Corporate Presentation. December 2017

Corporate Presentation December 2017

Advisory Regarding Forward-Looking Information and Statements 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. December 2017 1

NuVista Snapshot NuVista Corporate Info Grande Prairie TSX Trading Symbol: NVA Market Capitalization: ~$1.5 billion Basic Shares Outstanding (2) : 173.6 million Credit Facility Capacity (1) : $310 million Percent Drawn (2) : 48% Net Debt/Funds from Operations (2) : 1.4x NuVista Wapiti Montney Project 2018 Guidance FY Average Production: FY Capital Investment: FY Funds from Operations (3) : 35,000 40,000 Boe/d $270 $310 million $210 $240 million Edmonton Production (MBoe/d) 40 30 Non-Core Areas Calgary 20 10 0 28% 27% 25% 50% 17% 75% 90% 95+% 99% 2013* 2014 2015 2016 2017E 2018E Wapiti Montney Wapiti Sweet Other December 2017 2 1 As at Oct. 31, 2017 2 Sept. 30, 2017 net debt to Q317 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

Why Buy NuVista? Trusted Repeatable Value Growth 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 December 2017 3

Challenges with Canadian Energy? NVA Has Managed the Risk Challenge Can't get the oil out? Not enough gas egress? AECO Volatility? Can't get government permits? Need more facilities? NuVista Solution Alberta is the condensate market We have firm egress for 100% of our 60,000 Boe/d Plan 60% 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 December 2017 4

Cal Day Gas Avg (MMcf/d) Prod Well Count Montney In The Right Neighborhood Condensate-Rich Montney Industry Growth Continues High level of industry activity continues Elmworth to Kakwa Montney HZ Activity Update* > 900 Montney HZ wells licensed and/or drilled to date Montney gas production exceeding 1.0 Bcf/d T70 T69 T68 Elmworth to Kakwa Production Growth* T67 1000 Cal Gas Rate Prod Well Count 750 T66 800 600 T65 600 450 T64 400 200 0 300 150 0 NuVista Encana Paramount Sinopec-Daylight CNRL Seven Generations Shell Montney Licenses and Hz Wells R8W6 R7W6 T63 T62 R6W6 R5W6 R4W6 R3W6 R2W6 December 2017 *Excludes southern areas of Alberta Condensate-rich Montney (Resthaven and Simonette). Map is an estimate of Industry land positions compiled from public data. 5

Funded Growth Plan Strong Growth with Managed Net Debt to Funds from Operations Capital Expenditure Guidance Range ($MM) $400 Production Guidance Range (MBoe/d) 40 40.0 $300 $200 $273 $189 $300 $280 $310 $270 30 20 22.4 24.6 31.0 28.0 35.0 $100 2015A 2016A 2017E 2018E 10 2015A 2016A 2017E 2018E Funds from Operations Guidance Range (1)(2) ($MM) Net Debt/Funds from Operations (1)(2) $250 $240 3.0x $200 $180 2.0x $150 $100 $125 $138 $160 $210 1.0x $50 2015A 2016A 2017E 2018E (1) Assumptions: 2017: US$50/Bbl WTI; US$3.00/MMBtu NYMEX; 1.3:1.0 C$:USD 2018: US$55/Bbl WTI; US$3.00/MMBtu NYMEX; 1.25:1.0 C$:USD (2) Funds from Operations. See "Non-GAAP Measurements". December 2017 6 0.0x 2015A 2016A 2017E 2018E

2018 Guidance Strong Year-over-Year Growth and Capital Flexibility 2018 Capex Range ($MM) Flexibility to adjust Flexibility to adjust ~$120M of 2018 capex without capex without impacting 2018 impacting annual production production $85 $60 $160 2018 Production Adds Activity 2019 Growth Activity Long Term Investment, Maintenance and Other 2018 Capex Guidance: $270 $310MM 2018 Production Guidance: 35,000 40,000 Boe/d 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 *Long term investments include Pipestone long lead-time compression, water sourcing and disposal infrastructure, and science projects December 2017 7

Line-of-Sight to 60,000+ Boe/d Four Development Blocks Established Piestone Pipestone Emerging Dev Block 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) Elmworth Free Cashflow Elmworth Generation 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) Gold Creek On Production 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) Bilbo Free Cashflow Generation 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) (1) Well inventory is expected to be sufficient to produce at facility capacity for at least 10 years; refer to slides 22 & 23 for our existing midstream capacity and licensed Wapiti area gas plants. December 2017 8

