corporate presentation - nuvista energy...corporate presentation may 2017 . advisory regarding...
TRANSCRIPT
Corporate Presentation
May 2017
Advisory Regarding Forward-Looking
Information and Statements
May 2017 1
This presentation contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “will”, “expects”, “believe”, “plans”, “potential” and similar expressions are intended to identify forward-looking statements or information. More particularly and without limitation, this presentation contains forward-looking statements and information concerning: NuVista's future strategy, focus and opportunities; 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 (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.
NuVista Snapshot
May 2017 2
Production (MBoe/d)
27% 50%
75% 90%
95+%
28%
25%
17%
0
5
10
15
20
25
30
35
2013* 2014 2015 2016 2017E
Wapiti Montney Wapiti Sweet Other
TSX Trading Symbol: NVA
Market Capitalization: ~$1.0 billion
Basic Shares Outstanding(1): 172.8 million
Credit Facility Capacity(1): $235 million
Percent Drawn(1): 26%
Net Debt/Funds from Operations(2): 0.9x
2017 Guidance
FY Average Production: 28,000 – 31,000 Boe/d
FY Capital Investment: $280 – $300 million
FY Funds from Operations(3): $160 – $180 million
NuVista Corporate Info
Grande Prairie
Edmonton
Calgary
NuVista Wapiti Montney Project
Non-Core Areas
1 As at May 1, 2017 2 March 31, 2017 net debt to Q117 Annualized Funds from Operations. See "Non-GAPP Measurements". 3 2017 Pricing Assumptions: $3/GJ AECO and US$55/Bbl WTI * Pro-forma 2013 Divestitures
Why Buy NuVista?
Trusted Repeatable Growth
May 2017 3
Pure-Play Montney Company – In The Right Neighborhood Funded Growth Plan Through 2018+ 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 2017 4
• High level of industry activity continues
• > 900 Montney HZ wells licensed and/or drilled to date
• Montney gas production exceeding 0.9 Bcf/d
Elmworth to Kakwa Montney HZ Activity Update*
Elmworth to Kakwa Production Growth*
NuVista Encana Paramount Sinopec-Daylight CNRL Seven Generations Shell Apache Montney Licenses and Hz Wells R6W6 R4W6 R2W6 R8W6
T65
T62
T67
T69
T70
T68
T66
T64
T63
R5W6 R3W6 R7W6
*Excludes southern areas of Alberta Condensate-rich Montney (Resthaven and Simonette). Map is an estimate of Industry land positions compiled from public data.
Montney – In The Right Neighborhood Condensate-Rich Montney Industry Growth Continues
0
100
200
300
400
500
600
700
0
100
200
300
400
500
600
700
800
900
1000
Pro
d W
ell
Co
un
t
Cal
Day
Gas
Avg
(M
Mcf
/d)
Cal Gas Rate
Prod Well Count
Montney – In The Right Neighborhood The Alberta Condensate-Rich Montney: A World Class Play
May 2017 5
1. Scalable/Repeatable
• Deposition on the shelf edge – not isolated pockets
• Gas charged top to bottom • Over-pressured – low water saturation
2. Porous and Permeable
• Hydrocarbon filled porosity up to 9% (typically 4-5%)
• Sand/silt reservoir exhibits much better permeability
3. Condensate-rich
• High liquids and condensate demonstrated in all our wells to date
4. Thick Formation
• 150 – 200 metres • Multiple developable layers of resource
HIGH QUALITY
RESERVOIR
150-200M THICK
CONDENSATE RICH
OVERPRESSURED
Funded Growth Plan Strong Growth with Managed Debt-to-Cashflow
May 2017 6
28.0 35.0
10
20
30
40
50
2015A 2016A 2017E 2018E
Upside Case Base Case
Capital Expenditures ($MM) Production (MBoe/d)
(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".
