Corporate Presentation. March 2018

Transcription

1 Corporate Presentation March 218

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; 217 and 218 full-year production guidance (including mix of production from different areas); 217 and 218 full-year capital investment guidance; expectation of ability to grow production to 6, Boe/d; expectation of wellhead-to-market egress plans; expectation of firm egress for 1% of up to 6, Boe/d of production; expectation of 6% 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 1 years; expected 217 and 218 adjusted funds flow ranges and net debt to adjusted funds flow ratios; expected expenditures associated with 218 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 217 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 ( This presentation also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about our prospective results of operations and adjusted funds flow, 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. March 218 1

3 NuVista Snapshot NuVista Corporate Info Grande Prairie TSX Trading Symbol: NVA Market Capitalization: ~$1.5 billion Basic Shares Outstanding (1) : 174 million Credit Facility Capacity (1) : $31 million Percent Drawn (2) : 41% Net Debt/Annualized Adjusted Funds Flow (2) :.6x NuVista Wapiti Montney Project 218 Guidance FY Average Production: FY Capital Investment: FY Adjusted Funds Flow (3) : 35, 4, Boe/d $27 $31 million $2 $23 million Edmonton Production (MBoe/d) 4 3 Non-Core Areas Calgary % 27% 25% 5% 17% 75% 9% 97% 99% 213* E Wapiti Montney Wapiti Sweet Other March As at Dec. 31, Dec 31, 217 net debt to Q417 Annualized Adjusted Funds Flow See "Non-GAAP Measurements" Pricing Assumptions: US$3./MMBtu NYMEX and US$55/Bbl WTI * Pro-forma 213 Divestitures

4 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 6, Boe/d Inventory Underpinned by Four Established Development Blocks Wellhead-to-Market Egress Plan In-Place + Rolling Hedging Program 3%+ Condensate Production Torque to Oil Price Proven Track Record of Execution & Continuous Improvement March 218 3

5 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 1% of our 6, Boe/d Plan 6-7% of revenue from condensate, strong hedging program and natural gas sales to all points North America Midstream plant to take us to 6, Boe/d already approved and under construction for 219 startup March 218 4

6 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* > 9 Industry Montney HZ wells licensed and/or drilled to date Montney gas production exceeding 1. Bcf/d T7 T69 T68 Elmworth to Kakwa Production Growth* T67 1 Cal Gas Rate Prod Well Count 75 T T T NuVista Encana Paramount Sinopec-Daylight CNRL Seven Generations Shell T63 T62 Montney Licenses and Hz Wells R8W6 R7W6 R6W6 R5W6 R4W6 R3W6 R2W6 * Excludes southern areas of Alberta Condensate-rich Montney (Resthaven and Simonette). Map is an estimate of Industry land positions compiled from public data. The information in this slide constitutes analogous information. See Advisory Regarding Oil and Gas Information. March 218 5

7 Funded Growth Plan Strong Growth with Managed Net Debt to Adjusted Funds Flow Capital Expenditure Guidance Range ($MM) Production Guidance Range (MBoe/d) $ $3 $2 $273 $189 $315 $31 $ $1 215A 216A 217A 218E 1 215A 216A 217A 218E Adjusted Funds Flow Guidance Range (1)(2) ($MM) Net Debt/Annual Adjusted Funds Flow (1)(2) $25 $23 3.x $2 $2 2.x $15 $1 $125 $138 $2 1.x $5 215A 216A 217A 218E (1) Assumptions: 218: US$55/Bbl WTI; US$3./MMBtu NYMEX; 1.25:1. C$:USD (2) Adjusted Funds Flow. See "Non-GAAP Measurements"..x 215A 216A 217A 218E March 218 6