NuVista Montney Portfolio Increasing Rate-of-Change in Value Valued on Production Bilbo Elmworth Gold Creek Pipestone Valued on Potential Lower Montney West Bilbo Establishing Type-Curve Improving Type-Curve Maintenance DELINEATION EARLY DEVELOPMENT FULL DEVELOPMENT December 2017 9

200m+ Inventory Underpinned by Established Development Blocks Pipestone Elmworth Gold Creek Bilbo Middle Montney 'D' Tested 21 Producers Not Tested 3 Producers Middle Montney 'C' Offsetting Production Middle Montney 'B' Not Tested 6 Producers 8 Producers 45 Producers Lower Montney Multiple Industry Tests Significant Future Potential Inventory (Based on Zones Tested to date) Pipestone (C) Elmworth (B&C) Gold Creek (B) Bilbo (B&C) Total NVA NVA Producers 0 27 8 48 83 Remaining Inventory 40 125 115 140 420 *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 2016 Proved Plus Probable locations (including producers) was 309. See "Advisory Regarding Oil and Gas Information". December 2017 10

Production (Mboed) Bilbo Development Block Free-Cashflow Positive 48 Wells on Production (IP30) South Montney Sales Production Six-well pad On Production 18 16 14 12 10 Cumulative-to-Date Bbls/MMcf 5 4 85 C5+ Butane Propane Sales Gas NGL's C5+ 8 6 4 2 2-well Pad Drilling T65 0 Bilbo Well Performance NVA Montney New IP30's NVA In-Progress Wells Montney Horizontal Wells NVA Compressor Site R6W6 Connected to Keyera 2-well Pad Completed (including 1 Lower Montney) On-stream Q1 2018 Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) C5+ Yield (Bbl/ MMcf) Well Count IP30 6,420 746 1,713 116 48 IP60 5,750 622 1,493 108 48 IP90 5,276 547 1,346 104 48 IP180 4,411 412 1,086 93 43 IP360 3,308 263 775 79 34 December 2017 11

Total Sales (Boe/d) Capital Costs / 100m hz ($) Bilbo Development Block Performance Update: Getting More for Less Bilbo IP90 Production and DCET Capital Cost Total Sales IP90 for Bilbo Condensate (Bbl/d) Total Sales (Boe/d) 10-well Total Sales Mov. Avg. 10-well Capital Cost Mov. Avg. Hi-FI Wells 3,000 Encouraging Initial Hi-Fi Results 1,200 2,500 Now Reflects IP90 Data 1,000 2,000 800 1,500 600 1,000 400 500 200 0 0 2012 2013 2014 2015 On Production Year 2016 2017 December 2017 12

NYMEX NYMEX Rate (MMcf/d) NYMEX Bilbo Development Block Results To-Date and Type Well Economics 10 Type Curve Comparison Plot Original Historical Average Hi-Fi Hi-Fi Type Curve Economic Sensitivities Payout (Years) WTI $55/Bbl $60/Bbl $65/Bbl $2.70/MMBtu 1.3 1.1 1.0 1 $3.10/MMBtu 1.1 1.0 0.9 $3.50/MMBtu 1.0 0.9 0.8 0 0 1,000 2,000 3,000 4,000 5,000 6,000 Cumulative Gas (MMcf) Rate of Return WTI $55/Bbl $60/Bbl $65/Bbl $2.70/MMBtu 65% 85% 110% Hi-Fi Type Curve Production Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) IP90 7,000 525 1,640 IP180 6,531 490 1,530 IP360 4,848 364 1,136 Hi-Fi Type Curve Inputs DCET Capital ($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 $3.10/MMBtu 85% 110% 130% $3.50/MMBtu 110% 135% 160% Net Present Value @ 10% ($MM) WTI $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 * 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 December 2017 13