$280
$100
$200
$300
$400
2015A 2016A 2017E 2018E
Upside Case Base Case
Funds from Operations(1)(2) ($MM) Net Debt:Funds from Operations(1)(2)
$160
$215
$50
$100
$150
$200
$250
2015A 2016A 2017E 2018E
Upside Case Base Case
$189
$273
22.4 24.6
$300
31.0
$125 $138
$180
0.0x
1.0x
2.0x
3.0x
2015A 2016A 2017E 2018E
Base Pricing
$330
$280
$250
40.0
May 2017 7
24.7
26.7
32.5-35.0
60
80
100
120
10
20
30
40
Q416A Q117A Q217E Q317E Q417E
Pro
du
ctiv
e M
on
tne
y W
ell
Co
un
t
Pro
du
ctio
n (
MB
oe
/d)
Guidance Range Well CapabilityWells Capable of Production
Production & Productive Well Count Forecast 2017E Capex Range ($MM)
~$230-240
~$50-60
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 2018
2017 Capex Guidance: $280 – $300MM
DCET & Well Optimization
Facilities, Water & Other
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
2017 Production Guidance: 28,000 – 31,000 Boe/d
Q1-Q3: 26.0-29.0 MBoe/d
2017 Funds from Operations Guidance(1)(2): $160 – $180MM
Funded Growth Plan Strong Production Ramp in Q4 After Planned Outages
(1)Commodity Price Assumptions: US$55/Bbl WTI; C$3.00/GJ AECO; 1.30:1.0 C$:USD Fx (2) See "Non-GAAP Measurements".
Line-of-Sight to 60,000+ Boe/d Four Development Blocks Established
May 2017 8
Piestone • Four layer development potential in the
Montney
• Initial type-curve 5.0 Bcf, 60+ Bbls/MMcf condensate (range 45 to 150+ Bbls/MMcf)
• 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)
Pipestone – Emerging Dev Block
Elmworth
• 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)
Elmworth – 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)
Gold Creek – On Production
• 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)
Bilbo – Free Cashflow Generation
(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.
May 2017 9
Inventory (Based on Zones Tested to date)
Pipestone (C) Elmworth (B&C) Gold Creek (B) Bilbo (B&C) Total NVA
NVA Producers 0 22 6 44 72
Remaining Inventory 40-50 125 115 140 - 175 420 - 465
Pipestone
Gold Creek
Bilbo
Elmworth
*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".
16 Producers
6 Producers 6 Producers
Not Tested 3 Producers
41 Producers
Middle Montney 'D' Middle Montney 'C'
Middle Montney 'B'
Lower Montney
Not Tested
Offsetting Production
Multiple Industry Tests – Significant Future Potential
Tested
20
0m
+
Inventory Underpinned by Established
Development Blocks
May 2017 10
R6W6
T65
South Montney Sales Production
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
Six-well pad. Drilling HZ sections
Two-well Pad Equipping
44 Wells on Production (IP30)
Two-well Pad Drilling
Bilbo Well Performance
Bilbo Development Block 2 Rigs Drilling – 5 New Wells in Q1 2017
Raw Gas (Mcf/d)
C5+ (Bbl/d)
Total Sales
(Boe/d)
C5+ Yield (Bbl/
MMcf)
Well Count
IP30 6,379 737 1,700 116 44
IP60 5,595 574 1,429 103 40
IP90 5,153 506 1,295 98 39
IP180 4,348 375 1,047 86 36
IP360 3,278 252 762 77 29
0
2
4
6
8
10
12
14
16
18
20
Pro
du
ctio
n (
Mb
oe
/d)
Sales Gas NGL's C5+
81
5 4
Cumulative-to-Date Bbls/MMcf Condensate
Butane
Propane
NVA Montney New IP30's
NVA In-Progress Wells
Montney Horizontal Wells
