Corporate Presentation. May 2017

Transcription

1 Corporate Presentation May 2017

2 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; plans to maintain NuVista's balance sheet strength; NuVista's ability to profitably grow production and funds from operations and develop NuVista's resource base, processing and infrastructure plans; future processing capacity; the benefits of NuVista's risk management program; the anticipated benefits of NuVista's asset base; expected supply cost increases and annual efficiency gains; 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; estimated supply and demands for condensates; anticipated well economics including drilling, completion and equipping and tie-in costs; estimated future oil and gas services 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; anticipated facility capacity and NuVista's ability to fulfill all TOP obligations; expected impact of infrastructure maintenance; guidance with respect to NuVista's capital expenditure program, production, production mix, netback, funds from operations, targeted net debt levels and net debt to funds from operations ratios; working capital, commodity pricing and exchange rates, industry activity 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; 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, 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 ( 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. May

3 NuVista Snapshot NuVista Corporate Info Grande Prairie TSX Trading Symbol: NVA Market Capitalization: ~$1.0 billion Basic Shares Outstanding (1) : million Credit Facility Capacity (1) : $235 million Percent Drawn (1) : 26% Net Debt/Funds from Operations (2) : 0.9x NuVista Wapiti Montney Project 2017 Guidance FY Average Production: FY Capital Investment: FY Funds from Operations (3) : 28,000 31,000 Boe/d $280 $300 million $160 $180 million Edmonton Production (MBoe/d) Non-Core Areas Calgary % 27% 25% 50% 17% 75% 90% 95+% 2013* E Wapiti Montney Wapiti Sweet Other May As at May 1, March 31, 2017 net debt to Q117 Annualized Funds from Operations. See "Non-GAPP Measurements" Pricing Assumptions: $3/GJ AECO and US$55/Bbl WTI * Pro-forma 2013 Divestitures

4 Why Buy NuVista? Trusted Repeatable Growth Pure-Play Montney Company In The Right Neighborhood Funded Growth Plan Through 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 May

5 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 0.9 Bcf/d T70 T69 T68 Elmworth to Kakwa Production Growth* T Cal Gas Rate Prod Well Count T66 T NuVista Encana Paramount Sinopec-Daylight CNRL Seven Generations Shell Apache T64 T63 T62 Montney Licenses and Hz Wells R8W6 R7W6 R6W6 R5W6 R4W6 R3W6 R2W6 May 2017 *Excludes southern areas of Alberta Condensate-rich Montney (Resthaven and Simonette). Map is an estimate of Industry land positions compiled from public data. 4

6 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 metres Multiple developable layers of resource OVERPRESSURED HIGH QUALITY RESERVOIR CONDENSATE RICH M THICK May

7 Funded Growth Plan Strong Growth with Managed Debt-to-Cashflow Capital Expenditures ($MM) Production (MBoe/d) $400 Upside Case Base Case 50 Upside Case Base Case $300 $200 $273 $189 $300 $280 $330 $ $ A 2016A 2017E 2018E A 2016A 2017E 2018E Funds from Operations (1)(2) ($MM) Net Debt:Funds from Operations (1)(2) $250 Upside Case Base Case $ x Base Pricing $200 $ x $150 $100 $125 $138 $160 $ x $ A 2016A 2017E 2018E (1) Assumptions: 2017/18: US$55/Bbl WTI; C$3.00/GJ AECO; 1.30:1.0 C$:USD (2) Funds from Operations. See "Non-GAPP Measurements". 0.0x 2015A 2016A 2017E 2018E May

8 Production (MBoe/d) Productive Montney Well Count Funded Growth Plan Strong Production Ramp in Q4 After Planned Outages Production & Productive Well Count Forecast 2017E Capex Range ($MM) 40 Guidance Range Wells Capable of Production Well Capability 120 DCET & Well Optimization Facilities, Water & Other ~$50-60 Q1-Q3: MBoe/d ~$ Q416A Q117A Q217E Q317E Q417E Production Guidance: 28,000 31,000 Boe/d 2017 Capex Guidance: $280 $300MM Highlights: ~5 Active rigs in H117 drive Q417 production ramp Planned 5-yr cycle maintenance outages at K3 and Simonette plants impact Q2/Q3 production, ~3,000 Boe/d annual impact ~40% Production growth Q416 to Q417 Highlights: ~29 Wells planned: development wells in Bilbo, Elmworth and Gold Creek; and one well in Pipestone Continued piloting of ERH and Hi-Fi well designs Water and Compression infrastructure capacity build-out to hit ~40,000 Boe/d in Funds from Operations Guidance (1)(2) : $160 $180MM (1) May 2017 Commodity Price Assumptions: US$55/Bbl WTI; C$3.00/GJ AECO; 1.30:1.0 C$:USD Fx (2) See "Non-GAAP Measurements". 7