Production (Mboed) Elmworth Development Block Significant New Results Hi-Fi Coming Through 27 Wells on Production (IP30) North Montney Sales Production R9W6 T69 3 New IP30's in Q3 Avg: 2,240 Boe/d 779 Bbl/d C5+ R8W6 16 14 12 10 C5+ Butane Propane Cumulative-to-Date Bbls/MMcf 9 9 40 Sales Gas NGL's C5+ 8 T68 4 more IP30's to come in Q4 (non Hi-Fi) 6 4 2 0 Elmworth Well Performance T67 NVA Montney New IP30's NVA In-Progress Wells Montney Horizontal Wells NVA Compressor Site Connected to SemCAMS Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) C5+ Yield (Bbl/ MMcf) Well Count IP30 7,371 413 1,549 56 27 IP60 6,206 291 1,256 47 22 IP90 5,845 266 1,175 46 22 IP180 4,772 207 949 43 21 IP360 3,299 132 645 40 16 December 2017 14

Total Sales (Boe/d) Capital Costs / 100m hz ($) Elmworth Development Block At a Tipping Point: Encouraging Recent Well Results Elmworth IP30 Production and DCET Capital Cost Total Sales IP30 for Elmworth Condensate (Bbl/d) Total Sales (Boe/d) 10-well Total Sales Mov. Avg. 10-well Capital Cost Mov. Avg. Hi-FI Wells 3,500 800 3,000 700 2,500 600 2,000 1,500 1,000 500 400 300 200 500 100 0 0 2010 2012 2013 2014 2015 On Production Year 2016 2017 December 2017 15

NYMEX NYMEX Rate (MMcf/d) NYMEX Elmworth Development Block Results To-Date and Type Well Economics 10 Type Curve Comparison Plot Original Historical Average Hi-Fi Hi-Fi Type Curve Economic Sensitivities Payout (Years) WTI $55/Bbl $60/Bbl $65/Bbl $2.70/MMBtu 2.4 1.9 1.5 1 $3.10/MMBtu 1.7 1.4 1.2 $3.50/MMBtu 1.3 1.2 1.1 0 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 Cumulative Gas (MMcf) Rate of Return WTI $55/Bbl $60/Bbl $65/Bbl $2.70/MMBtu 30% 40% 50% Hi-Fi Type Curve Production Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) IP90 7,000 280 1,370 IP180 7,000 280 1,370 IP360 6,007 239 1,174 Hi-Fi Type Curve Inputs DCET Capital ($MM) $8.4 EUR (Raw Gas) (Bcf) 7.0 EUR (MMBoe) 1.4 CGR (C5+ Bbls/MMcf) 40 Opex ($/Boe) $10.50 Horizontal Length (m) 2,000 Stage Count 40 $3.10/MMBtu 40% 55% 65% $3.50/MMBtu 60% 75% 90% Net Present Value @ 10% ($MM) WTI $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 * 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 December 2017 16

Lower MNTN MNTN 'B' MNTN 'C' Gold Creek Development Block Initial Type-Curve Established 2016/17 Early Development Activity and Infrastructure Gold Creek Highlights Gold Creek Geology Up to 3 developable layers Condensate yield expected to average 60+ Bbls/MMcf (range 40 to 150+) Gamma Porosity % 20 0 Gold Creek Step-out Completion in Q417 Initial type-curve raw gas EUR average 4.0+ Bcf 5 existing producers ~4 additional through 2017 (incl. ERH and Hi-Fi tests) Pipeline Connected to NVA Elmworth Comp Stn 3-well ERH/HiFi Pad (06-13) On stream 2016/17 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 IP30's 2019 SemCAMS Wapiti Gas Plant NVA Montney New 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 NVA In-Progress Wells Montney Hz Wells 06-13 Hi-Fi + ERH Avg 6,857 863 1,946 126 December 2017 17

NYMEX NYMEX Rate (MMcf/d) NYMEX Gold Creek Development Block Results To-Date and Type Well Economics 10 Type Curve Comparison Plot Historical Average ERH ERH + HiFi Hi-Fi Type Curve Economic Sensitivities Payout (Years) WTI $55/Bbl $60/Bbl $65/Bbl $2.70/MMBtu 1.8 1.4 1.2 1 $3.10/MMBtu 1.4 1.2 1.1 $3.50/MMBtu 1.2 1.1 1.0 0 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 Cumulative Gas (MMcf) Rate of Return (Pct.) WTI $55/Bbl $60/Bbl $65/Bbl $2.70/MMBtu 40% 50% 65% Hi-Fi Type Curve Production Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) IP90 7,000 420 1,545 IP180 7,000 420 1,545 IP360 5,684 341 1,254 Hi-Fi Type Curve Inputs DCET Capital ($MM) $10.8 EUR (Raw Gas) (Bcf) 6.0 EUR (MMBoe) 1.3 CGR (C5+ Bbls/MMcf) 60 New GP Opex ($/Boe) $8.00 Horizontal Length (m) 3,000 Stage Count 60 $3.10/MMBtu 50% 65% 80% $3.50/MMBtu 70% 80% 100% Net Present Value @ 10% ($MM) WTI $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 * 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 December 2017 18

