakwa Production Growth*

0

50

100

150

200

250

300

350

400

450

500

0

100

200

300

400

500

600

700

800

900

1000

Prod

ucin

g Hz

Wel

l Cou

nt

Avg.

Cal

enda

r Day

Gas

(M

Mcf

/d)

Avg. Gas Rate Producing Well Count

6

2016 Capital Guidance Ability to Adapt to Commodity Price Environment

June 2016

2015A FY Capex ($MM)

$185

$67

$10 $11

2016FY Capex – March Forecast ($MM)

$100

$10

$8 $6

DCET & Well OptimizationFacilities & Water MgmtMaintenanceOther

2015 Highlights: • 18 Montney Wells drilled • Built Elmworth Compressor Station

March 2016 Highlights: • Flexible capex program; reduced

from orig. Budget of $140M-$160M • 10-11 Wells in Bilbo & Elmworth • Minimal infrastructure spend

Development Focused

$273 MM $115-$135 MM

2016FY Capex – June Forecast ($MM)

$140

$14

$8 $6

June 2016 Highlights: • Increased capex as a result of

proceeds from strategic initiatives • Incremental development wells

added: total of ~18 Wells now planned

$165-$175 MM

Incremental Wells with Robust Economics

7

22.4 23.5 26.0

1.0

3.0

10

15

20

25

30

35

2015A 2016E 2017E

Upside Case Strip Case

June 2016

Funded Growth Plan at Strip and Upside Pricing…

Capital Expenditures ($MM) Production (MBoe/d)

(1)Assumptions: 2016 STRIP & UPSIDE: US$46/bbl WTI; C$2.00/GJ AECO; 1.31:1.0 C$:USD 2017 STRIP: US$51/bbl WTI; C$2.60/GJ AECO; 1.31:1.0 C$:USD 2017 UPSIDE: US$60/bbl WTI; C$3.00/GJ AECO; 1.27:1.0 C$:USD

$273

$165 $140

$10 $40

$100

$200

$300

2015A 2016E 2017E

Upside Case Strip Case

Cashflow(1) ($MM) Debt ($MM)(1)(3)

$125 $110 $125

$10

$50

$50

$100

$150

$200

2015A 2016E 2017E

Upside Case Strip Case $175

$120 $125

$50

$150

$250

2015A 2016E 2017E

Term Debt Bank Debt

$180 $175(2)

$273

22.4 24.5

29.0

(2) 2016 Capex approximately $100MM net of June 2016 W6 Asset Divestiture proceeds

(3) Working Capital Deficit not illustrated, which estimated to be approximately $20MM

8

0

1,000

2,000

3,000

4,000

5,000

6,0000 5 10 15 20 25 30 35 40

Dep

th (m

)

Days

2013 2014 2015

Recent wells: 4,700m in 17 days; 5,500m in 21 days

Recent Wells

$0

$2

$4

$6

$8

$10

$12

2013 2014 2015E 2016E

($M

) Relentless Improvement Efficiency and Well Costs

June 2016

$0

$100

$200

$300

$400

$500

$600

2013 2014 2015E 2016E

($00

0)

• Drilling and completion costs coming down steadily from efficiency improvements

• Record drilling cost of $2.8 MM with 4,750 metres of total measured depth

• Record completion costs of <$2.0 MM; average completion cost per stage placed has now dropped below $130,000

• In-field gathering largely in place – majority of 2016 wells will be on-lease tie-ins; limited expiry/step-out drilling

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

Montney Drilling & Completion Cost per Stage Operational Highlights

Recent Record Wells:

4,750m in 17 days; 5,500m in 21 days

Last 5 wells outperforming

these 2016 budget

expectations

9

0

100

200

300

400

500

600

700

0 6 12 18 24 30 36

Cum

ulat

ive

Prod

uctio

n (M

boe)

Time (Months)

2015 Type Curve (4.4 Bcf, 75 bbl/MMcf)2011-2013 (11 Wells)2014 (12 Wells)2015+ (10 Wells)

Relentless Improvement Bilbo Well Performance

June 2016

Bilbo Type Curve Progression

0

100

200

300

400

0 6 12 18 24

Cum

ulat

ive

Prod

uctio

n (M

Boe)