NVA Compressor Site
Connected to Keyera
Bilbo Development Block Results To-Date and Type Well Economics
May 2017 11
Economics(6)(7)(8)(9) Original
Type Curve Historical Average(3)
Hi-Fi Type Curve
NPV10 ($MM) $6.6 $7.9 $10.1
PIR 1.0 1.2 1.2
Payout (Years) 1.5 1.3 0.9
ROR (%) 65% 80% 125%
Netback ($/Boe) $25.00 $25.00 $25.00
F+D ($/Boe) $6.25 $6.50 $7.00
Cap. Efficiency ($/Boed) $10,000 $9,000 $7,000
1st Year Prod (Boe/d) 600 700 1,100
1st Year Cash Flow ($MM) $5.5 $6.3 $10.3
Bilbo Type Curve Inputs and Economics
Half-Cycle Inputs Original
Type Curve Historical Average(3)
Hi-Fi Type Curve
DCET Capital ($MM) $6.3 $6.6 $8.4
EUR (Raw Gas) (Bcf) 4.4 4.4 5.0
EUR (MMBoe) 1.0 1.0 1.2
NGL(4) (C3, C4 Bbl/MMcf) 11 11 11
CGR(5) (C5+ Bbls/MMcf) 75 75 75
Opex ($/Boe) $10.00 $10.00 $10.00
Horizontal Length (m) 1,800 2,000 2,000
Stage Count 18 20 40
* 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): $3.00; Fx (CAD:USD): 1.30:1
Currently Piloting
0
1
10
0 1,000 2,000 3,000 4,000 5,000 6,000
Rat
e (
MM
cf/d
)
Cumulative Gas (MMcf)
Original Historical Average Hi-Fi
Type Curve Comparison Plot
Bilbo Well Production to-Date(1)(2)
0
2
4
6
8
10
12
Pro
du
ctio
n (
Mb
oe/
d)
Sales Gas NGL's C5+
Elmworth Development Block Volume Ramp In-Progress
May 2017 12
R9W6
T67
T68
R8W6 T69
Three-well Pad Drilled – ERH Pilot up to 2,450m and
50 stages
2 Well Pad Drilled Hi-Fi Completion – Q2
Planned Avg. 50 stages/well
North Montney Sales Production
Elmworth Well Performance
22 Wells on Production (IP30)
Raw Gas (Mcf/d)
C5+ (Bbl/d)
Total Sales
(Boe/d)
C5+ Yield (Bbl/
MMcf)
Well Count
IP30 6,889 337 1,405 49 22
IP60 5,879 282 1,193 48 21
IP90 5,552 259 1,120 47 21
IP180 4,405 193 875 44 19
IP360 3,268 131 641 40 15
39
8
9
Cumulative-to-Date Bbls/MMcf
Condensate
Butane
Propane
NVA Montney New IP30's
NVA In-Progress Wells
Montney Horizontal Wells
NVA Compressor Site
Connected to SemCAMS
Record new Elmw IP30 in Q1/17 2,729 Boe/d
Including 563 Bbl/d condensate 1,733m HZ, 22 Stages
Four-well Pad Drilling
Elmworth Development Block Results To-Date and Type Well Economics
May 2017 13
Economics(6)(7)(8)(9) Original
Type Curve Historical Average(3)
Hi-Fi Type Curve
NPV10 ($MM) $4.6 $4.1 $6.5
PIR 0.8 0.7 0.8
Payout (Years) 2.0 2.3 1.2
ROR (%) 40% 35% 65%
Netback ($/Boe) $20.00 $19.00 $19.00
F+D ($/Boe) $5.25 $5.25 $6.00
Cap. Efficiency ($/Boed) $10,000 $10,000 $7,000
1st Year Prod (Boe/d) 600 600 1,200
1st Year Cash Flow ($MM) $4.5 $4.1 $8.2
Elmworth Type Curve Inputs and Economics
Half-Cycle Inputs Original
Type Curve Historical Average(3)
Hi-Fi Type Curve
DCET Capital ($MM) $6.1 $6.1 $8.2
EUR (Raw Gas) (Bcf) 6.0 6.0 7.0
EUR (MMBoe) 1.2 1.2 1.4
NGL(4) (C3, C4 Bbl/MMcf) 19 19 19
CGR(5) (C5+ Bbls/MMcf) 45 40 40
Opex ($/Boe) $10.50 $10.50 $10.50
Horizontal Length (m) 1,800 1,800 2,000
Stage Count 18 18 40
Currently Piloting
* 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): $3.00; Fx (CAD:USD): 1.30:1
Type Curve Comparison Plot
0
1
10
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000
Rat
e (
MM
cf/d
)
Cumulative Gas (MMcf)
Original Historical Average Hi-Fi