9 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) Full Development into 2019 SemCAMS Wapiti Gas Plant Early Development Drilling in 2017 Forecast production ~27% condensate 10,000 Boe/d expected facility capacity and well inventory (1) Gold Creek On Production Initial type-curve 4.0 Bcf, 60 Bbls/MMcf condensate (40 to 150+Bbls/MMcf) NVA footprint provides optionality in well length (ERH) Early delineation/dev capacity into Elmworth infrastructure Full Development into 2019 SemCAMS Wapiti Gas Plant Forecast production ~27% condensate 18,000 Boe/d expected facility capacity and well inventory (1) Elmworth On Production Base Type-curve 6.0 Bcf, 45 Bbls/MMcf condensate Optimized 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 ~12,500+ Boe/d with ~22% condensate 16,000 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 slide 22 & 23 for our existing midstream capacity and licensed Wapiti area gas plants. Bilbo Free Cashflow Generation Base Type-curve 4.4 Bcf, 75 Bbls/MMcf condensate Optimized 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 20,000+ Boe/d with over 1/3 condensate 18,000+ Boe/d existing facility capacity and well inventory (1) May

10 200m+ Inventory Underpinned by Established Development Blocks Pipestone Elmworth Gold Creek Bilbo Middle Montney 'D' Tested 16 Producers Not Tested 3 Producers Middle Montney 'C' Offsetting Production Middle Montney 'B' Not Tested 6 Producers 6 Producers 41 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 Remaining Inventory *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". May

11 Production (Mboe/d) Bilbo Development Block 2 Rigs Drilling 5 New Wells in Q Wells on Production (IP30) South Montney Sales Production Six-well pad. Drilling HZ sections Cumulative-to-Date Bbls/MMcf 5 4 Condensate Butane Propane Sales Gas NGL's C Two-well Pad Equipping T65 Two-well Pad Drilling Bilbo Well Performance NVA Montney New IP30's NVA In-Progress Wells Montney Horizontal Wells NVA Compressor R6W6 Site Connected to Keyera 5 New IP30's in Q1/2017 Average 1,842 Boe/d Including 1,005 Bbl/d condensate Average 2,300m HZ, 40 stages/well Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) C5+ Yield (Bbl/ MMcf) Well Count IP30 6, , IP60 5, , IP90 5, , IP180 4, , IP360 3, May

12 Rate (MMcf/d) Bilbo Development Block Results To-Date and Type Well Economics Bilbo Well Production to-date (1)(2) Bilbo Type Curve Inputs and Economics Currently Piloting Half-Cycle Inputs Original Type Curve Historical Average (3) Hi-Fi Type Curve DCET Capital ($MM) $6.3 $6.6 $8.4 EUR (Raw Gas) (Bcf) EUR (MMBoe) NGL (4) (C3, C4 Bbl/MMcf) CGR (5) (C5+ Bbls/MMcf) Opex ($/Boe) $10.00 $10.00 $10.00 Horizontal Length (m) 1,800 2,000 2,000 Stage Count Type Curve Comparison Plot Original Historical Average Hi-Fi Economics (6)(7)(8)(9) Original Type Curve Historical Average (3) Hi-Fi Type Curve NPV10 ($MM) $6.6 $7.9 $10.1 PIR Payout (Years) ROR (%) 65% 80% 125% 1 Netback ($/Boe) $25.00 $25.00 $25.00 F+D ($/Boe) $6.25 $6.50 $ ,000 2,000 3,000 4,000 5,000 6,000 Cumulative Gas (MMcf) Cap. Efficiency ($/Boed) $10,000 $9,000 $7,000 1 st Year Prod (Boe/d) ,100 1 st Year Cash Flow ($MM) $5.5 $6.3 $10.3 * Refer to the Advisories for our "Economic Input Assumptions" and for the various footnotes referred to above. (6) Pricing Assumptions: WTI (USD/Bbl): $55.00; AECO (C$/GJ): $3.00; Fx (CAD:USD): 1.30:1 May