Time (Months)

2013 Type Curve (4.4 Bcf; 35 Bbls/MMcf)2014 Type Curve (4.4 Bcf; 45 Bbls/MMcf)2015 Type Curve (4.4 Bcf; 75 Bbls/MMcf)2016 Optimized Locations (5.0 Bcf; 66 Bbls/MMcf)

0

300

600

900

1,200

1,500

1,800

0 6 12 18 24

Sal

es P

rod

(Boe

/d)

Time (Months)

2016 Optimized Bilbo Well Production Profile

Two-year CTD production up 13% vs. 2015 and 38% vs. 2013

2016 Optimized Bilbo Total Production (Boe/d) 2016 Optimized Bilbo C5+ Production (Bbls/d)

NuVista's type curve based on Management's best estimates; Type Curve: Bcf = EUR; Bbls/MMcf = C5+ yield

Bilbo Well Production-to-Date

*Production groupings based off spud dates

10

Relentless Improvement Elmworth Well Performance

June 2016

Elmworth Type Curve Progression

0

100

200

300

400

0 6 12 18 24

Cum

ulat

ive

Prod

uctio

n (M

Boe)

Time (Months)

2013 Type Curve (4.4 Bcf; 35 Bbls/MMcf)2014 Type Curve (4.4 Bcf; 45 Bbls/MMcf)2015 Type Curve (6.0 Bcf; 45 Bbls/MMcf)2016 Optimized Loc's (6.5 Bcf; 42 Bbls/MMcf)

0

300

600

900

1,200

1,500

1,800

0 6 12 18 24

Sal

es P

rod

(Boe

/d)

Time (Months)

2016 Optimized Elmworth Total Production (Boe/d) 2016 Optimized Elmworth C5+ Production (Bbls/d)

2016 Optimized Elmworth Well Production Profile

Two-year CTD production up 7% vs.

2015 and 45% vs. 2013

Elmworth Well Production-to-Date

NuVista's type curve based on Management's best estimates; Type Curve: Bcf = EUR; Bbls/MMcf = C5+ yield

0

100

200

300

400

500

600

700

0 6 12 18 24 30 36

Cum

ulat

ive

Prod

uctio

n (M

boe)

Time (months)

2015 Type Curve (6 Bcf, 45 bbl/MMcf)Small Frac (3 Wells)Big Frac (12 Wells)

11

Montney Operations Activity Update

Elmworth 16 Wells Producing in the Development Block (IP30)

4 Elmworth Extension wells Producing (IP30) 1 New IP 30 – 1 Additional on-stream

1 Rig Drilling

Gold Creek 6 Producers (IP30)

One new IP 30

NVA New IP30 NVA Producing Montney (IP30) NVA In-Progress Wells Montney HZ’s

2016 Focus on Capital Efficiency • Increasing Montney Activity post-W6 Divestiture • ~18 Montney wells planned in 2016 • Minimal Infrastructure Capex required – filling

existing facilities • 2016 well performance expectations up 10-15%

over 2015

Attractive Land Tenure • NuVista has over 135,000 gross acres of land

(210 sections @ 86% WI) • Minimal 3rd party encumbrances • Manageable expiries

Activity Highlights • 4 New IP30's in Q1 – 4 Additional IP30's in Q2 • Increasing to 2 Rigs in Q3 • >60 wells on production

June 2016

T70

T68

T66

R8W6 R6W6

T67

T69

R7W6

Bilbo

33 Producers (IP30) 2 New IP30's – 2 Additional on-stream

1 New Extended-reach well completed (on-stream in July)

New Gold Creek IP30: Raw Gas: 4.4 MMcf/d (flat) Condensate: 710 Bbl/d Total Sales: 1,355 Boed CGR: 160 Bbl/MMcf