Pipestone Highlights Lower MNTN MNTN 'B' Pipestone Development Block Facilities in Planning Phase for 2019-20 Development Pipestone Activity Pipestone Geology ECA Pipestone 'Super- Condensate' Up to 4 developable layers Acreage to the West extensively developed by EnCana Gamma Porosity 20 0 NVA 13-27 Hz Successful Test Final 24-hr rate: 6 MMcf/d Gas >100 Bbls/MMcf C5+ CNOR 13-22 Hz Initial Test 278 Bbls/MMcf C5+ 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 MNTN 'C' MNTN 'D' ECA Pipestone Condensaterich Development Future NVA Compressor and Pipeline to SemCAMS Wapiti Gas Plant *Map of activity at Pipestone is compiled from public data December 2017 19

Sales Production (Boe/d) Pipestone Development Block Robust Initial Type-Curve Economics Offsetting Well Production vs. NVA Type Well (1) Pipestone Dev. Type Curve Inputs and Economics Half-Cycle Inputs Base Type Curve Offsetting wells restricted by operator to ~3-4 MMcf/d DCET Capital ($MM) $7.0 EUR (Raw Gas) (Bcf) 5.0 EUR (MMBoe) 1.1 CGR (C5+ Bbls/MMcf) 60 Opex ($/Boe) $10.00 Horizontal Length (m) 2,000 Stage Count 25 Source: GeoSCOUT 1,800 1,500 Pipestone Base Type Well Production Profile Pipestone TC Total Prod Pipestone TC Condensate Prod Economics Base Type Curve NPV10 ($MM) $7.5 PIR 1.1 1,200 900 600 300 0 0 6 12 18 24 Time (Months) Payout (Years) 1.2 ROR (%) 85% Netback ($/Boe) $22.00 F+D ($/Boe) $6.50 Cap. Efficiency ($/Boed) $8,000 * 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 December 2017 20

($000) Number of Stages ($MM) Depth (m) Proven Track Record of Execution Improving Efficiency and Well Costs Montney Well Cost (DCET) By Year Average Annual Montney Drilling Curves $14 $12 $10 $8 0 1,000 2,000 2013 2014 2015 2016 2017 $6 3,000 $4 4,000 $2 5,000 $0 2013 2014 2015 2016 2017E 2018E 6,000 0 5 10 15 20 25 30 35 Montney Drilling & Completion Cost per Stage Operational Highlights $600 $500 $400 $300 $200 Cost per Stage No. of Stages 60 50 40 30 20 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 $100 $0 2013 2014 2015 2016 2017E 2018E 10 0 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 December 2017 21

Wellhead-to-Market Egress Plan In-Place Firm Egress Counts: Long-Term Growth Secured NuVista North Compressor Station (50% WI) Gross Raw Gas Capacity: 35 MMcf/d Grande Prairie SemCAMS Wapiti Sour Gas Plant Status: Under Construction 2019 Startup Raw Gas Capacity: 200 MMcf/d Condensate Capacity: 20,000 Bbl/d CNRL Gold Creek Plant Keyera Wapiti Sour Gas Plant Status: Licensed Raw Gas Capacity: 300 MMcf/d Condensate Capacity: 25,000 Bbl/d NuVista Elmworth Compressor Station (100% WI) Raw Gas Capacity: 80 MMcf/d Condensate Capacity: 4,000 Bbl/d NuVista Bilbo Compressor Station (100% WI) Raw Gas Capacity: 80 MMcf/d Condensate Capacity: 8,000 Bbl/d Keyera Simonette Plant SemCAMS K3 Plant SemCAMS Raw Gas Pipeline Keyera Raw Gas and C5+ P/L Alliance Sales Line TCPL Sales Line December 2017 22