8 218 Guidance Strong Year-over-Year Growth and Capital Flexibility 218 Capex Range ($MM) Flexibility to adjust Flexibility to adjust ~$12M of 218 capex without capex without impacting 218 impacting annual production production $85 $6 $ Production Adds Activity 219 Growth Activity Long Term Investment, Maintenance and Other 218 Capex Guidance: $27 $31MM 218 Production Guidance: 35, 4, Boe/d Highlights: ~3-4 Active rigs in 218 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 ~25-3% production growth YoY 218 vs. 217 *Long term investments include Pipestone long lead-time compression, water sourcing and disposal infrastructure, and science projects March 218 7

9 Line-of-Sight to 6,+ Boe/d Four Development Blocks Established Piestone Pipestone Emerging Dev Block Four layer development potential in the Montney Initial type-curve 5. Bcf, 6+ Bbls/MMcf condensate (range 45 to 15+ Bbls/MMcf) First Well Successfully tested Forecast production ~27% condensate 1, Boe/d expected facility capacity and well inventory (1) Elmworth Free Cashflow Elmworth Generation Hi-Fi Type-Curve 7. Bcf, 4 Bbls/MMcf condensate Existing NVA owned compression and long-term firm service agreement for 1% of volumes Current Production up to 16,+ Boe/d with ~23% condensate 16,+ Boe/d existing facility capacity and well inventory (1) Gold Creek On Production Hi-Fi Type-Curve 6. Bcf, 6 Bbls/MMcf condensate (range 4 to 15+Bbls/MMcf) NVA footprint provides optionality in well length (ERH) Full Development into 219 SemCAMS Wapiti Gas Plant Current Production ~4, boe/d Forecast production ~27% condensate 18, Boe/d expected facility capacity and well inventory (1) Bilbo Free Cashflow Generation Hi-Fi Type-Curve 5. Bcf, 75 Bbls/MMcf condensate Existing NVA owned compression and long-term firm service agreement for 1% of volumes Current Production ~18, Boe/d with over 1/3 condensate 18,+ 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 1 years; refer to slides 24 & 25 for our existing midstream capacity and licensed Wapiti area gas plants. March 218 8

10 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 March 218 9

11 2m+ Inventory Underpinned by Established Development Blocks Pipestone Elmworth Gold Creek Bilbo Middle Montney 'D' Tested Middle Montney 'C' NVA Test and Offsetting Production 24 Producers Not Tested 5 Producers Middle Montney 'B' Tested 6 Producers 8 Producers 5 Producers Lower Montney Multiple Industry Tests Significant Future Potential 1 Producer Inventory (Based on Zones Tested to date) Pipestone (C) Elmworth (B&C) Gold Creek (B) Bilbo (B&C) Lower Montney Total NVA NVA Producers Remaining Inventory Still establishing Type Curve *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 217 Proved Plus Probable locations (including producers) was 364. Certain information in this slide constitutes analogous information. See "Advisory Regarding Oil and Gas Information". March

12 NuVista Reserves Solid And Growing Underlying Reserves Foundation 217 Year-end Reserve Highlights Significant growth in PDP reserves and NPVBT1, a YoY increase of 43% to 54 MMBoe and 36% to $53MM, respectively, which serves as a solid foundation for near-term production and cashflow generation TP+PA reserves and NPVBT1 increased materially YoY, up 35% to 347 MMBoe and 53% to $1.8Bn, respectively, a recognition of the inventory that backstops our growth plan to 6, Boe/d Robust PDP and TP+PA F&D at $11.35/Boe and $6.95/Boe driven by positive technical revisions and continued improvement in our Montney development drilling Condensate now 27% of NuVista's PDP reserves (up from 25% last year) Total Montney PDP Wells increased to 96 (gross) TP+PA well count (incl. PDP) now 379 (gross) NuVista PDP Reserves (MMBoe) NuVista PDP NPVBT1 ($MM) 6 5 Non-Montney Bilbo Elmworth Gold Creek $6 $5 Non-Montney Bilbo Elmworth Gold Creek 4 $4 3 $3 2 $2 1 $ See Advisory Regarding Reserve Disclosure $ March