13 Production (Mboe/d) Elmworth Development Block Volume Ramp In-Progress 22 Wells on Production (IP30) North Montney Sales Production T69 R9W6 Three-well Pad Drilled ERH Pilot up to 2,450m and 50 stages R8W Condensate Butane Propane Cumulative-to-Date Bbls/MMcf Sales Gas NGL's C5+ Four-well Pad Drilling 6 4 T68 2 Well Pad Drilled Hi-Fi Completion Q2 Planned Avg. 50 stages/well 2 0 Record new Elmw IP30 in Q1/17 2,729 Boe/d Including 563 Bbl/d condensate 1,733m HZ, 22 Stages T67 NVA Montney New IP30's NVA In-Progress Wells Montney Horizontal Wells NVA Compressor Site Connected to SemCAMS Raw Gas (Mcf/d) Elmworth Well Performance C5+ (Bbl/d) Total Sales (Boe/d) C5+ Yield (Bbl/ MMcf) Well Count IP30 6, , IP60 5, , IP90 5, , IP180 4, IP360 3, May

14 Rate (MMcf/d) Elmworth Development Block Results To-Date and Type Well Economics Elmworth Well Production to-date (1)(2) Elmworth Type Curve Inputs and Economics Currently Piloting Half-Cycle Inputs Original Type Curve Historical Average (3) Hi-Fi Type Curve 10 Type Curve Comparison Plot Original Historical Average Hi-Fi DCET Capital ($MM) $6.1 $6.1 $8.2 EUR (Raw Gas) (Bcf) EUR (MMBoe) NGL (4) (C3, C4 Bbl/MMcf) CGR (5) (C5+ Bbls/MMcf) Opex ($/Boe) $10.50 $10.50 $10.50 Horizontal Length (m) 1,800 1,800 2,000 Stage Count Economics (6)(7)(8)(9) Original Type Curve Historical Average (3) Hi-Fi Type Curve NPV10 ($MM) $4.6 $4.1 $6.5 PIR Payout (Years) ROR (%) 40% 35% 65% 1 Netback ($/Boe) $20.00 $19.00 $ ,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 Cumulative Gas (MMcf) F+D ($/Boe) $5.25 $5.25 $6.00 Cap. Efficiency ($/Boed) $10,000 $10,000 $7,000 1 st Year Prod (Boe/d) ,200 1 st Year Cash Flow ($MM) $4.5 $4.1 $8.2 * Refer to the Advisories for our "Economic Input Assumptions" and for the various footnotes referred to above. (6) Pricing Assumptions: WTI (USD/Bbl): $55.00; AECO (C$/GJ): $3.00; Fx (CAD:USD): 1.30:1 May

15 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 Pipeline Connected to NVA Elmworth Comp Stn 3-well ERH Pad Wait on completion Hi-Fi Avg. 3300m+ HZ and 55 stages 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 5 existing producers ~4 additional through 2017 Extended-reach Hz (ERH) and High Frac Intensity (Hi-Fi) tests are planned 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 Gamma Porosity % SemCAMS Wapiti Gas Plant NVA Montney New IP30's NVA In-Progress Wells Montney Hz Wells May

16 Rate (MMcf/d) Gold Creek Development Block Results To-Date and Type Well Economics Gold Creek Well Production to-date (1) Gold Creek Type Curve Inputs and Economics Currently Piloting piloting Half-Cycle Inputs Historical Average (3) ERH Type Curve ERH + Hi-Fi Type Curve DCET Capital ($MM) $7.1 $8.4 $10.6 EUR (Raw Gas) (Bcf) EUR (MMBoe) NGL (4) (C3, C4 Bbl/MMcf) CGR (5) (C5+ Bbls/MMcf) New GP Opex ($/Boe) $8.00 $8.00 $8.00 Horizontal Length (m) 2,000 3,000 3,000 Stage Count Type Curve Comparison Plot Economics (6)(7)(8)(9) Historical Average ERH ERH + HiFi Historical Average (3) ERH Type Curve ERH + Hi-Fi Type Curve NPV10 ($MM) $4.2 $7.1 $8.6 PIR Payout (Years) ROR (%) 35% 60% 75% 1 Netback ($/Boe) $24.50 $24.50 $24.50 F+D ($/Boe) $8.00 $7.00 $ ,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 Cumulative Gas (MMcf) Cap. Efficiency ($/Boed) $13,000 $10,000 $8,500 1 st Year Prod (Boe/d) ,250 1 st Year Cash Flow ($MM) $5.0 $7.6 $11.3 * Refer to the Advisories for our "Economic Input Assumptions" and for the various footnotes referred to above. (6) Pricing Assumptions: WTI (USD/Bbl): $55.00; AECO (C$/GJ): $3.00; Fx (CAD:USD): 1.30:1 May