Montney Raw Gas Capacity (MMcf/d) Montney Capacity (Boe/d) Market Egress Plan In-Place Wapiti Montney Processing Capacity Material Running Room 300 60,000+ Boe/d Montney Processing Capacity Secured 60,000 250 50,000 200 Pipestone 150 Gold Creek 40,000 30,000 100 Bilbo 20,000 50 10,000 Elmworth 0 2014 2015 2016 2017 2018 2019 2020 2021 0 Min. Midstream TOP Commitment Downstream Firm Gas Service TOP = NuVista Minimum take-or-pay volume commitment Downstream Firm Gas Service includes priority interruptible service December 2017 23

Pct. of Forecast Gas Production Market Egress Plan In-Place Natural Gas Price Diversification 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 Natural Gas Price Diversification Hedged NYMEX Floating Chicago Floating California Floating Dawn Floating AECO Floating 100% 1% 1% 21% 28% 20% 75% 7% 1% 14% 27% 50% 9% 19% 70% 25% 48% 14% 20% 0% 2017 Q4 2018 2019 December 2017 24

Hedged Volume, GJ/d Price, C$/GJ Hedged Volume, Bbl/d Price, C$/Bbl Commodity Price Risk Management Continuing Rolling Hedging Program Crude Oil Hedge Position 8,000 70.00 7,000 67.50 6,000 65.00 5,000 4,000 3,000 62.50 60.00 57.50 Floor C$ WTI price of $68.58/Bbl on ~66% of 2017Q4 net production 2,000 55.00 1,000 52.50 2017 Q4 2018 Q1 2018 Q2 2018 Q3 2018 Q4 50.00 Bbl/d Capped Bbl/d Uncapped Avg. Floor Avg. Ceiling Natural Gas Hedge Position 125,000 3.75 100,000 3.00 75,000 50,000 2.25 1.50 Floor AECO price of $3.04/Mcf on ~70% of 2017Q4 net production 25,000 0.75 2017 Q4 2018 Q1 2018 Q2 2018 Q3 2018 Q4 GJ/d Capped GJ/d Uncapped Avg. Floor Avg. Ceiling December 2017 Natural gas hedges include some NYMEX hedges converted to an AECO equivalent price. 25

Natural Gas Sales Points Q3 2017 Diversification Counts Grande Prairie AECO $2.04 Market Price Market Netback $2.73 $2.72 $2.58 Dawn $3.64 Malin $3.41 Chicago $3.58 * All prices in C$/mcf * Market Netback = Market Price less tolls (including fuel) * FX at C$/US$ at 1.2638 * Based on Q317 average prices Henry Hub $3.79 December 2017 26

($MM) ($/BOE) NuVista Operating Results 2017 Guidance On Track Corporate Production (Boe/d) Wapiti Montney Other Properties 35,000 Actual Production (Boe/d) Guidance (Boe/d) 30,000 25,000 20,000 24,898 24,716 26,731 25,454 29,405 Q1 '17 26,730 26,000 29,000 Q2 '17 25,450 22,500 25,000 15,000 10,000 5,000 83% 96% 96% 96% 96% 97% Q3 '17 29,400 26,000 29,000 Q4 '17-35,000 38,000 - Q3 '16 Q4 '16 Q1 '17 Q2 '17 Q3 '17 FY 2017-28,000 31,000 Corporate Funds from Operations $60 Funds from Operations ($MM) Funds from Operations ($/Boe) $55 $50 $17.90 $17.98 $16.98 $45 $15.36 $40 $13.65 $35 $30 $25 $20 $15 $10 Q3 '16 Q4 '16 Q1 '17 Q2 '17 Q3 '17 $25 $20 $15 $10 $5 $0 2017 YTD Capex ($MM) 2017 Capex Guidance Range ($MM) $275 $280-$300 2017 YTD Funds from Operations ($MM) 2017 Funds from Operations Guidance Range ($MM) $124 $160-$180 December 2017 27

NuVista Looking Forward Flexibility and Strength Growth in a Volatile Environment 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 December 2017 28

Advisory Regarding Oil and Gas Information 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, 2016 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 Original); (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 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 "Development Well Capital" (or "DCET"), "raw EUR", "NPV10", "PIR", "payout", "ROR", "netback", "F&D", "capital efficiency", "IRR", "recycle ratio" and "reserves life index". 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. 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. December 2017 29