13 NuVista Reserves 217 Year-end Reserves Report Montney 'C' Reserves* Montney 'B' Reserves* NuVista F&D Costs ($/Boe) $25 $2 PDP F&D TP+PA F&D $15 $1 $5 $ Gross Montney Well and Location Count by Year Montney Well and Location Count Breakdown (Gross) Bilbo Elmworth Gold Creek Pipestone Total NVA Proved Developed Undeveloped Locations Total See Advisory Regarding Reserve Disclosure * Refers to TP+PA Reserves Undeveloped Locations Proved Developed Wells March

14 Production (Mboed) Bilbo Development Block Free-Cashflow Positive 56 Wells on Production (IP3) 2 15 South Montney Sales Production Cumulative-to-Date Bbls/MMcf 5 4 C5+ Butane Propane Sales Gas NGL's C T65 2-well Pad On Production Q1 2-well Pad x2 Completing Bilbo Well Performance Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) C5+ Yield (Bbl/ MMcf) Well Count NVA Montney New IP3's NVA In-Progress Wells Montney Horizontal Wells NVA Compressor R6W6 Site Connected to Keyera Lower Montney IP3: 3.6 MMcf/d Raw Gas 665 Bbls/d C5+ IP3 6, , IP6 5, , IP9 4, , IP18 4, , IP36 3, March

15 Total Sales (Boe/d) Capital Costs / 1m hz ($) Bilbo Development Block Performance Update: Getting More for Less Bilbo IP9 Production and DCET Capital Cost Condensate (Bbl/d) Total Sales (Boe/d) 1-well Total Sales Mov. Avg. 3, 2,5 1-well Condensate Mov. Avg. 1-well Capital Cost Mov. Avg. Hi-FI Wells Bilbo NE 6-Well Pad 25% shorter hz length vs. Bilbo 2,m avg. IP9 C5+ prod of 6 Bbl/d 1% above Bilbo avg. 1,2 1, 2, 8 1,5 6 1, On Production Year 217 March

16 NYMEX NYMEX Rate (MMcf/d) NYMEX Bilbo Development Block Results To-Date and Type Well Economics 1 Type Curve Comparison Plot Original Historical Average Hi-Fi Hi-Fi Type Curve Economic Sensitivities Payout (Years) WTI $55/Bbl $6/Bbl $65/Bbl $2.7/MMBtu $3.1/MMBtu $3.5/MMBtu , 2, 3, 4, 5, 6, Cumulative Gas (MMcf) Rate of Return WTI $55/Bbl $6/Bbl $65/Bbl $2.7/MMBtu 65% 85% 11% Hi-Fi Type Curve Production Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) IP9 7, 525 1,64 IP18 6, ,53 IP36 4, ,136 Hi-Fi Type Curve Inputs DCET Capital ($MM) $8.6 EUR (Raw Gas) (Bcf) 5. EUR (MMBoe) 1.2 CGR (C5+ Bbls/MMcf) 75 Opex ($/Boe) $1. Horizontal Length (m) 2, Stage Count 4 $3.1/MMBtu 85% 11% 13% $3.5/MMBtu 11% 135% 16% Net Present 1% ($MM) WTI $55/Bbl $6/Bbl $65/Bbl $2.7/MMBtu $6.5 $7.9 $9.3 $3.1/MMBtu $8. $9.5 $1.8 $3.5/MMBtu $9.5 $11. $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 March

17 Production (Mboed) Elmworth Development Block Significant New Results Hi-Fi Coming Through 3 Wells on Production (IP3) North Montney Sales Production 2 15 C5+ Butane Propane Cumulative-to-Date Bbls/MMcf Sales Gas NGL's C5+ 4-well pad Drilling Piloting 3T/m completions and cemented Liners 1 5 Elmworth Well Performance Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) C5+ Yield (Bbl/ MMcf) Well Count NVA Montney New IP3's NVA In-Progress Wells Montney Horizontal Wells NVA Compressor Site Connected to SemCAMS IP3 7, , IP6 6, , IP9 6, , IP18 4, IP36 3, March