17 Pipestone Highlights Lower MNTN MNTN 'B' Pipestone Development Block Facilities in Planning Phase for 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 License Spud Mid 2017 CNOR 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 is presently planning minimum of one well in 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 May

18 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) $7.1 EUR (Raw Gas) (Bcf) 5.0 EUR (MMBoe) 1.1 CGR (C5+ Bbls/MMcf) 60 Opex ($/Boe) $10.00 Horizontal Length (m) 2,000 Stage Count 25 Source: GeoSCOUT 1,800 1,500 Pipestone Base Type Well Production Profile Pipestone TC Total Prod Pipestone TC Condensate Prod Economics (6)(7)(8)(9) Base Type Curve NPV10 ($MM) $7.5 PIR 1.1 1, Time (Months) Payout (Years) 1.2 ROR (%) 85% Netback ($/Boe) $22.50 F+D ($/Boe) $6.50 Cap. Efficiency ($/Boed) $8,000 * Refer to the Advisories for our "Economic Input Assumptions" and for the various footnotes referred to above. (6) Pricing Assumptions: WTI (USD/Bbl): $55.00; AECO (C$/GJ): $3.00; Fx (CAD:USD): 1.30:1 May

19 ($000) Number of Stages ($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 0 1,000 2, $8 $6 $4 $2 3,000 4,000 5,000 6,000 $ E 2017E 7, Days Montney Drilling & Completion Cost per Stage Operational Highlights $600 $500 $400 $300 $200 $100 Cost per Stage No. of Stages Record three-well pad cost of $5.1 MM per well (DCET) in Elmworth in summer Completed 4 plug and perf style wells: 2 x 40 stage wells, and a 45 and 55 stage well completed For 2017 Plan, we have assumed some service cost pressures will evolve offset by continued annual efficiency gains Well designs continue to evolve longer, more frac stages, more production with less cost per stage $ E 2017E 0 May

20 Cumulative Production (MBoe) Total Sales IP180 (Boe/d) Proven Track Record of Execution ERH and Hi-Fi Completions NVA Extended Reach Montney Horizontals ,500m Hz 23 Stages 3 Wells 2,200m+ avg. 35 stages per well On-stream ,400m Hz 22 Stages ,600m Hz 29 Stages ,700m Hz 32 Stages ,400m Hz 23 Stages 2 Wells 2,300m+ 50 stages per well On-stream ,100m Hz 37 Stages 2,000 1,800 1,600 1,400 1,200 1, Bilbo IP180 vs. Original Type Curve Bilbo ERH Production vs. Original Type Curve (1) Bilbo TC Approx. 2x Yr 1 Prod Type Curve (4.4 bcf, 75 bbl/mmcf) Average Encouraging ERH Results ,000 1,500 2,000 2,500 3,000 3,500 Horizontal Length (m) (1) NuVista's type curve based on Management's best estimates Time (months) May

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 May

22 Montney Raw Gas Capacity (MMcf/d) Montney Capacity (Boe/d) Market Egress Plan In-Place Wapiti Montney Processing Capacity Material Running Room ,000+ Boe/d Montney Processing Capacity Secured 60, , Pipestone 150 Gold Creek 40,000 30, Bilbo 20, ,000 Elmworth Min. Midstream TOP Commitment Downstream Firm Gas Service TOP = NuVista Minimum take-or-pay volume commitment Downstream Firm Gas Service includes priority interruptible service May

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 100% 75% 50% 25% 0% Hedged Henry Hub Floating Chicago Floating California Floating Dawn Floating AECO Floating 3% 6% 4% 20% 16% 11% 29% 27% 18% 14% 24% 64% 8% 14% 27% 15% May

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 7, , , ,000 3,000 2, Floor C$ WTI price of $66.30/Bbl on ~61% of 2017Q2-Q4 net production 1, Q Q Q Q Q Q Q Bbl/d Capped Bbl/d Uncapped Avg. Floor Avg. Ceiling Natural Gas Hedge Position 175, , , ,000 75,000 50,000 25, Floor AECO price of $3.18/Mcf on ~64% of 2017Q2-Q4 net production 2017 Q Q Q Q Q Q Q Q1 GJ/d Capped GJ/d Uncapped GJ/d AECO-NYMEX Basis Avg. Floor Avg. Ceiling May 2017 Basis includes some export capacity to Chicago and California. Includes NYMEX hedges converted to an AECO equivalent price. 23