12

Elmworth Development Block Volume Ramp in-progress

June 2016

R9W6

T67

T68

NVA Montney IP30's

NVA In-Progress Wells

Montney Horizontal Wells

NVA Compressor Site Connected to SemCAMS

R8W6 1 New IP30

2 Additional Wells Recently On-Stream 1 Rig Drilling T69

0

1

2

3

4

5

6

7

8

9

Prod

uctio

n (M

boed

)

Sales Gas NGL's C5+

39 9

11

Cumulative-to-Date Bbls/MMcf

Condensate

Butane

Propane

North Montney Sales Production

Elmworth Well Performance

Raw Gas (Mcf/d)

C5+ (Bbl/d)

Total Sales

(Boe/d)

C5+ Yield (Bbl/

MMcf)

Well Count

IP30 6,305 312 1,298 49 16 IP60 5,662 268 1,154 47 15 IP90 5,375 236 1,078 44 13

IP180 4,169 172 837 41 9 IP360 3,186 126 635 39 8

13

Bilbo Development Block Focus on Efficient Production Additions in 2016

June 2016

NVA Montney IP30 Wells

NVA Montney In-Progress Wells

Montney Horizontal Wells

NVA 3-36 Compressor and connect to Keyera R6W6

T65

T66

2 New IP30's 2 Wells Recently On-Stream

1 Well Completed

0

2

4

6

8

10

12

14

16

Prod

uctio

n (M

boed

)

Sales Gas NGL's C5+

76

5 5

Cumulative-to-Date Bbls/MMcf

Condensate

Butane

Propane

South Montney Sales Production

Bilbo Well Performance

Raw Gas (Mcf/d)

C5+ (Bbl/d)

Total Sales

(Boe/d)

C5+ Yield (Bbl/

MMcf)

Well Count

IP30 6,341 642 1,618 101 33 IP60 5,604 515 1,383 92 31 IP90 5,123 450 1,245 88 31

IP180 4,331 343 1,021 79 26 IP360 3,235 226 737 70 22

Two New Step-Out IP30's Avg/Well: Raw Gas: 6.3 MMcf/d Condensate: 842 Bbl/d Total Sales: 1,732 Boed CGR: 134 Bbl/MMcf

14

A Closer Look at the NuVista 'Boe' Condensate Underpins Economics and Provides Torque to Oil Price Recovery

June 2016

NuVista Production Mix(1)

0

5,000

10,000

15,000

20,000

25,000

2013 2014 2015 2016E

71%

12%

17%

70%

22%

8% Nat Gas

Condensate

NGL's & Oil

NuVista 2016 Revenue Composition(2)

49%

49%

2%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2016E

(1) Pro-forma Divestitures (2) Based on WTI (USD/Bbl): $40.00; AECO (C$/GJ): $2.50; Fx (CAD:USD): 1.4:1

Boe/

d

Hedged or Unhedged: Condensate is ~50% of revenue from 22% of total

production

15

Wapiti Montney … Firm Egress Counts Built-in growth with generous capital flexibility in the short term … … and multiple options for the long term

CNRL Gold Creek Plant

Keyera Simonette Plant

SemCAMS K3 Plant SemCAMS Raw Gas Pipeline

Keyera Raw Gas and c5+ Pipeline

Alliance Sales Line

TCPL Sales Line

NuVista (100%) Bilbo Compressor Station

Raw Gas Capacity – 80 MMcf/d Condensate Cap'y – 8,000 Bbl/d

NuVista (100%) Elmworth Compressor Station

Raw Gas Capacity – 80 MMcf/d Condensate Cap'y – 4,000 Bbl/d

NuVista (50%) North Compressor Station

Raw Gas Capacity – 20 MMcf/d

Grande Prairie

Proposed 2018 Wapiti Area Gas Plants

June 2016

16

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

0

20

40

60

80

100

120

140

160

180

200

Mon

tney

Cap

acity

– B

oe/d

Mon

tney

Raw

Gas

Cap

acity

- M

Mcf

/d

SemCAMS Keyera Min TOP Commitment

30 MMcf/d

2016 Montney Production 20,000+ Boe/d 15,000+ Boe/d of Future Growth Capacity in Place

2013 2016 2015 2014

Wapiti Montney Processing Capacity Firm Capacity with TOP flexibility built in All products have virtually 100% FIRM downstream take-away