Elmworth Well Production to-Date(1)(2)
Gold Creek Development Block Initial Type-Curve Established – 2016/17 Early Development
May 2017 14
Gold Creek Highlights
• Up to 3 developable layers
• Condensate yield expected to average 60+ Bbls/MMcf (range 40 to 150+)
• Initial type-curve raw gas EUR average 4.0+ Bcf
• 5 existing producers – ~4 additional through 2017
• Extended-reach Hz (ERH) and High Frac Intensity (Hi-Fi) tests are planned
• 2016/17 Early Development through Elmworth Compressor – Full-field Development into 2019 SemCAMS Wapiti Gas Plant
• Majority of development does not require additional compression infrastructure – Lower Opex
Gold Creek Geology
MN
TN
'C
' M
NT
N 'B
' L
ow
er
MN
TN
Gamma Porosity %
20 0
Pipeline Connected to
NVA Elmworth Comp Stn
2019 SemCAMS
Wapiti Gas Plant
Activity and Infrastructure
3-well ERH Pad – Wait on completion Hi-Fi Avg. 3300m+ HZ and 55 stages
NVA Montney New IP30's
NVA In-Progress Wells
Montney Hz Wells
Gold Creek Development Block Results To-Date and Type Well Economics
May 2017 15
0
1
10
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000
Rat
e (
MM
cf/d
)
Cumulative Gas (MMcf)
Historical Average ERH ERH + HiFi
Type Curve Comparison Plot Economics(6)(7)(8)(9)
Historical Average(3)
ERH Type Curve
ERH + Hi-Fi Type Curve
NPV10 ($MM) $4.2 $7.1 $8.6
PIR 0.6 0.9 0.8
Payout (Years) 2.3 1.5 1.1
ROR (%) 35% 60% 75%
Netback ($/Boe) $24.50 $24.50 $24.50
F+D ($/Boe) $8.00 $7.00 $8.00
Cap. Efficiency ($/Boed) $13,000 $10,000 $8,500
1st Year Prod (Boe/d) 550 850 1,250
1st Year Cash Flow ($MM) $5.0 $7.6 $11.3
Gold Creek Type Curve Inputs and Economics
Half-Cycle Inputs Historical Average(3)
ERH Type Curve
ERH + Hi-Fi Type Curve
DCET Capital ($MM) $7.1 $8.4 $10.6
EUR (Raw Gas) (Bcf) 4.0 5.5 6.0
EUR (MMBoe) 0.9 1.2 1.3
NGL(4) (C3, C4 Bbl/MMcf) 19 19 19
CGR(5) (C5+ Bbls/MMcf) 60 60 60
New GP Opex ($/Boe) $8.00 $8.00 $8.00
Horizontal Length (m) 2,000 3,000 3,000
Stage Count 25 38 60
Currently piloting
Currently Piloting
Gold Creek Well Production to-Date(1)
* 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): $3.00; Fx (CAD:USD): 1.30:1
May 2017 16
Pipestone Highlights Pipestone Geology
• Up to 4 developable layers
• Acreage to the West extensively developed by EnCana
• Condensate yield expected to average 60+ Bbls/MMcf (Range of 45 to 150+)
• Type-curve raw gas EUR expected to average 5.0 Bcf (Range of 3.0 to 7.0 Bcf)
• NVA is presently planning minimum of one well in 2017
• 2019-20 full-field development including compressor station and pipeline to new SemCAMS Wapiti plant
MN
TN
'C
' M
NT
N 'D
' M
NT
N 'B
' L
ow
er
MN
TN
Gamma Porosity
20 0 ECA Pipestone 'Super-
Condensate'
ECA Pipestone Condensate-rich Development
Future NVA Compressor and Pipeline to SemCAMS
Wapiti Gas Plant
Pipestone Activity
*Map of activity at Pipestone is compiled from public data
CNOR 13-22 HZ Initial Test
278 Bbls/MMcf C5+
Pipestone Development Block Facilities in Planning Phase for 2019-20 Development
NVA 13-27 License Spud Mid 2017
Pipestone Development Block Robust Initial Type-Curve Economics
May 2017 17
Offsetting Well Production vs. NVA Type Well(1)