18 Total Sales (Boe/d) Capital Costs / 1m hz ($) Elmworth Development Block At a Tipping Point: Encouraging Recent Well Results Elmworth IP3 Production and DCET Capital Cost Condensate (Bbl/d) Total Sales (Boe/d) 1-well Total Sales Mov. Avg. 3,5 1-well Condensate Mov. Avg. 1-well Capital Cost Mov. Avg. Hi-FI Wells 8 3, 7 2,5 6 2, 1,5 1, On Production Year March

19 NYMEX NYMEX Rate (MMcf/d) NYMEX Elmworth Development Block Results To-Date and Type Well Economics 1 Type Curve Comparison Plot Original Historical Average Hi-Fi Hi-Fi Type Curve Economic Sensitivities Payout (Years) WTI $55/Bbl $6/Bbl $65/Bbl $2.7/MMBtu $3.1/MMBtu $3.5/MMBtu , 2, 3, 4, 5, 6, 7, 8, Cumulative Gas (MMcf) Rate of Return WTI $55/Bbl $6/Bbl $65/Bbl $2.7/MMBtu 3% 4% 5% Hi-Fi Type Curve Production Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) IP9 7, 28 1,37 IP18 7, 28 1,37 IP36 6, ,174 Hi-Fi Type Curve Inputs DCET Capital ($MM) $8.4 EUR (Raw Gas) (Bcf) 7. EUR (MMBoe) 1.4 CGR (C5+ Bbls/MMcf) 4 Opex ($/Boe) $1.5 Horizontal Length (m) 2, Stage Count 4 $3.1/MMBtu 4% 55% 65% $3.5/MMBtu 6% 75% 9% Net Present 1% ($MM) WTI $55/Bbl $6/Bbl $65/Bbl $2.7/MMBtu $2.6 $3.7 $4.8 $3.1/MMBtu $4.4 $5.5 $6.5 $3.5/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 March

20 Lower MNTN MNTN 'B' MNTN 'C' Gold Creek Development Block Initial Type-Curve Established Early Development Activity and Infrastructure Gold Creek Highlights Gold Creek Geology Gold Creek Step-out Drilled & Tested Q218 Tie-in Up to 3 developable layers Condensate yield expected to average 6+ Bbls/MMcf (range 4 to 15+) Initial type-curve raw gas EUR average 4.+ Bcf Gamma Porosity % 2 8 existing producers ~4 additional wells on-stream through Early Development through Elmworth Compressor Full-field Development into 219 SemCAMS Wapiti Gas Plant 2-well Pad Completing (ERH + Hi-Fi) Majority of development does not require additional compression infrastructure Lower Opex Gold Creek IP3's Gold Creek IP9's 219 SemCAMS Wapiti Gas Plant NVA Montney New IP3's NVA In-Progress Wells Montney Hz Wells Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) C5+ Yield (Bbl/ MMcf) First 5 Well Avg 5,4 48 1, Pad Avg 6, , Hi-Fi + ERH Avg 6, , Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) C5+ Yield (Bbl/ MMcf) First 5 Well Avg 4, Pad Avg 5, , Hi-Fi + ERH Avg 5, , March

21 NYMEX NYMEX Rate (MMcf/d) NYMEX Gold Creek Development Block Results To-Date and Type Well Economics 1 Type Curve Comparison Plot Historical Average ERH ERH + HiFi Hi-Fi Type Curve Economic Sensitivities Payout (Years) WTI $55/Bbl $6/Bbl $65/Bbl $2.7/MMBtu $3.1/MMBtu $3.5/MMBtu , 2, 3, 4, 5, 6, 7, 8, Cumulative Gas (MMcf) Rate of Return (Pct.) WTI $55/Bbl $6/Bbl $65/Bbl $2.7/MMBtu 4% 5% 65% Hi-Fi Type Curve Production Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) IP9 7, 42 1,545 IP18 7, 42 1,545 IP36 5, ,254 Hi-Fi Type Curve Inputs DCET Capital ($MM) $1.8 EUR (Raw Gas) (Bcf) 6. EUR (MMBoe) 1.3 CGR (C5+ Bbls/MMcf) 6 New GP Opex ($/Boe) $8. Horizontal Length (m) 3, Stage Count 6 $3.1/MMBtu 5% 65% 8% $3.5/MMBtu 7% 8% 1% Net Present 1% ($MM) WTI $55/Bbl $6/Bbl $65/Bbl $2.7/MMBtu $4.9 $6.3 $7.6 $3.1/MMBtu $6.5 $7.9 $9.2 $3.5/MMBtu $8.1 $9.4 $1.7 * 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 March 218 2

