43
Corporate Presentation August 2019
Corporate Presentation
August 2019
Advisory Regarding Forward-Looking
Information and Statements
August 2019
This presentation contains forward-looking statements and forward-looking information (collectively, forward-looking statements") within the meaning of applicable securities laws. The use of any of the words "will", "may", "expects", "believe", "plans", "potential", "continue", "guidance", and similar expressions are intended to identify forward-looking statements. More particularly and without limitation, this presentation contains forward looking statements, with respect to: management's assessment of: NuVista's future focus, strategy, plans, opportunities and operations; 2019 guidance with respect to average production, capital investment and adjusted funds flow; 2019 production; the quality and growth potential of NuVista's Montney assets; expectations that NuVista will achieve its production target of 110,000 Boe/d, the pace of development and that this will result in production growth returns of approximately 0-15% per year, all within anticipated adjusted funds flow; management's view that NuVista's inventory is underpinned by four established development blocks; the future impact of oil prices and hedging; expectations that NuVista's record of execution and improvement will continue; key 2019 planned milestones and growth options including the Wapiti Plant start-up timing and capacity, Pipestone South development plans, and plans with respect to continued Lower Montney delineation; expectations that NuVista will experience measured funded growth; 2019 and 2020 capital expenditure, production, adjusted funds flow and adjusted funds flow per share and net dent to annual adjusted funds flow guidance; 2019 capital guidance and allocation plans; expectations and plans with respect to the flexibility of NuVista's capital expenditure plans; plans to finalize a midstream agreement for the planned Pipestone South compressor station; expectations with respect to full field development production, production mix, estimated stay flat capital expenditures and the expected resulting annual adjusted funds flow; expectations regarding full field development and associated CGRs, commodity prices, operating and transportation expenses, decline rates and capital efficiencies; plans to ramp up activities in Gold Creek and Pipestone South in 2019 including compressor station and pipeline construction plans and timing, forecast production mix, well inventory, anticipated full field development production, Hi-Fi well economics, ERH optionality and facility capacity; NuVista's drilling inventories; expectations with respect to future reserve upside and that the Pipestone acquisition improved NuVista's reserve growth opportunities; expectations with respect to Bilbo and Elmworth operating income and stay flat capital requirements and associated CGRs, commodity prices, operating and transportation expenses, decline rates and capital efficiencies; expectations with respect to HiFi drilling at Elmworth and that this will result in improved capital efficiencies and shorter payout periods; Gold Creek type curves; Pipestone development plans, capital investment and future production; existing and future processing options; future market egress plans, optionality and impact of NuVista's 110,00 Boe/d production target; natural gas price diversification options and plans; the impact of NuVista'scommodity hedging program and financial basis hedges; 2019 drilling time, DCET costs (by year and per stage); 2019 operational plans including plans to continue to optimize well designs to push unit costs down and to drill further ERH wells; future reservoir optimization plans; Bilbo, Elmworth, Gold Creek and Pipestone type curves; payouts, rates of return, NPV10 and other economics and anticipated associated DCET, EURs, CGRs, operating expenses and drilling plans; future condensate demand and pricing; and anticipated drilling results for lower Montney wells currently being drilled.
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.
By their nature, forward-looking statements are based upon certain assumptions and are subject to numerous risks and uncertainties, some of which are beyond NuVista's control, including the impact of general economic conditions, industry conditions, current and future commodity prices and differentials, currency and interest rates, anticipated production rates, borrowing, operating and other costs and adjusted funds flow, the timing, allocation and amount of capital expenditures and the results therefrom, anticipated reserves and resources and the imprecision of reserve and resource estimates, the performance of existing wells, the success obtained in drilling new wells, the sufficiency of budgeted capital expenditures in carrying out planned activities, access to infrastructure and markets, competition from other industry participants, availability of qualified personnel or services and drilling and related equipment, stock market volatility, effects of regulation by governmental agencies including changes in environmental regulations, tax laws and royalties; the ability to access sufficient capital from internal sources and bank and equity markets; obtaining the necessary regulatory approvals to complete the acquisition and other transactions referred to herein on the terms and timing contemplated and including, without limitation, those risks considered under "Risk Factors" in NuVista's Annual Information Form. 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 forward-looking statements. NuVista's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements, or if any of them do so, what benefits NuVista will derive therefrom. NuVista has included the 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. NuVista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
1
27% 50%75%
90%97%
97%97%
28%25%
17%
0
10
20
30
40
50
2013* 2014 2015 2016 2017 2018 2019E
Wapiti Montney Wapiti Sweet Other Pipestone Acquisition
Production (MBoe/d)
NuVista Snapshot
August 2019
TSX Trading Symbol: NVA
Market Capitalization: ~$600 million
Basic Shares Outstanding: 225 million
Credit Facility Capacity: $500 million
Percent Drawn(1): 68%
Net Debt/Adjusted Funds Flow(2): 2.2x
NuVista Corporate Info
Grande Prairie
Edmonton
Calgary
NuVista Wapiti Montney Project
Non-Core Areas
1 Percent drawn at June 30, 2019 on $500MM facility 2 Q2 2019 Net Debt to annualized Q2 2109 Adjusted Funds Flow See "Non-GAAP Measurements" * Pro-forma 2013 Divestitures 2
2019 Guidance
Full Year Avg. Production (Boe/d) 51,000 – 54,000
Q3 19 Avg. Production (Boe/d) 49,000 – 52,000
Capital Investment ($MM) $300 – $325
3
• High level of industry activity continues
• >1,300 Industry Montney HZ wells drilled to date
• Montney gas production of ~1.5 Bcf/d
Wembley to Kakwa Montney HZ Activity Update
Wembley to Kakwa Production Growth(1)
Montney – In The Right NeighborhoodCondensate-Rich Montney Industry Growth Continues
(1) 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”.August 2019
NuVistaEncanaParamountSinopec-DaylightCNRLSeven GenerationsShellHuskyPipestone
Montney Licensesand Hz Wells
0
150
300
450
600
750
900
1050
1200
1350
0
200
400
600
800
1000
1200
1400
1600
1800
Pro
d W
ell
Co
un
t
Cal
Day
Gas
Avg
(M
Mcf
/d)
Cal Gas Rate Prod Well Count
Built-in Control and FlexibilityValue Creation Remains Top-Priority
August 2019 4
Pure-Play Montney Company – In The Right Neighborhood
Clear Line-of-Sight to 110,000 Boe/d – but Optionality to flatten at 68,000 Boe/d in 2021-2022
Wellhead-to-Market Egress Plan In-Place – Material Flexibility in Infrastructure Agreements
Inventory Underpinned by Four Established Development Blocks
30%+ Condensate Production – Torque to Oil Price + Rolling Hedging Program
Proven Track Record of Execution & Continuous Improvement
Thoughtfully Measured & Self-Funded GrowthMaximum Shareholder Value derives from measured growth to our 2021 Minimum
Volume Commitments… followed by flexibility to flatten for FCF Generation
August 2019 5
51.0
57.0
63.0
15
30
45
60
2015A 2016A 2017A 2018A 2019E 2020E 2021E
US$65/Bbl US$55/Bbl
Capital Expenditure Outlook Range ($MM) Production Outlook Range (MBoe/d)
(1)Assumptions: Oil Price: US$55/Bbl = 2019-2021 US$55/Bbl WTI; -US$4/Bbl C5+ Differential; US$65/Bbl = 2019-2021 US$65/Bbl WTI; -US$4/Bbl C5+ Differential;Gas Price: 2019/20: US$2.60/MMBtu NYMEX; C$1.75/GJ AECO; 2021: US$2.75/MMBtu NYMEX; C$1.95/GJ AECO; Fx: 2019-2021: 1.32:1.0 C$:USD
(2)Adjusted Funds Flow. See "Non-GAAP Measurements".