Pipestone Base Type Well Production Profile
Pipestone Dev. Type Curve Inputs and Economics
Half-Cycle Inputs Base Type Curve
DCET Capital ($MM) $7.1
EUR (Raw Gas) (Bcf) 5.0
EUR (MMBoe) 1.1
CGR (C5+ Bbls/MMcf) 60
Opex ($/Boe) $10.00
Horizontal Length (m) 2,000
Stage Count 25
Economics(6)(7)(8)(9) Base Type Curve
NPV10 ($MM) $7.5
PIR 1.1
Payout (Years) 1.2
ROR (%) 85%
Netback ($/Boe) $22.50
F+D ($/Boe) $6.50
Cap. Efficiency ($/Boed) $8,000
0
300
600
900
1,200
1,500
1,800
0 6 12 18 24
Sale
s P
rod
uct
ion
(B
oe
/d)
Time (Months)
Pipestone TC Total Prod
Pipestone TC Condensate Prod
Offsetting wells restricted by operator to ~3-4 MMcf/d
* 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
Source: GeoSCOUT
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
0 5 10 15 20 25 30 35 40Days
2013 2014 2015 2016
0
5
10
15
20
25
30
35
$0
$100
$200
$300
$400
$500
$600
2013 2014 2015 2016E 2017E
Nu
mb
er o
f St
ages
($0
00
)
Cost per Stage No. of Stages
$0
$2
$4
$6
$8
$10
$12
$14
2013 2014 2015 2016E 2017E
($M
M)
Proven Track Record of Execution Improving Efficiency and Well Costs
May 2017 18
Average Annual Montney Drilling Curves Montney Well Cost (DCET) By Year
• Record three-well pad cost of $5.1 MM per well (DCET) in Elmworth in summer 2016.
• 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
Montney Drilling & Completion Cost per Stage Operational Highlights
Dep
th (
m)
Proven Track Record of Execution ERH and Hi-Fi Completions
May 2017 19
04-05 2,500m Hz 23 Stages
16-10 2,400m Hz 23 Stages
09-24 3,100m Hz 37 Stages 01-34
2,700m Hz 32 Stages
16-27 2,600m Hz 29 Stages
NVA Extended Reach Montney Horizontals
Bilbo IP180 vs. Original Type Curve
05-02 2,400m Hz 22 Stages
Bilbo ERH Production vs. Original Type Curve(1)
0
100
200
300
400
500
600
0 1 2 3 4 5 6 7 8 9 10 11 12
Cu
mu
lati
ve P
rod
uct
ion
(M
Bo
e)
Time (months)
Type Curve (4.4 bcf, 75 bbl/mmcf) Average
Approx. 2x Yr 1 Prod
(1) NuVista's type curve based on Management's best estimates
2 Wells 2,300m+ 50 stages per well
On-stream
3 Wells 2,200m+ avg. 35 stages per well
On-stream
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
0 500 1,000 1,500 2,000 2,500 3,000 3,500
Tota
l Sal
es
IP1
80
(B
oe
/d)
Horizontal Length (m)
Bilbo TC Encouraging ERH Results
Wellhead-to-Market Egress Plan In-Place Firm Egress Counts: Long-Term Growth Secured
May 2017 20
CNRL Gold Creek Plant
Keyera Simonette Plant
SemCAMS K3 Plant
SemCAMS Raw Gas Pipeline
Keyera Raw Gas and C5+ P/L
Alliance Sales Line
TCPL Sales Line
Grande Prairie SemCAMS Wapiti Sour Gas Plant
Status: Under Construction – 2019 Startup Raw Gas Capacity: 200 MMcf/d
Condensate Capacity: 20,000 Bbl/d
Keyera Wapiti Sour Gas Plant
Status: Licensed Raw Gas Capacity: 300 MMcf/d
Condensate Capacity: 25,000 Bbl/d
NuVista North Compressor Station
(50% WI)
Gross Raw Gas Capacity: 35 MMcf/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
0
10,000
20,000
30,000
40,000
50,000
60,000
0
50
100
150
200
250
300
2014 2015 2016 2017 2018 2019 2020 2021
Mo
ntn
ey
Cap
acit
y (B
oe
/d)
Mo
ntn
ey
Raw
Gas
Cap
acit
y (M
Mcf
/d)