22 Lower MNTN MNTN 'B' Pipestone Development Block Facilities in Planning Phase for Development Pipestone Activity Pipestone Highlights Pipestone Geology ECA Pipestone Condensaterich Development ECA Pipestone 'Super- Condensate' NVA Hz Successful Test Final 24-hr rate: 6 MMcf/d Gas >1 Bbls/MMcf C5+ CNOR Hz Initial Test 278 Bbls/MMcf C5+ Up to 4 developable layers Acreage to the West extensively developed by EnCana Condensate yield expected to average 6+ Bbls/MMcf (Range of 45 to 15+) Type-curve raw gas EUR expected to average 5. Bcf (Range of 3. to 7. Bcf) NVA successfully tested first Pipestone well in full-field development including compressor station and pipeline to new SemCAMS Wapiti plant MNTN 'C' MNTN 'D' Gamma Porosity 2 Montney 'D' Hz Wells Montney 'C' Hz Wells Montney 'B' Hz Wells Future NVA Compressor and Pipeline to SemCAMS Wapiti Gas Plant *Map of activity at Pipestone is compiled from public data March 218 Certain information in this slide constitutes analogous information. See "Advisory Regarding Oil and Gas Information". 21

23 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) $7. EUR (Raw Gas) (Bcf) 5. EUR (MMBoe) 1.1 CGR (C5+ Bbls/MMcf) 6 Opex ($/Boe) $1. Horizontal Length (m) 2, Stage Count 25 Source: GeoSCOUT 1,8 1,5 Pipestone Base Type Well Production Profile Pipestone TC Total Prod Pipestone TC Condensate Prod Economics Base Type Curve NPV1 ($MM) $7.5 PIR 1.1 1, Time (Months) Payout (Years) 1.2 ROR (%) 85% Netback ($/Boe) $22. F+D ($/Boe) $6.5 Cap. Efficiency ($/Boed) $8, * Refer to the "Advisory Regarding Oil and Gas Information" and "Economic Input Assumptions". * Pricing Assumptions: WTI (USD/Bbl): $6.; NYMEX (USD/MMBtu): $3.1; Fx (CAD:USD): 1.25:1 March 218 Certain information in this slide constitutes analogous information. See "Advisory Regarding Oil and Gas Information". 22

24 ($) Number of Stages ($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 $1 $8 1, 2, $6 3, $4 4, $2 5, $ E 218E 6, Montney Drilling & Completion Cost per Stage Operational Highlights $6 $5 $4 $3 $2 Cost per Stage No. of Stages Executed a Gold Creek 3 well pad with 164 stages: longest well was drilled to 3,85m lateral length (6,7m MD) and a 71 stage completion Elmworth in 217 drilled and completed 9 wells (5 Hi-Fi) for ~$215k/stage Successful transition to plug & perf 12 wells completed with over 4 stages $1 $ E 218E 1 For 217 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 March

25 Wellhead-to-Market Egress Plan In-Place Firm Egress Counts: Long-Term Growth Secured NuVista North Compressor Station (5% WI) Gross Raw Gas Capacity: 35 MMcf/d Grande Prairie SemCAMS Wapiti Sour Gas Plant Status: Under Construction 219 Startup Raw Gas Capacity: 2 MMcf/d Condensate Capacity: 2, Bbl/d CNRL Gold Creek Plant Keyera Wapiti Sour Gas Plant Status: Under Construction Raw Gas Capacity: 3 MMcf/d Condensate Capacity: 25, Bbl/d NuVista Elmworth Compressor Station (1% WI) Raw Gas Capacity: 8 MMcf/d Condensate Capacity: 4, Bbl/d NuVista Bilbo Compressor Station (1% WI) Raw Gas Capacity: 8 MMcf/d Condensate Capacity: 8, 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 March