$100
$200
$300
2015A 2016A 2017A 2018A 2019E 2020E 2021E
Adjusted Funds Flow Outlook Range(1)(2) ($MM)
$50
$150
$250
$350
$450
2015A 2016A 2017A 2018A 2019E 2020E 2021E
US$65/Bbl US$55/Bbl
$189
$273
22.424.6
$315
29.8
$125 $138
$200
0.0x
1.0x
2.0x
3.0x
2015A 2016A 2017A 2018A 2019E 2020E 2021E
US$55/Bbl US$65/Bbl
$345
$300
$265
40.0
Net Debt/Annual Adjusted Funds Flow(1)(2)
$32554.0
+10-15% Prod/Share
Growth while…
$300
$350
…maintaining D:CF in a $55 WTI world & generating free
funds flow in a $65 world
$300
$375
$280 $295
61.0
68.0
$450
$320
$300
$350
~$260M
~$30M
~$25M
August 2019 6
Capital Expenditure HighlightsMaintaining Maximum Near-term Flexibility
While Growing 10-15+% per year
Drill, Complete, Equip & T/I Facilities & Water Management
Maintenance, Corporate & Other
2019 Capex Breakdown
2019 Capex Guidance$300 – $325MM
• Activity focused on development drilling at Bilbo and Elmworth and ramping up initial growth into the New Wapiti Gas Plant at Gold Creek & Pipestone South
• The 2019 plan maintains maximum flexibility to adjust pace of growth upwards or downwards in response to commodity prices• Base plan includes a ~3 rig program in H1 and ~2 rigs steady through H219 (~30 wells drilled, phased throughout)• The Pipestone South compressor station capital has been removed from our Budget as we have midstreamed the cost (NVA operates)
Oct-18 Dec-18 Jan-19 Apr-19 Jun-19 Aug-19 Oct-19 Dec-19 Feb-20 Apr-20
2019
RIG
1R
IG 2
RIG
3
2020
Bilbo Elmworth Other/FlexR
4
2019 Drilling Gantt Chart
Significant H219 flexibility to dial down capital spend if pricing
deteriorates…
… while maintaining the option to increase pace
with a strengthening price outlook
PipestoneGold Creek
$150MM
70 Bbls/MMcf
US$65/Bbl
US$3/MMBtu
$12/Bbl
37%
$11.5K/Boed
-$25 $0 $25 $50
Capital Efficiency
NYMEX Gas Price
Ann'l Decline Rate
Opex & Transport
CGR
WTI Oil Price
Adj. FF - Capex
Building on Solid FoundationFree Funds Flow Generation as early as 2021-2022
August 2019 7
2022 Minimum Take-or-Pay
Capacity
Production Mix
Stay-Flat Capex Est.
Annual Adjusted Funds Flow(1)
Free funds flow represents the amount of adjusted funds flow generated that is in excess of total capital expenditures - See Advisory regarding "Non-GAAP Measurements"
-10%
Adjusted Funds Flow less Capex at Near-Term Target
BaseVariable Free Funds Flow Impact
+10 Bbls/MMcf
-5% Ann'l Rate
-$1.50/Bbl
+US$5/Bbl
+$0.25/MMBtu
Free Funds Flow
68,000 Boe/d
$450MM
$300MM
$150MM
Near-Term Target
(1) Base Assumptions: US$65/Bbl WTI; -US$4/Bbl C5+ Differential; US$2.75/MMBtu NYMEX (C$1.95/GJ AECO); 1.32:1.0 C$:USD
Free Funds Flow
62%
6%
32% Natural Gas
NGL's
Condensate
Even at US$55/Bbl~$50MM of free funds flow
is generated
110,000 Boe/d
Optional FutureFull-Field Target
Optional Line-of-Sight 68,000 - 110,000+ Boe/dFour Development Blocks Established – Gold Creek and
Pipestone South Ramping up in 2019
August 2019 8
Piestone• Compressor station and pipeline under
construction for late-2019 Pipestone South volume ramp
• Infrastructure agreements in place for late-2020 Pipestone North growth
• Forecast production ~35-40% condensate or 80-90 Bbls/MMcf
• Well Inventory for full field development to 60,000+ Boe/d
Pipestone – Infrastructure Agreements in Place
Elmworth
• Area production at capacity – Hi-Fi well results exhibiting step-change in economics
• Existing NVA owned compression and long-term firm service agreement for 100% of volumes
• Current production ~22% condensate
• 19,000+ Boe/d existing facility capacity and well inventory(1)
Elmworth – Excess Cash Generation
• SemCAMS Wapiti Gas Plant construction complete, on-Budget and ahead of schedule
• Ramping up volumes through Q2/Q3
• NVA footprint provides optionality in well length (ERH)
• Forecast production ~30% condensate
• 18,000 Boe/d expected facility capacity and well inventory(1)
Gold Creek – On Production
• Area production at capacity – continuing to delineate the Lower Montney
• Existing NVA owned compression and long-term firm service agreement for 100% of volumes
• Current production ~40% condensate –driving robust free-cashflow
• 18,000+ Boe/d existing facility capacity and well inventory(1)
Bilbo – Excess Cash Generation
(1) Well inventory is expected to be sufficient to produce at facility capacity for at least 10 years; refer to slide 10 for disclosure on reserves and resources location inventory.