2017

15 MMcf/d

30 MMcf/d

35 MMcf/d

17 MMcf/d

30 MMcf/d

June 2016

New Sour Gas Plant

17

Commodity Price Risk Management We are well hedged with under 10% AECO exposure for 2016

June 2016

Floor C$ WTI price of $77.17/Bbl on ~52% of

2016 Q2-Q4 net production

Floor AECO price of $3.30/Mcf on ~71% of

2016 Q2-Q4 net production

Basis includes some Chicago pricing. Includes NYMEX hedges converted to an AECO equivalent price. Hedging position shown is post-W6 asset sale circa July 1, 2016

20.00

40.00

60.00

80.00

100.00

500

1,000

1,500

2,000

2,500

3,000

3,500

2016 Q2 2016 Q3 2016 Q4 2017 Q1 2017 Q2

Pric

e, C

$/Bb

l

Hedg

ed V

olum

e, B

bl/d

Crude Oil Hedge Position

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

0.75

1.50

2.25

3.00

3.75

4.50

20,000

40,000

60,000

80,000

100,000

120,000

2016Q2

2016Q3

2016Q4

2017Q1

2017Q2

2017Q3

2017Q4

2018Q1

2018Q2

2018Q3

2018Q4

2019Q1

Pric

e, C

$/G

J

Hedg

ed V

olum

e, G

J/d

Natural Gas Hedge Position

GJ/d Capped GJ/d Uncapped GJ/d AECO-NYMEX Basis Avg. Floor Avg. Ceiling

Only 5% of gas volumes exposed to AECO this

summer

18

Funds from Operations and netbacks hanging in there despite low commodity prices

45% 31%

52%

66% 72% 72% 79%

81%

17,823 14,493

18,030

23,165 23,215 21,448 21,622 23,355

25,484

-

5,000

10,000

15,000

20,000

25,000

30,000

Q114 Q214 Q314 Q414 Q115 Q215 Q315 Q415 Q116

Wapiti Montney Other Properties

NuVista Operating Results 2016 Guidance

Corporate Production (Boe/d)

Funds from Operations

2016 Actual Production (Boe/d)

Guidance (Boe/d)

Q1 25,484 24,500 - 25,000

2016 FY - 23,500 - 24,500

$19.26

$11.42

$16.47 $17.22 $14.52 $15.53 $16.00 $15.15

$13.06

$0

$5

$10

$15

$20

$25

$0$5

$10$15$20$25$30$35$40$45$50

Q114 Q214 Q314 Q414 Q115 Q215 Q315 Q415 Q116

($/B

OE)

($M

M)

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

June 2016

2016 Actual Capex ($MM)

2016 Capex Guidance Range

($MM)

Q1 $61 -

2016 FY $165 - $175

76%

2016 Actual Funds from Operations

($MM)

2016 Funds from Operations

Guidance Range ($MM) (1)

Q1 $30 -

2016 FY $110 - $120

(1) Based on commodity pricing of US$50/Bbl WTI and $2.10/GJ AECO

19

Balance sheet comes first Top plays win at any price, wells keep improving Focused capital discipline & reducing unit costs No material unutilized TOP cost concerns Increasing our growth in stages as strip prices move up Hedging – strong downside protection through 2016+

but with full torque to oil prices 2017+

NuVista Looking Forward Flexibility and Strength in a Volatile Environment

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

June 2016

20

Advisory Regarding Oil and Gas Information & Other Advisories

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 typecurves and well economics which are based on NuVista’s historical production in the Bilbo and Elmworth development areas, in addition to production history from analogous Montney developments located in close proximity to the Wapiti 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 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. 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 "Development Well Capital", "raw EUR", "NPV10", "PIR", "payout", "ROR", "netback", "F&D" and "capital efficiency". Development well capital includes all capital spent to drill, complete, equip and tie-in a well. Raw 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 development well capital. Payout means the anticipated years of production from a well required to fully pay for the development well capital 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. 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. 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. NON-GAAP MEASUREMENTS Within this presentation, references are made to terms commonly used in the oil and natural gas industry. Management uses funds flow, debt to annualized funds from operations and netback to analyze operating performance and leverage. Funds from operations as presented, does 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 cash 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. Debt (net debt) is calculated as long-term debt plus current assets less current liabilities and excludes the current portions of the commodity derivative asset or liability.