26 Montney Raw Gas Capacity (MMcf/d) Montney Capacity (Boe/d) Market Egress Plan In-Place Wapiti Montney Processing Capacity Material Running Room 3 6,+ Boe/d Montney Processing Capacity Secured 6, 25 5, 2 Pipestone 15 Gold Creek 4, 3, 1 Bilbo 2, 5 1, 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 March

27 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 1% 1% 13% 2% 2% 15% 15% 75% 5% 25% 12% 6% 2% 66% 27% 13% 7% 17% 22% 15% 5% 38% 18% 17% 14% 13% 3% 5% 5% 5% % 16% March

28 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 9, 8, 7, 6, 5, 4, 3, 2, 1, 218 Q1 218 Q2 218 Q3 218 Q4 219 Q1 219 Q2 219 Q3 219 Q Floor C$ WTI price of $69.91/Bbl on ~64% of 218 net production Bbl/d Capped Bbl/d Uncapped Avg. Floor Avg. Ceiling Natural Gas Hedge Position 125, 4.5 1, , 5, Floor AECO price of $2.7/Mcf on ~66% of 218 net production 25, Q1 218 Q2 218 Q3 218 Q4 219 Q1 219 Q2 219 Q3 219 Q4 GJ/d Capped GJ/d Uncapped Avg. Floor Avg. Ceiling March 218 Natural gas hedges include some NYMEX and Dawn hedges converted to an AECO equivalent price. 27

29 Natural Gas Sales Points Q4 217 Diversification Counts Grande Prairie AECO $1.96 Market Price Market Netback $2.66 $2.85 $2.69 Dawn $3.75 Malin* $3.34 Chicago $3.7 All prices in C$/mcf Market Netback = Market Price less tolls (including fuel) FX at C$/US$ at Based on Q417 average prices *NVA service commences early-mid 218 Henry Hub $3.73 March

30 ($MM) ($/BOE) NuVista Operating Results 217 Guidance Delivered Corporate Production (Boe/d) Wapiti Montney Other Properties 4, 35, 3, 25, 24,716 26,731 25,454 29,45 37,435 Actual Production (Boe/d) Guidance (Boe/d) Q1 '17 26,731 26, 29, Q2 '17 25,454 22,5 25, 2, 99% 15, 98% 1, 96% 96% 97% 96% 5, - Q4 '16 Q1 '17 Q2 '17 Q3 '17 Q4 '17 Adjusted Funds flow Adjusted Funds Flow ($MM) Adjusted Funds Flow ($/Boe) $8 $22.6 $25 Q3 '17 29,45 26, 29, Q4 '17 37,435 35, 38, FY217 29,783 28, 31, 217 Capex ($MM) 217 Capex Guidance Range ($MM) $6 $17.9 $17.98 $16.98 $15.36 $2 $315 $28-$3 $4 $2 $15 $1 $5 217 Adjusted Funds Flow ($MM) 217 Adjusted Funds Flow Guidance Range ($MM) $ Q4 '16 Q1 '17 Q2 '17 Q3 '17 Q4 '17 $ $2 $16-$18 March

31 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 6, Boe/d Inventory Underpinned by Four Established Development Blocks Wellhead-to-Market Egress Plan In-Place + Rolling Hedge Program 3%+ 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 March 218 3