9
Pipestone South
Pipestone North
ElmworthGold Creek Bilbo
Stratigraphy & Well PlacementReserves Booked in only 1-2 Layers Across our Lands…
Material Future Upside Remains
Lower Montney
B
C
D
Mid
dle
Mo
ntn
eyLo
we
r Mo
ntn
ey
5 % Gas Filled Porosity
Pipestone area has four well
developed zones
August 2019
Pipestone area has four well
developed zones
(1)Based on the GLJ Report.
NVA Wells on Block Industry Test Near Block Substantial Reserves Booked Across Block
Development Underpinned by Robust
Established and Emerging Inventory
August 2019 10
Montney 'A' Reserves & Resource Montney 'B' Reserves & Resource
(Gross) Bilbo West Bilbo Elmworth Gold Creek Pipestone South Pipestone North Total NVA
NuVista Developed Wells 74 1 43 18 3 29 168
Undeveloped 2P Locations 79 4 83 75 43 83 367
Undeveloped 2C Locations 164 45 155 198 42 194 798
Total Wells + Locations 317 50 281 291 88 306 1,333
Montney Well and Location Count Breakdown
See "Advisory Regarding Oil and Gas Information"
Montney 'C' Reserves & Resource
Montney Wells
Montney Lands
Montney A HZ Wells
Montney 2P Reserves
Montney 2C Resources
Montney Wells
Montney Lands
Montney B HZ Wells
Montney 2P Reserves
Montney 2C Resources
Montney Wells
Montney Lands
Montney C HZ Wells
Montney 2P Reserves
Montney 2C Resources
Montney 'D' Reserves & Resource
Montney Wells
Montney Lands
Montney D HZ Wells
Montney 2P Reserves
Montney 2C Resources
$65MM
80 Bbls/MMcf
US$65/Bbl
US$2.75/MMBtu
$11/Bbl
39%
$11.5K/Boed
-$10 $0 $10 $20
NYMEX Gas Price
Capital Efficiency
Opex & Transport
Ann'l Decline Rate
CGR
WTI Oil Price
Free Cashflow
August 2019
Bilbo Sales ProductionBilbo Activity and Reserves & Resource
Bilbo Development BlockGenerating Excess Cash & Significant Remaining Inventory
Bilbo Operating Income Less Stay-Flat Capex at Capacity
BaseVariable Free Funds Flow Impact
+10 Bbls/MMcf
-5% Ann'l Rate
-$1.50/Bbl
-10%
+$5/Bbl
+$0.25/MMBtu
11
5-Well Pad – On ProdIP90 data on new HiFi
ERH 'C' wells encouraging
NVA Montney New IP's
NVA In-Progress Wells
NVA Montney IP30
Montney Hz Wells
Free Funds Flow
C B Lower
This tornado chart is provided by NuVista for illustrative purposes and is based on a field capacity of 80 MMcf/d and the assumptions outlined within.
See Advisory regarding "Non-GAAP Measurements"
4-Well Pad – On ProdIP30 on 2 Lower Montney wells in line with Bilbo hist
avg for less capital cost
4-Well Pad – Equipping Includes 3 'C' wells
On stream Q3
0
5
10
15
20
Pro
du
ctio
n (
Mb
oe
d)
Sales Gas NGL's C5+
91
5 4
Cumulative-to-DateBbls/MMcf
C5+
Butane
Propane
Bilbo Cube DevelopmentLower Montney & Montney C Wells Exhibit Strong Performance
August 2019 12
Q119 On-stream Two Infill 'C' Wells
Q319E On-stream Three Infill 'C' Wells
Cumulative Condensate Production vs TimeQ417 On-stream
Two Infill 'C' Wells
Montney 'C' Wells (4 HZ Wells)Lower Montney Wells (3 HZ Wells)Montney 'C' Wells (Q319 O/S)Montney 'B' Wells
Q219 On-stream Two Lower Wells
Q417 On-streamFirst Lower Montney
• Recent delineation wells have performed in line with historical Bilbo average
• 7 recent delineation wells producing with 3 more coming on-stream in Q3
0
25
50
75
100
125
150
0 60 120 180 240 300 360
Cu
mu
lati
ve C
on
de
nsa
te (
Mb
bls
)
Days on Production
Bilbo Avg Delineation Avg
New Montney C Wells Lower Montney Wells
0
50
100
150
200
250
0 2 4 6 8 10 12 14 16 18 20 22 24
Cu
m C
on
de
nsa
te o
r O
il P
rod
(M
Bb
l)
Normalized Flowing Time (months)
0
200
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1000
1200
1400
0 2 4 6 8 10 12 14 16 18 20 22 24
Cu
mu
lati
ve G
as P
rod
uct
ion
(M
Mcf
)
Normalized Flowing Time (months)
Lower Montney Activity Update26 wells and counting…encouraging results from NVA, POU and VII
August 2019 13
Raw Gas Cum Time Plot
Condensate Cum Time Plot
NVA 11-18
NVA 2/9-10
POU 4-25 POU 1-7
SCL 6-20
SCL 9-27
26-Well Average
NVA 11-18
POU 01-07
SCL 09-27
SCL 06-20
NVA 2/09-10
POU 04-25
VII 14-26
VII 12-11
Recent NVA LwrMontney wells are performing above
area average
Robust liquids volumes after 12+ months
NVA 11-18
NVA 2/9-10
POU 4-25
VII 12-11
VII 14-26
Only ~1,600m Hz; ~40% shorter than
other highlighted wells
0.0
0.5
1.0
1.5
2.0
Cas
h F
low
($
MM
) /
Cap
Ex (
$M
M)
Bilbo IP360 Capital Returned
IP360 Capital Returned 10-well Mov Avg Hi-FI Wells
Bilbo Development Block
First-Year Capital Efficiency & Capital ReturnedStrong Condensate Yields Driving Cash Generation
14
Bilbo First Year Capital Returned(2)Bilbo Capital Efficiency per Well(1)
Wells Sorted Chronologically by On-stream Date →
August 2019
2010 2019 Wells Sorted Chronologically by On-stream Date →2010 2019
(1) Total well Drill, Complete and Equip Capital / IP360 Sales Production(2) Revenue (assuming US$65/Bbl WTI; -US$4/Bbl C5+ Dif; $2.75/MMBtu NYMEX) less royalties, opex and transportation / Total well Drill, Complete and Equip Capital
Additions since last update
0%
10%
20%
30%
40%
50%
60%
70%
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
Co
nd
en
sate
% (
Co
nd
bo
e/T
ota
l bo
e)
Cap
ital
Eff
icie
ncy
($
/To
tal
bo
e/d
)
Capital Efficiency ($/Total boe/d) 10-well Cap Eff Mov Avg
Hi-FI Wells 10-well Avg Cond %
$30M
40 Bbls/MMcf
US$65/Bbl
US$2.75/MMBtu
$12.5/Bbl
37%
$9K/Boed
-$10 $0 $10 $20
Capital Efficiency
Ann'l Decline Rate
NYMEX Gas Price
WTI Oil Price
Opex & Transport
CGR
Free Cashflow
August 2019
Elmworth Sales ProductionElmworth Activity
Elmworth Development BlockSignificant New Results – Hi-Fi Coming Through
Elmworth Operating Income Less Stay-Flat Capex at Capacity
BaseVariable
+10 Bbls/MMcf
-5% Ann'l Rate
-$1.50/Bbl
-10%
+$5/Bbl
+$0.25/MMBtu
15
NVA Montney New IP30's
NVA In-Progress Wells
NVA Montney IP30
Montney Hz Wells
Free Funds Flow
Free Funds Flow Impact
This tornado chart is provided by NuVista for illustrative purposes and is based on a field capacity of 77 MMcf/d and the assumptions outlined within.