Advisory Regarding Oil and Gas Information ADVISORY REGARDING OIL AND GAS INFORMATION This presentation discloses NuVista's drilling inventory associated with its Montney assets. Certain of the drilling locations represented in such inventory represent unbooked locations. While proved and probable locations (or "booked" locations) are derived from NuVista's most recent independent reserves as prepared by GLJ as of December 31, 2016 and account for drilling locations that have associated proved and/or probable reserves, unbooked locations do not have any associated proved or probable reserves as at December 31, 2016. Unbooked locations are management's internal estimates of drilling locations based on current estimates for achievable well length and inter-well spacing. There is no certainty that NuVista will drill all drilling locations and if drilled there is no certainty that such locations will result in additional production or reserves. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory, oil and natural gas prices, costs, actual drilling results and other factors. 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, 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. December 2017 30

Advisory Regarding Non-GAAP Measurements, Reserves Disclosure & Economic Assumptions 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. 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, 2016 and is based on an independent evaluation by GLJ using January 1, 2017 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 December 2017 31

APPENDIX December 2017 32

Montney In The Right Neighborhood The Alberta Condensate-Rich Montney: A World Class Play 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 OVERPRESSURED HIGH QUALITY RESERVOIR CONDENSATE RICH 150-200M THICK December 2017 33

Proven Track Record of Execution 2016 Year-end Reserves Report 2016 Year-end Reserve Highlights Montney now comprises 99% of NuVista's reserves PDP F&D at 5-year low ($10.80/Boe) driven by positive technical revisions and continued focus on Montney development drilling PDP reserves value (NPV10) at recent high despite low commodity price forecasts Condensate now 25% of NuVista reserves (up from 19% last year) Pipestone Probable locations booked Total Montney PDP Wells increased to 69 Total Proved + Probable well count (incl. PDP) now 309 NuVista PDP Reserves (MMBoe) NuVista PDP NPV10 ($MM) 40 Non-MTY MTY $400 Non-MTY MTY 30 $300 20 $200 10 $100 0 2012 2013 2014 2015 2016 $0 2012 2013 2014 2015 2016 See Advisory Regarding Reserve Disclosure December 2017 34

Proven Track Record of Execution 2016 Year-end Reserves Report Montney 'C' Reserves Montney 'B' Reserves NuVista F&D Costs ($/Boe) $30 $25 $20 $15 $10 $5 PDP F&D TP+PA F&D $0 2013 2014 2015 2016 Gross Montney Well and Location Count by Year Montney Well and Location Count Breakdown (Gross) Bilbo Elmworth Gold Creek Pipestone Other* PDP 39 21 4 0 5 Offsets 87 58 35 8 52 Total 126 79 39 8 57 * Includes wells outside of our defined development blocks See Advisory Regarding Reserve Disclosure 350 300 250 200 150 100 50 0 Offsets Locations PDP Wells 309 275 228 240 223 121 194 103 18 34 52 69 2013 2014 2015 2016 December 2017 35

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 Western Canadian Condensate Pricing 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" Western Canadian Condensate Supply and Demand Premium for condensate will always reflect the cost of transportation to deliver to Alberta while demand outstrips local Alberta production and it still does December 2017 36

Lower Montney Activity NuVista Data Collection In Progress R9W6 R7W6 R5W6 R3W6 T70 T68 Pipestone NVA 15-13-68-7W6 Vertical Over-pressured 133 Bbls/MMcf C5+ Elmworth ACL 1-7-67-7W6 CTD: 1.1 bcf, Test CGR: 54 Gold Creek SCL 15-1-69-6W6 Tested: 1.9 MMcf/d and 174 bpd C5+ SCL 1-33-67-5W6 CTD: 0.1 bcf, Current CGR: 100 Velvet 12-33-66-2W6 CTD: 0.2 bcf, 42 mbbl C5+ 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 T66 SCL 02/9-27-66-7W6 CTD: 0.8 bcf, IP30 CGR: 85 South Wapiti H217 NVA Lower Montney Hz SCL 6-20-66-6W6 Confidential until Sep 2017 Bilbo Karr 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 NuVista first horizontal test well now drilled and completion in Q118 T64 SCL 6-15-63-7W6 Tested: 9 MMcf/d and 302 bpd C5+ 7Gen 02/9-22-63-3W6 Tested 800 Mcf/d, 428 bpd C5+ Kakwa T62 NVA Lands Montney Hz Wells LWR Montney 'A' Wells LWR Montney 'A' Cores December 2017 37