32 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, 217 for the Bilbo, Elmworth, Pipestone and Gold Creek development blocks had a lower estimate of estimated ultimate recovery than the type curves presented herein; however, the production forecasts in such independent reserves evaluation are also lower than NuVista's current production as well as the production forecasts prepared by management. The type curves presented fall into several categories: (i) Base (or Initial); (ii) Historical Average; (iii) ERH; (iv) Hi-Fi; and (v) ERH +Hi-Fi; the expectations for each type curve differ as a result of varying horizontal well length, stage count and stage spacing. The Base or Initial type curve represents the average type curve expected. Historical Average is the average type curve achieved from the wells previously drilled by NuVista in the area. The ERH type curves represents NuVista's expected type curve from drilling extended reach horizontal wells. The Hi-Fi type curves represents NuVista's expected type curve from utilizing high fracture intensity techniques on wells and ERH + Hi-Fi type curves are the expected type curves from combining extended reach horizontal with high-fracture intensity. NuVista is still in the early days of piloting extended reach horizontals and high intensity facture techniques and as such there is no certainty that such results will be achieved or that NuVista will be to optimize such drilling results to achieve the optimized type curves described. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented; however, there is no certainty that NuVista will ultimately recover such volumes from the wells it drills. In presenting such type curves, inputs and economics information, NuVista has used a number of oil and gas metrics which do not have standardized meanings and therefore may be calculated differently from the metrics presented by other oil and gas companies. Such metrics include DCET, "EUR", "NPV1", "PIR", "payout", "rate of return" (or "ROR"), "netback", "F&D", "capital efficiency", "recycle ratio" and "reserves life index". Development well capital includes all capital spent to drill, complete, equip and tie-in a well. EUR represents the estimated ultimate recovery of resources associated with the type curves presented. NPV 1 represents the anticipated net present value of the future net revenue discounted at a rate of 1% associated with the type curves presented. PIR (Profit to Investment Ratio) is the ratio of the NPV 1 relative to the DCET. Payout means the anticipated years of production from a well required to fully pay for the DCET of such well. ROR means the rate of return of a well or the discount rate required to arrive at a NPV equal to zero. Netback equals total revenues on a BOE basis (excluding realized commodity derivative gains/losses) less royalties, transportation and operating costs. F&D is the anticipated full exploration and development costs associated with each barrel of oil equivalent expected to be recovered from a well based on the type curves and economics presented. Historical F&D is calculated based on exploration and development capital spent in a period plus the change in future development capital associated with the Company's reserves divided by the reserves additions. Capital efficiency is a measure of expected development well capital divided by average first year production results (IP365) from such well based on the type curve presented. Recycle ratio is a measure of the netback achieved on a barrel of oil equivalent divided by the associated F&D costs for such barrel of oil equivalent. Reserves life is a measure of the volume of the Company's reserves divided by the annual average production. March

33 Advisory Regarding Oil and Gas Information ADVISORY REGARDING OIL AND GAS INFORMATION This presentation discloses NuVista's drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the GLJ Reserves Report and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 45 net drilling locations identified herein, 135 net are proved locations, 123 net are probable locations and 147 net are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves or production. Certain information in this presentation may constitute "analogous information" as defined in National Instrument Standards of Disclosure for Oil and Gas Activities with respect to the certain drilling results, total production in the Montney, number of wells drilled, or offset well production from other producers with operations that are in geographical proximity to or believed to be on-trend with NuVista's Montney assets. Management of NuVista believes the information may be relevant to help determine the expected results that NuVista may achieve within NuVista's lands and such information has been presented to help demonstrate the basis for NuVista's business plans and strategies with respect to its Montney assets. There is no certainty that the results of the analogous information or inferred thereby will be achieved by NuVista and such information should not be construed as an estimate of future production levels, reserves or the actual characteristics and quality of NuVista's Montney assets. It should not be assumed that the future net revenues (NPV1) 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. March

34 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 adjusted funds flow, net debt to annualized adjusted funds flow 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 adjusted funds flow 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, 217 and three months ended December 31, 217. 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, 217 and is based on an independent evaluation by GLJ using January 1, 218 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 = 3%; C4 = 65%; C5+ = WTI +US$2/Bbl (6) Gas price offset reflects NuVista's aggregate egress pipeline tolls and a $US1.5/MMBtu AECO to NYMEX basis (7) Recovered liquids unit transportation cost: C$6/Bbl March