See Advisory regarding "Non-GAAP Measurements"
2-Well & 3-Well Hi-Fi Pad IP30 ~30% Above Elm Avg.
Q419/Q120 Activity Focused on Higher CGR area – IP360
CGR ~85 Bbls/MMcf
0
3
6
9
12
15
18
Pro
du
ctio
n (
Mb
oe
d)
Sales Gas NGL's C5+
43
10
11
Cumulative-to-DateBbls/MMcf
C5+
Butane
Propane
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
Cas
h F
low
($
MM
) /
Cap
Ex (
$M
M)
Elmworth IP360 Capital Returned
IP360 Capital Returned 10-well Mov Avg Hi-FI Wells
0%
5%
10%
15%
20%
25%
30%
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
Co
nd
en
sate
% (
Co
nd
bo
e/T
ota
l bo
e)
Cap
ital
Eff
icie
ncy
($
/To
tal
bo
e/d
)
Capital Efficiency ($/Total boe/d) 10-well Cap Eff Mov Avg
Hi-FI Wells 10-well Avg Cond %
Elmworth Development Block
First-Year Capital Efficiency & Capital ReturnedImproving Capital Efficiencies Driving Payouts toward One Year
16
Elmworth First Year Capital Returned(2)Elmworth Capital Efficiency per Well(1)
August 2019
Wells Sorted Chronologically by On-stream Date →2010 2018 Wells Sorted Chronologically by On-stream Date →2010 2018
Hi-Fi wells results continue to drive capital returns at
Elmworth
Additions since last update
(1) Total well Drill, Complete and Equip Capital / IP360 Sales Production(2) Revenue (assuming US$65/Bbl WTI; -US$4/Bbl C5+ Dif; $2.75/MMBtu NYMEX) less royalties, opex and transportation / Total well Drill, Complete and Equip Capital
Gold Creek Development BlockNew ERH and Hi-Fi Wells off to a Strong Start
August 2019
SemCAMSWapiti Gas
PlantOn-stream
Activity and Infrastructure
ERH vs. Non-ERH Cum. Production
17
4-Well Hi-Fi Pad Robust IP90 C5+
Rates at >350 Bbls/d
NVA Montney New IP30's
NVA In-Progress Wells
NVA Montney IP30
Montney Hz Wells
Cum. Production Normalized for Cost
Gold Creek Sales Production
4-Well Pad –Q319 IP30
0
1
2
3
4
5
6
7
8
Pro
du
ctio
n (
Mb
oe
d)
Sales Gas NGL's C5+
68
910
Cumulative-to-DateBbls/MMcf
C5+
Butane
Propane
0
5
10
15
20
25
30
35
40
0 60 120 180 240 300 360
Avg
Cu
m P
rod
per
$1M
Cap
Ex (
Mb
oe)
Days on Production
ERH Cum. Total Prod. Non-ERH Cum. Total Prod.
0
100
200
300
400
500
0 60 120 180 240 300 360
(Mb
oe)
Days on Production
ERH Cum. Condensate ERH Cum. Total Prod.
Non-ERH Cum. Condensate Non-ERH Cum. Total Prod.
ERH Prod +2.0xHz Length : Prod Correlation = 1:1
ERH wells exhibiting +30% Improvement in IP360 Capital Eff.
0
10,000
20,000
30,000
40,000
Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19 Jan-20
Gas
Rat
e (
Mcf
/d)
Historical NVA Forecasted
Pipestone Development BlockSolid Production Base… On-track for a Q419 Ramp-up
18
Activity and Infrastructure Pipestone Highlights
• Up to 4 Developable layers – All have been proven productive on or adjacent to NVA lands
• Recent activity by multiple operators focused on cube development approach
• Future development planned to use NVA and offsetting operator best practices • 90% of acquired wells sub optimally completed (0.3 to 0.8 T/m proppant)• Various frac fluids used – NVA to employ Slickwater going forward
• Development efficiencies due to contiguous land position and year round access
• Lower D&C costs due to shallower depth
• Existing Pipestone North infrastructure will be kept full through 2019 with minimal capital investment
• Currently drilling an 8 well cube (in 4 zones) ahead of the anticipated Q419 commissioning of the Pipestone South Compressor StationECA - 3 Developed
Producing Layers
PEC - 3 Layers Waiting Tie-In
NVA 8 well Hi-Fi Pad
Piloting 4 Layer Cube
Pipestone North Montney Production
Stay flat with behind-pipe production shut-in by the previous
operator due to capacity constraints
NVA Compressor Station – Q419 Start-up
Montney 'D' Hz Wells
Montney 'C' Hz Wells
Montney 'B' Hz Wells
Lwr. Montney Hz WellsNorthwest Pad Avg.
IP365 Prod: 2.2 MMcf/d (Restricted)
CGRi: 185; 73 CTD Bbl/MMcf0.9 T/m & 2,400m Hz
Middle Montney Avg.
IP365 Prod: 2.9 MMcf/d (Restricted)
CTD CGR: 50 Bbl/MMcf (flat)1.4 T/m & 2,400m Hz
Lower Montney Well
IP365 Prod: 2.4 MMcf/d(Restricted)
CTD CGR: 80 Bbl/MMcf2.8 T/m & 1,450m Hz
August 2019
NVA - 3 Developed Producing Layers
NVA 3 Wells – late-
Q3 O/S
Tidewater
Pipestone
SemCAMS
Pipestone
CSV
Albright
Keyera
Pipestone
NuVista
Wembley
Keyera
Wapiti #1 & #2
SemCAMS
Wapiti
Planned Gathering Lines (approx.)