Min. Midstream TOP Commitment Downstream Firm Gas Service
May 2017 21
TOP = NuVista Minimum take-or-pay volume commitment Downstream Firm Gas Service includes priority interruptible service
Elmworth
Bilbo
Gold Creek
Pipestone
60,000+ Boe/d Montney Processing Capacity Secured
Market Egress Plan In-Place Wapiti Montney Processing Capacity…Material Running Room
May 2017 22
• NuVista has contracted for firm transportation on export pipelines to diversify pricing exposure
• We continue to evaluate future opportunities for diversification
• Ongoing rolling hedging program and financial basis hedges further diversify price exposure
Market Egress Plan In-Place Natural Gas Price Diversification
64%
27%
11%
8%
15%
16%
14%
14%
18%
24%
6%
29%
27%
3% 4%
20%
0%
25%
50%
75%
100%
2017 2018 2019
Pct
. of
Fore
cast
Gas
Pro
du
ctio
n
Hedged Henry Hub Floating Chicago Floating California Floating Dawn Floating AECO Floating
Natural Gas Price Diversification
Commodity Price Risk Management Continuing Rolling Hedging Program
May 2017 23 Basis includes some export capacity to Chicago and California. Includes NYMEX hedges converted to an AECO equivalent price.
60.00
62.00
64.00
66.00
68.00
70.00
72.00
74.00
1,000
2,000
3,000
4,000
5,000
6,000
7,000
2017 Q2 2017 Q3 2017 Q4 2018 Q1 2018 Q2 2018 Q3 2018 Q4
Pri
ce, C
$/B
bl
He
dge
d V
olu
me
, Bb
l/d
Bbl/d Capped Bbl/d Uncapped Avg. Floor Avg. Ceiling
0.75
1.50
2.25
3.00
3.75
4.50
25,000
50,000
75,000
100,000
125,000
150,000
175,000
2017 Q2 2017 Q3 2017 Q4 2018 Q1 2018 Q2 2018 Q3 2018 Q4 2019 Q1
Pri
ce, C
$/G
J
He
dge
d V
olu
me
, GJ/
d
GJ/d Capped GJ/d Uncapped GJ/d AECO-NYMEX Basis Avg. Floor Avg. Ceiling
Floor C$ WTI price of $66.30/Bbl on ~61% of
2017Q2-Q4 net production
Floor AECO price of $3.18/Mcf on ~64% of
2017Q2-Q4 net production
Crude Oil Hedge Position
Natural Gas Hedge Position
May 2017 24
NuVista Operating Results 2017 Guidance
Corporate Production (Boe/d)
Corporate Funds from Operations
96% 81% 83%
96% 96% 96%
25,484
23,451 24,898 24,716
26,731
-
5,000
10,000
15,000
20,000
25,000
30,000
Q1 '16 Q2 '16 Q3 '16 Q4 '16 Q1 '17
Wapiti Montney Other Properties
$13.06
$16.69
$13.65
$17.90 $17.98
$0
$5
$10
$15
$20
$25
$10
$15
$20
$25
$30
$35
$40
$45
$50
$55
$60
Q1 '16 Q2 '16 Q3 '16 Q4 '16 Q1 '17
($/B
OE)
($M
M)
Funds from Operations ($MM) Funds from Operations ($/Boe)
Actual Production (Boe/d)
Guidance (Boe/d)
Q1 '17 26,731 26,000 – 29,000
Q2 '17 - 26,000 – 29,000
Q3 '17 - 26,000 – 29,000
Q4 '17 - 32,500 – 35,000
FY 2017 - 28,000 – 31,000
Q1 2017 Capex ($MM)
2017 Capex Guidance Range ($MM)
$107.2 $280-$300
Q1 2017 Funds from Operations
($MM)
2017 Funds from Operations Guidance
Range ($MM)
$43.3 $160-$180
NuVista Looking Forward Flexibility and Strength …Growth in a Volatile Environment
May 2017 25
Pure-Play Montney Company – In The Right Neighborhood
Balance Sheet Strength – Funded Growth Plan Through 2018+
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
Advisory Regarding Oil and Gas
Information
May 2017 26
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, 2015. 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.