June 2016

21

Advisory Regarding Reserves Disclosure

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, 2015 and is based on an independent evaluation by GLJ using January 1, 2016 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.

June 2016

22

APPENDIX

June 2016

23

Gold Creek Delineation Continued Encouragement…

June 2016

16-1 On-production

16-19 On-production

16-27 On-production

1-28 On-production

8-12 New IP30

IP30

Well Raw Gas (MMcf/d)

C5+ (Bbls/d)

Total Sales (Boe/d)

C5+ Yield (Bbl/MMcf)

16-19 6.8 377 1,307 56 13-25 1.8 263 543 146 1-28 2.9 462 876 161 16-01 7.3 489 1,635 67 16-27 4.6 256 1,044 55 8-12 4.4 710 1,355 160

Cumulative Production to Date (June 15, 2016)

Well Days on Prod

C5+ Yield Condensate Cumulative Sales Gas Total

(Bbl/MMcf) (Mbbls) (MMcf) (MBoe)

16-19 339 56 52 775 197 13-25 232 123 36 257 81 1-28 451 121 120 860 270

16-01 245 49 40 694 170 16-27 322 40 39 832 193

13-25 Shut-in pending tie-in

24

2015 Year-end Reserves Report

2015 Year-end Reserves Report – GLJ Petroleum Consultants Ltd. • PDP reserves volume increased 40% before production and dispositions, or 13% after • Corporate TP+PA reserves volume increased by 15% • Corporate TP+PA F&D of $3.69/Boe & TP F&D of $8.11/Boe – 2015 Corporate Netback

$15.28/Boe – TP+PA Recycle Ratio 4.1x & TP Recycle Ratio 1.9x • Corporate TP+PA B-Tax NPV10% decreased 25% to $1.1 billion primarily due to a ~30%

reduction in GLJ's price forecast* • Reserve Life Index now at ~27 years and ~13 years on a TP+PA and TP basis, respectively • Montney TP+PA average reserves per well increased 4% vs. 2014; Montney TP+PA well

locations now 253, an increase of 23% compared to year end 2014

12 29 86

184 225

98 65

53

36

28

0

50

100

150

200

250

300

2011 2012 2013 2014 2015

Other Wapiti Montney

Corporate TP+PA Reserves (MMBoe)

253

87 167

847 1,155

938

1,197

612

476

251

120

0

200

400

600

800

1,000

1,200

1,400

1,600

2011 2012 2013 2014 2015

Other Wapiti Montney

Corporate TP+PA NPV10% ($MM)

1,058

Corporate TP+PA Reserves by Area

* Based on first 3 yr avg prices See Appendix for important disclosures regarding Reserves June 2016

89%

9%

2% MTY

W6 SWT

Non-W6

25

Condensate Pricing Strong demand and premium price for the long term

• 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 Canada Condensate Supply and Demand

June 2016

Western Canadian Condensate Pricing

26

Lower Montney Activity NuVista Data Collection In Progress

Elmworth

Wapiti

South Wapiti

Gold Creek

Bilbo

Kakwa

Karr

Pipestone

SCL 1-33-67-5W6 Producing

7Gen 13-24-65-5W6 Producing (dual lateral)

7Gen 12-32-64-5W6 Producing

7Gen 15-22-63-3W6 Producing

Confidential 30-Jan-2016

NVA Lands Montney Wells LWR Montney A Wells LWR Montney Cores

• 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 pilot deferred until commodity price recovery

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

June 2016

ACL 1-7-67-7W6 Producing

Confidential: 07-Oct-2015

SCL 9-27-66-7W6 Confidential: 14-Feb-2016

T70

T68

T66

R9W6 R7W6 R5W6 R3W6