Planned Gathering Lines
Now On-Stream
Multiple Existing and Future
Processing Options
August 2019 19
Existing Gas Plants
Future Gas Plants
SemCAMS Raw Gas Pipeline
Keyera Raw Gas and C5+ P/L
Existing Gas Plant
Proposed or Future Gas Plant
FacilityNuVista Ownership or Firm Capacity In
Place
NuVista Firm Downstream
Capacity
Excess Capacity Available
SemCAMS K3 X
Keyera Simonette X
NuVista Wembley X
Veresen Hythe
Facility StatusNuVista Ownership
or Firm Capacity Contracted
Excess Capacity Available
SemCAMS Wapiti On-Stream
Keyera Wapiti Plant#1
Constructing X XKeyera Wapiti Plant
#2Announced X
SemCAMS Pipestone Proposed X
Tidewater Pipestone Constructing X
CSV Albright Proposed X
Keyera Pipestone Constructing X
0
20,000
40,000
60,000
80,000
100,000
120,000
0
100
200
300
400
500
600
2017 2018 2019 2020 2021 2022 2023 2024
Mo
ntn
ey C
apac
ity
(Bo
e/d
)
Mo
ntn
ey R
aw G
as C
apac
ity
(MM
cf/d
)
Pipestone Expected Future Capacity Pipestone Secured Capacity Gold Creek Secured
Bilbo Secured Elmworth Secured Minimum Take-or-Pay
Three Clear Choices
August 2019 20
Well over 110,000 Boe/d Montney Well Inventory Potential
Market Egress PlanCapacity Secured… Near-Term 2021 Production Target of ~68,000 Boe/d
then complete optionality for Free Funds Flow Generation or Growth Thereafter
Minimum Volume Commitment
Firm Capacity Secured Now
Capacity available to go and getonly if and when desired
ENVIRONMENTAL SOCIAL GOVERNANCE
Canada and Alberta have among themost stringent regulatoryrequirements in the world; theseensure the safe, responsible andtransparent development of ourhydrocarbon resources.
Our HSE Policy mandates ourcommitment to minimizing ourimpact on the environment.
We are continually seeking out andimplementing opportunities toreduce methane emissions andlower our carbon intensity – cut by>40% since 2012.
We are working with industry andstakeholders to find innovativeapproaches to reducing freshwateruse – RRR.
We remain focused on annualprogress in the abandonment andreclamation of inactive wells andfacilities.
Safety is our priority. Our HSE Policyoutlines our commitment to conductingour activities in a manner that protectsthe health and safety of our workers andthe public.
We believe in contributing to thecommunities in which we operate. Wemake substantial contributions to avariety of charities and First Nationsthrough employee volunteering,sponsorships and donations. In 2018,we donated over $380,000. We provideFirst Nations business opportunities.
We consult respectfully with FirstNations and local communities on everyproject including through the AboriginalConsultation Office of the Governmentof Alberta.
Our people drive our success. We offeran inclusive work environment where weembrace diversity of people, thinkingand ideas. Virtues like fair labor lawsand clean drinking water are "Givens" inCanada and in NuVista.
Sound corporate governance isfundamental to protecting the long-term interests of all stakeholders. In2018, we implemented a third partymaintained whistleblower site. Allstaff review & sign Code of EthicsPolicy annually.
We have an engaged, diverse andaccountable Board of Directors.Currently we have 1 woman on ourBoard with a stated objective of 20%membership by 2021.
Our Executive compensationprogram is aligned withshareholders’ interests – tied tosafety, environment, shareholderreturns, and corporate performance.We have a Say on Pay vote.
Committed to Environmental, Social and Governance (ESG) Performance
Just our Most Recent:
$13K Raised
August 2019 21
SOCIAL
0
1
2
3
4
5
6
7
0
20
40
60
80
100
120
140
2012 2013 2014 2015 2016 2017 2018
Liab
ility
Man
agem
ent
Rat
ing
(LM
R)
An
nu
al W
ell C
ou
nt
Annual Reclamation Certificates Annual Well Abandonments
NuVista YE LMR (AER)
Safety and Environment – Important aspects of ESG
NVA is proud… and Canada should be proud of its industry record
of corporate responsibility versus other countries
August 2019 22
Managing Abandonment and Reclamation Liability
NuVista GHG Reduction Projects
0
1
2
2011 2012 2013 2014 2015 2016 2017 2018
Recordable Injury Frequency (Employees and Contractors) per 200,000 man hours
Total Recordable Injury Frequency Falling
Total Annual Greenhouse Emissions & Intensity are Way Down
LMR Rating Excellent & Improving
Implemented Projects Under Consideration or Design Phase
Waste heat recovery units on compressors• 7 x $400k = $2.8MM• 1,000 tpa CO2 reduction per unit
Centralized instrument air for new pad-sites
Annual methane emissions reporting and fugitive emissions surveys being completed
Swap hi bleed for low bleed controllers plus tie some fields into flare (nil methane release)
5 solid oxide fuel cells deployed to pad-sites (nil methane release)
Tie chemical pumps to flare (nil methane release)
Low-Bleed pneumatic device conversion program
Solar Chemical Pumps
71 Hectares of land was reclaimed in 2018, equivalent to 135 NFL
football fields
0.000
0.005
0.010
0.015
0.020
0.025
0.030
0.035
0.040
0
50
100
150
200
250
300
350
400
2012 2013 2014 2015 2016 2017 2018
Ton
nes
CO
2e
/ B
oe
10
3To
nn
esC
O2e
DIRECT GHG EMISSIONS INDIRECT GHG EMISSIONS GHG EMISSIONS INTENSITY (CO2e / BOE)
Acquisition of the
WembleyAssets
Natural Gas Sales Points Q2 2019Diversification Counts
August 2019 23
2% 3%1%
0%
17%
3%
74%
Chicago Nat Gas Dawn Nat GasMalin Nat Gas AECO Nat GasNat Gas Hedges NGL'sCondensate
Net Revenue by Product & Gas Sales Point(1,2)
(1) Net Revenue = Revenue (includes realized hedging gains/losses) less Transportation costs
AECO
Chicago
Dawn
Henry Hub
$1.17
$3.29
$3.14
$3.54
Grande Prairie
* All prices in C$/mcf* Market Netback = Market Price less tolls (including fuel)* FX at C$/US$ at 1.3412* Based on Q219 average prices* Percentages reflect proportion of physical gas volumes delivered to the respective market in the period
Market Price
Market Netback
Malin
$2.92
$2.24$2.42
$2.10
Commodity Price Risk ManagementContinuing Rolling Hedging Program
August 2019 24Natural gas hedges include some NYMEX and Dawn hedges converted to an AECO equivalent price.