25 ($MM) ($/BOE) NuVista Operating Results 2017 Guidance Corporate Production (Boe/d) Wapiti Montney Other Properties 30,000 25,484 24,898 25,000 23,451 24,716 26,731 Actual Production (Boe/d) Guidance (Boe/d) Q1 '17 26,731 26,000 29,000 20,000 Q2 '17-26,000 29,000 15,000 10,000 5,000 81% 83% 96% 96% 96% 96% Q3 '17-26,000 29,000 Q4 '17-32,500 35,000 - Q1 '16 Q2 '16 Q3 '16 Q4 '16 Q1 '17 FY ,000 31,000 Corporate Funds from Operations $60 $55 Funds from Operations ($MM) Funds from Operations ($/Boe) $50 $17.90 $17.98 $16.69 $45 $40 $13.06 $13.65 $35 $30 $25 $20 $15 $10 Q1 '16 Q2 '16 Q3 '16 Q4 '16 Q1 '17 $25 $20 $15 $10 $5 $0 Q Capex ($MM) 2017 Capex Guidance Range ($MM) $107.2 $280-$300 Q Funds from Operations ($MM) 2017 Funds from Operations Guidance Range ($MM) $43.3 $160-$180 May

26 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 Through 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 We have the Assets We have the Will We have the Team We have the Strategy To Deliver May

27 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 typecurves 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 (NuVista has not yet drilled a well in the Pipestone development block). 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, 2015 for the Bilbo and Elmworth development blocks had a lower estimate of estimated ultimate recovery than the type curves presented herein. Due to the early stages of development of the Pipestone and Gold Creek development blocks no reserves were attributed to such development blocks as of December 31, The type curves presented fall into several categories: (i) Base (or initial); (ii) Historical Average; (iii) Optimized, (iv) ERH; (v) Hi-Fi; and (vi) 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 Optimized type curve represents the best potential type curve NuVista expects is achievable if NuVista fully optimizes its drilling operations in such development blocks. 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. May

28 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, 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 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. May

29 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 GAPP measure, please see NuVista's management's discussion and analysis for the year ended December 31, 2016 and three months ended March 31, RESERVES DISCLOSURE The reserves estimates prepared herein have been evaluated by an independent qualified reserves evaluator in accordance with NI 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) Production groupings based off spud dates (3) Economics based on average historical well performance with current well cost estimate (4) NGL yield represents the equivalent constant yield for the full life of the well (5) CGR yield represents the equivalent constant yield for the full life of the well (6) Pricing Assumptions: WTI (USD/Bbl): $55.00; AECO (C$/GJ): $3.00; Fx (CAD:USD): 1.30:1 (7) Price case flat on a real basis; costs inflated at 2% per annum (8) NGL's as % of WTI: C3 35%, C4 65%; C5+ = WTI +$2 (9) Unit transportation costs: sales gas $0.20/Mcf, recovered liquids: $6/Bbl May

30 APPENDIX May

31 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 $ $ $ $ See Advisory Regarding Reserve Disclosure May

32 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 $ Gross Montney Well and Location Count by Year Montney Well and Location Count Breakdown (Gross) Bilbo Elmworth Gold Creek Pipestone Other* PDP Offsets Total * Includes wells outside of our defined development blocks See Advisory Regarding Reserve Disclosure Offsets Locations PDP Wells May

33 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 May

34 Lower Montney Activity NuVista Data Collection In Progress R9W6 R7W6 R5W6 R3W6 T70 T68 Pipestone NVA W6 Vertical Over-pressured 133 Bbls/MMcf C5+ Elmworth ACL W6 CTD: 1.1 bcf, Test CGR: 54 Gold Creek SCL W6 Tested: 1.9 MMcf/d and 174 bpd C5+ SCL W6 CTD: 0.1 bcf, Current CGR: 100 Velvet W6 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/ W6 CTD: 0.8 bcf, IP30 CGR: 85 South Wapiti SCL W6 Confidential until Sep 2017 Bilbo Karr 7Gen W6 CTD: 0.2 bcf, 43 mbbl C5+, CGR: 233 7Gen W6 CTD: 0.3 bcf, Current CGR: 305 NuVista first horizontal test well now sanctioned for spud late in 2017 T64 SCL W6 Tested: 9 MMcf/d and 302 bpd C5+ 7Gen 02/ W6 Tested 800 Mcf/d, 428 bpd C5+ Kakwa T62 NVA Lands Montney Hz Wells LWR Montney 'A' Wells LWR Montney 'A' Cores May