Advisory Regarding Oil and Gas
Information
May 2017 27
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.
Advisory Regarding Non-GAAP Measurements,
Reserves Disclosure & Economic Assumptions
May 2017 28
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, 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) 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 2017 29
APPENDIX
Proven Track Record of Execution 2016 Year-end Reserves Report
May 2017 30
$0
$100
$200
$300
$400
2012 2013 2014 2015 2016
Non-MTY MTY
0
10
20
30
40
2012 2013 2014 2015 2016
Non-MTY MTY
• 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)
See Advisory Regarding Reserve Disclosure
2016 Year-end Reserve Highlights
Proven Track Record of Execution 2016 Year-end Reserves Report
May 2017 31
Gross Montney Well and Location Count by Year
Montney 'C' Reserves NuVista F&D Costs ($/Boe) Montney 'B' Reserves
$0
$5
$10
$15
$20
$25
$30
2013 2014 2015 2016
PDP F&D TP+PA F&D
18 34 52 69
103
194
223 240
0
50
100
150
200
250
300
350
2013 2014 2015 2016
Offsets Locations PDP Wells
121
228
275
309
(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
Montney Well and Location Count Breakdown
See Advisory Regarding Reserve Disclosure
May 2017 32
• Condensate is used in Alberta as a diluent to ship heavy oil on pipelines
• Condensate in Alberta is typically priced at a premium to crude oil
• US condensate supply is increasing
• But condensate export restrictions are easing
• Condensate must be transported to Alberta – "we're on the right end of the pipe"
• Premium for condensate will always reflect the cost of transportation to deliver to Alberta while demand outstrips local Alberta production … and it still does
Western Canadian Condensate Pricing
Condensate Pricing Strong Demand and Premium Price for the Long-Term
Western Canadian Condensate Supply and Demand
May 2017 33
• Multiple pilot wells in progress by industry – Early Production Data Emerging
• NuVista has good distribution of vertical wells and cores
• NuVista vertical completion: over pressured, condensate-rich
• NuVista first horizontal test well now sanctioned for spud late in 2017
Lower Montney Activity NuVista Data Collection In Progress
Elmworth
South Wapiti
Gold Creek
Bilbo
Kakwa
Karr
Pipestone
SCL 1-33-67-5W6 CTD: 0.1 bcf, Current CGR: 100
7Gen 13-24-65-5W6 CTD: 0.2 bcf, 43 mbbl C5+, CGR: 233
7Gen 12-32-64-5W6 CTD: 0.3 bcf, Current CGR: 305
7Gen 02/9-22-63-3W6 Tested 800 Mcf/d, 428 bpd C5+
NVA Lands Montney Hz Wells LWR Montney 'A' Wells LWR Montney 'A' Cores
ACL 1-7-67-7W6 CTD: 1.1 bcf, Test CGR: 54
SCL 6-20-66-6W6 Confidential until Sep 2017
T70
T68
T66
R9W6 R7W6 R5W6 R3W6
SCL 15-1-69-6W6 Tested: 1.9 MMcf/d and 174 bpd C5+
T64
NVA 15-13-68-7W6 Vertical Over-pressured – 133 Bbls/MMcf C5+
Velvet 12-33-66-2W6 CTD: 0.2 bcf, 42 mbbl C5+
SCL 6-15-63-7W6 Tested: 9 MMcf/d and 302 bpd C5+
SCL 02/9-27-66-7W6 CTD: 0.8 bcf, IP30 CGR: 85
T62