60.00
65.00
70.00
75.00
80.00
85.00
90.00
0
2,000
4,000
6,000
8,000
10,000
12,000
2019 Q3 2019 Q4 2020 Q1 2020 Q2 2020 Q3 2020 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
0.00
0.50
1.00
1.50
2.00
2.50
3.00
0
25,000
50,000
75,000
100,000
125,000
150,000
2019 Q3 2019 Q4 2020 Q1 2020 Q2 2020 Q3 2020 Q4
Pri
ce, C
$/G
J
He
dge
d V
olu
me
, GJ/
d
GJ/d Capped GJ/d Uncapped Avg. Floor Avg. Ceiling
Floor C$ WTI price of $79.60/Bbl on ~65% of
2019 Q3-Q4 net production
Floor AECO price of $2.12/Mcf on ~55% of
2019 Q3-Q4 net production
Crude Oil Hedge Position
Natural Gas Hedge Position
August 2019 25
• 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-PlaceNatural Gas Price Diversification
56%
18%
6%
31%59% 56%
5%
7%
20%21%
5%
8%
7% 8%11%
11%
9% 10%17%
25%
5% 5%
0%
25%
50%
75%
100%
2019 Q3-Q4 2020 2021 2022
Pct
. of
Fore
cast
Gas
Pro
du
ctio
n
Hedged NYMEX Floating Chicago Floating California Floating Dawn Floating AECO Floating
Natural Gas Price Diversification
August 2019
NuVista Operating Results2019 Guidance & Actuals Recap
Corporate Production (Boe/d)
Adjusted Funds flow
96%
$21.19 $19.69
$14.11
$18.17
$14.01
$0
$5
$10
$15
$20
$25
$0
$20
$40
$60
$80
$100
Q2 '18 Q3 '18 Q4 '18 Q1 '19 Q2 '19
($/B
OE)
($M
M)
Adjusted Funds Flow ($MM) Corporate Netback ($/Boe)
26See Advisory regarding "Non-GAAP Measurements"
*Refer to our MD&A for the applicable period for a reconciliation to cash provided by operating activities
Actual Production (Boe/d)
Guidance (Boe/d)
Q1 '19 43,839 43,000 - 46,000
Q2 '19 50,391 48,000 – 51,000
Q3 '19 - 49,000 – 52,000
Q4 '19 - Not disclosed
YTD 2019 47,133 51,000 - 54,000
Q2 2019 YTD Capex($MM)
2019 FY Capex Guidance Range ($MM)
$186 $300 – $325
Q2 2019 YTD Adjusted Funds Flow
($MM)
2019 FY Adjusted Funds Flow Guidance Range
($MM)
$136 Not Disclosed
99%99% 91% 95% 95%
36,035
40,080
49,06043,839
50,391
-
10,000
20,000
30,000
40,000
50,000
60,000
Q2 '18 Q3 '18 Q4 '18 Q1 '19 Q2 '19
Wapiti Montney Other Properties
Built-in Control and FlexibilityValue Creation Remains Top-Priority
August 2019 27
Pure-Play Montney Company – In The Right Neighborhood
Clear Line-of-Sight to 110,000 Boe/d – but Optionality to flatten at 68,000 in 2021-2022
Wellhead-to-Market Egress Plan In-Place – Material Flexibility in Infrastructure Agreements
Inventory Underpinned by Four Established Development Blocks
30%+ Condensate Production – Torque to Oil Price + Rolling Hedging Program
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
Advisory Regarding Oil and Gas
Information
August 2019
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 ofgas 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: 1Bbl) 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 energyequivalency 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 oilas 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 wellswill 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 haspresented certain type curves and well economics for the Bilbo, Elmworth, Pipestone and Gold Creek development blocks. For each of the Bilbo, Elmworth and Gold Creek areas the type curvespresented are based on NuVista's historical production in the Bilbo, Elmworth and Gold Creek development blocks, in addition to production history from analogous Montney developmentslocated in close proximity to the Wapiti area. For the Pipestone development block the rich and very rich type curves and well economics presented are based partially on initial drilling results but,due to the early stage of development, primarily on drilling results from analogous Montney developments located in close proximity to such area.
Such type curves and well economics are useful in understanding management's assumptions of well performance in making investment decisions in relation to development drilling in theMontney 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 ratesand 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. Thetype curves used by GLJ Petroleum Consultants Ltd. ("GLJ") for NuVista's most recent independent reserves evaluation as of December 31, 2018 for the Bilbo, Elmworth, Gold Creek and Pipestonedevelopment blocks had a lower estimate of estimated ultimate recovery than the type curves presented herein; however, the production forecasts in such independent reserves evaluation arealso lower than NuVista's current production as well as the production forecasts prepared by management.
The type curves presented fall into several categories: (i) Historical Average; (ii) ERH; (iii) Hi-Fi; (iv) ERH +Hi-Fi; (v) Rich; and (vi) Very Rich. The expectations for each type curve differ as a result ofvarying horizontal well length, stage count and stage spacing. Historical Average is the average type curve achieved from the wells previously drilled by NuVista in the area. The ERH type curvesrepresents 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 intensitytechniques on wells and ERH + Hi-Fi type curves are the expected type curves from combining extended reach horizontal with high-fracture intensity. In addition, with respect to the Pipestonedevelopment block this presentation includes well performance and estimated ultimate recoverable volumes associated with a Rich and Very Rich type curves, which refers to wells that areexpected to have a high and very high relative content of condensate production, respectively. The type curves and well economics associated with Rich and Very-Rich wells have been risked bytaking a reduced expected resource recovery from increased horizontal length and frac intensity based on applicable actual well data and applying our planned well design.
NuVista is still in the early days of piloting extended reach horizontals and high intensity facture techniques and in the early stages of development in respect of the Pipestone development block.As such there is no certainty that such results will be achieved or that NuVista will be able to optimize such drilling results to achieve the optimized type curves, well economics and estimatedultimate recoverable volumes described. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented; however, thereis no certainty that NuVista will ultimately recover such volumes from the wells it drills.
28
Advisory Regarding Oil and Gas
Information
August 2019
ADVISORY REGARDING OIL AND GAS INFORMATION
In presenting such type curves, inputs and economics information and in this presentation generally, NuVista has used a number of oil and gas metrics which do not have standardized meaningsand therefore may be calculated differently from the metrics presented by other oil and gas companies. Such metrics include "DCET", "EUR", "NPV10", "payout", "rate of return", "netback","F&D", "capital efficiency", "recycle ratio", and "capital returned". DCET includes all capital spent to drill, complete, equip and tie-in a well. EUR represents the estimated ultimate recovery ofresources 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 curvespresented. 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 toarrive 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 theanticipated 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 thereserves 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.First year capital returned is revenue (assuming US$65/Bbl WTI & $3/MMBtu NYMEX) for a given well less royalties, opex and transportation divided by total well drill, complete, equip and tie-incapital expenditures. 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.
This presentation discloses NuVista's drilling locations in two categories: (i) undeveloped 2P drilling locations; and (ii) undeveloped best estimate 2C drilling locations. Undeveloped 2P drillinglocations are derived from a report prepared by GLJ, NuVista's independent qualified reserves evaluator, evaluating NuVista's reserves as of December 31, 2018 (the "GLJ Report"), and accountfor undeveloped drilling locations that have associated proved and/or probable reserves, as applicable. Undeveloped 2C drilling locations are derived from a report prepared by GLJ evaluatingNuVista's contingent resources as of December 31, 2018 ("GLJ Contingent Resource Report"). There is no certainty that we will drill all drilling locations and if drilled there is no certainty that suchlocations will result in additional oil and gas production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonalrestrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. Contingent resources are those quantities of petroleumestimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered tobe commercially recoverable due to one or more contingencies. In the case of the contingent resources estimated in the GLJ Contingent Resource Report, contingencies include: (i) furtherdelineation of interest lands; (ii) corporate commitment, and; (iii) final development plan. To further delineate interest lands additional wells must be drilled and tested to demonstratecommercial rates on the resource lands. Reserves are only assigned in close proximity to demonstrated productivity. As continued delineation drilling occurs, a portion of the contingentresources are expected to be reclassified as reserves. Confirmation of corporate intent to proceed with remaining capital expenditures within a reasonable timeframe is a requirement for theassessment of reserves. Finalization of a development plan including timing, infrastructure spending and the commitment of capital. Determination of productivity levels is generally requiredbefore the company can prepare firm development plans and commit required capital for the development of the contingent resources. There is uncertainty that it will be commercially viable toproduce any portion of the contingent resources.
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 thecertain 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 believedto 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 withinNuVista'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 thatthe 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 theactual characteristics and quality of NuVista's Montney assets.
29
Advisory Regarding Oil and Gas
Information
August 2019
ADVISORY REGARDING OIL AND GAS INFORMATION
The reserves estimates presented herein have been evaluated by independent qualified reserves evaluator in accordance with NI 51- 101 and the Canadian Oil and Gas Evaluation Handbook("COGE Handbook"), are effective December 31, 2018 and are based on an independent evaluation by GLJ using January 1, 2018 forecast pricing. The contingent resource drilling locations arederived from the GLJ Contingent Resource Report. The reserves and resources presented herein have been categorized accordance with the reserves and resource definitions as set out in theCOGE Handbook.
ECONOMIC INPUT ASSUMPTIONS
NuVista's type curve based on management's best estimatesCGR yield represents the equivalent constant yield for the full life of the wellPricing Assumptions: Fx (CAD:USD): 1.25:1 used in all pricing scenariosPrice case flat on a real basis; costs inflated at 2% per annumNGL's as % of WTI: C3 = 30%; C4 = 65%; C5+ = WTI +US$2/BblGas price offset reflects NuVista's aggregate egress pipeline tolls and a $US1.05/MMBtu AECO to NYMEX basisRecovered liquids unit transportation cost: C$6/Bbl
30
Advisory Regarding Non-GAAP Measurements
August 2019 31
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”, "adjusted funds flow per share", "net debt", "net debt toadjusted funds flow", "stay-flat capex estimate, "operating netback", and "corporate netback", to analyze performance and leverage. These terms do not have any standardized meaning prescribed by GAAPand therefore may not be comparable with the calculation of similar measures for other entities. These terms are used by management to analyze performance on a comparable basis with prior periods and toanalyze the liquidity of NuVista.
Adjusted funds flow
NuVista considers adjusted funds flow to be a key measure that provides a more complete understanding of the Company's ability to generate cash flow necessary to finance capital expenditures, expenditures on asset retirement obligations, and meet its financial obligations. NuVista has calculated adjusted funds flow based on cash flow provided by operating activities, excluding changes in non-cash working capital, asset retirement expenditures and environmental remediation recovery, as management believes the timing of collection, payment, and occurrence is variable and by excluding these items from the calculation, management is able to provide a more meaningful performance measure. More specifically, expenditures on asset retirement obligations may vary from period to period depending on the Company's capital programs and the maturity of its operating areas, while environmental remediation recovery relates to an incident that management doesn't expect to occur on a regular basis. The settlement of asset retirement obligations is managed through NuVista's capital budgeting process which considers its available adjusted funds flow. Adjusted funds flow as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, per the statement of cash flows, net earnings (loss) or other measures of financial performance calculated in accordance with GAAP. Adjusted funds flow per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of net earnings (loss) per share.
Net debtNet debt is used by management to provide a more complete understanding of the Company's capital structure and provides a key measure to assess the Company's liquidity. NuVista has calculated net debt based on cash and cash equivalents, accounts receivable and prepaid expenses, asset under consruction, accounts payable and accrued liabilities, long term debt (credit facility) and senior unsecured notes.
Operating netback and corporate netback ("netbacks")NuVista reports netbacks on a total dollar and per Boe basis. Operating netback is calculated as petroleum and natural gas revenues including realized financial derivative gains/losses, less royalties, transportation and operating expenses. Corporate netback is operating netback less general and administrative, deferred share units, and interest expense. Management feels these netbacks are key industry benchmarks and measures of performance for NuVista that provides investors with information that is commonly used by other petroleum and natural gas producers. The measurement on a Boe basis assists management and investors with evaluating NuVista’s operating performance on a comparable basis.
Operating income equals the total of revenues including realized financial derivative gains/losses less royalties, transportation and operating expenses.
The operating netback, corporate netback and adjusted funds flow ($/Boe) assumptions used in this presentation to calculate estimated future adjusted funds flow are as follows:
*Net Revenues = Petroleum & Natural Gas Revenue +/- Realized Hedging Gain/Loss - Royalties
US$55/Bbl Case
$/Boe 2019 2020 2021
Net revenues* $29.50 $28.00 $28.00
Operating & Transportation expenses $12.25 $11.75 $12.00
G&A & Interest expenses $2.50 $2.00 $2.00
Adjusted funds flow $14.75 $14.25 $14.00
US$65/Bbl Case
$/Boe 2019 2020 2021 68 MBoe/d
Net revenues* $30.50 $30.00 $31.50 $31.00
Operating & Transportation expenses $12.25 $11.50 $12.00 $12.00
G&A & Interest expenses $2.50 $1.75 $1.75 $1.50
Adjusted funds flow $15.75 $16.75 $17.75 $17.50
August 2019
APPENDIX
32
Montney – In The Right NeighborhoodThe Alberta Condensate-Rich Montney: A World Class Play
August 2019
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
CONDENSATERICH
OVERPRESSURED
33
0
15
30
45
60
75
90
2013 2014 2015 2016 2017 2018
Non-Montney Pipestone Gold Creek Elmworth Bilbo
August 2019 34
NuVista 2018 Year-end Reserves Solid Foundation…Pipestone Acquisition Lengthens the
Runway for Growth
• Record growth in PDP reserves and NPVBT10, a YoY increase of 55% to 84 MMBoe and 66% to $880MM
• Record increase in TP+PA reserves and NPVBT10, up 55% to 538 MMBoe and 92% to $3.4Bn
Material growth in our legacy assets and the addition of the Pipestone North assets
• PDP and TP+PA F&D costs of $14.90/Boe and $6.43/Boe
• Robust recycle ratios of 1.4x and 3.3x for PDP and TP+PA reserves
• Total Montney developed wells increased to 168 (gross)
• TP+PA well count up 40% to 535 (gross) Strong backstop to our 110,000+ Boe/d growth plan
NuVista PDP Reserves (MMBoe) NuVista TP+PA BTAX NPV10 ($MM)
2018 Year-end Reserve Highlights
See Advisory Regarding Reserve Disclosure
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
2013 2014 2015 2016 2017 2018
Non-Montney Pipestone Gold Creek Elmworth Bilbo
$0
$2
$4
$6
$8
$10
$12
$14
2013 2014 2015 2016 2017 2018E 2019FC
($M
M)
0
10
20
30
40
50
60
$0
$100
$200
$300
$400
$500
$600
2013 2014 2015 2016 2017 2018E 2019FC
Nu
mb
er
of
Stag
es
($0
00
)
Cost per Stage No. of Stages
Proven Track Record of ExecutionImproving Efficiency and Well Costs
August 2019
Average Annual Montney Drilling CurvesMontney Well Cost (DCET) By Year
Montney Drilling & Completion Cost per Stage Operational Highlights
• Continue to optimize well designs to push unit cost per stage down; over 50% reduction achieved
• Continuing to drill further; Gold Creek ERH's drilled to 7,848m and 7,400m MD with 5,000m and 4,500m horizontal sections; NVA record low cost of $1,000/hz m
• Extended reach wells successfully completed, Gold Creek pumped ~8,800T of proppant per well
• 2019 well length on avg. shorter than 2018 due to location of activity – general NVA trend strongly toward ERH wells
35
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
0 5 10 15 20 25 30 35
Me
asu
red
De
pth
(m
)
Days from Spud
20132014
201520162017
2018Gold Creek 5,000m ERH
Reduction due to avg Hz length and area-by-area
optimization
Montney 3G Analysis
Tier I
Geological
GeochemicalGeomechanical
PVT Analysis
Microseismic
Calibrated Frac Modelling
3D Seismic
3D Static Geomech Model
Advanced Core Analysis
Fiber Optic Monitoring
Seismic Attributes
BH Pressure Monitoring
Reservoir Modelling
Petrophysics
Isotope Analysis
Gas
Oil
H2O
2012 2013 2014 2015 2016 2017 2018 Future
Max HZ Length 1,700m 2,500m 2,700m 3,100m 3,900m 5,000m2,400m
Max Frac T/m
Max Frac Stages
Min Inter-well Zone Spacing
Delineate, Prove Resource and Execution Mutli-well Pads, Prod. Ramp, Increased focus on Optimization Full Dev, Optimize, EOR
NuVista employs a balanced approach to reservoir optimization through the use of scientific, statistical and competitor analysis
1.1 1.2 1.1 1.7 2.1 2.2 3.0
16 20 22 32 55 70 88
New Zone Test(Elm/Bilbo C)
1,000+m 400m 320m 250m300m300m 200m
Bilbo B Elm / GC 'B' West Bilbo B Pipestone C / Bilbo Lower
Proven Track Record of ExecutionReservoir Optimization
August 2019
Minimize Footprint
Maximize Recovery
Maximize Returns
36
Bilbo Development BlockResults To-Date and Type Well Economics
August 2019
Hi-Fi Type Curve Economic Sensitivities
$55/Bbl $60/Bbl $65/Bbl
$2.70/MMBtu 1.3 1.1 1.0
$3.10/MMBtu 1.1 1.0 0.9
$3.50/MMBtu 1.0 0.9 0.8
0
1
10
0 1,000 2,000 3,000 4,000 5,000 6,000
Rat
e (
MM
cf/d
)
Cumulative Gas (MMcf)
Original Historical Average Hi-Fi
Type Curve Comparison Plot
Hi-Fi Type Curve Production
Raw Gas (Mcf/d)
C5+ (Bbl/d)
TotalSales
(Boe/d)
IP90 7,000 525 1,640
IP180 6,531 490 1,530
IP360 4,848 364 1,136
Hi-Fi Type Curve Inputs
DCET Capital ($MM) $8.6
EUR (Raw Gas) (Bcf) 5.0
EUR (MMBoe) 1.2
CGR (C5+ Bbls/MMcf) 75
Opex ($/Boe) $10.00
Horizontal Length (m) 2,000
Stage Count 40
WTI
NY
MEX
Payout (Years)
$55/Bbl $60/Bbl $65/Bbl
$2.70/MMBtu 65% 85% 110%
$3.10/MMBtu 85% 110% 130%
$3.50/MMBtu 110% 135% 160%
WTI
NY
MEX
Rate of Return
$55/Bbl $60/Bbl $65/Bbl
$2.70/MMBtu $6.5 $7.9 $9.3
$3.10/MMBtu $8.0 $9.5 $10.8
$3.50/MMBtu $9.5 $11.0 $12.3
WTIN
YM
EX
Net Present Value @ 10% ($MM)
* 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
37
Elmworth Development BlockResults To-Date and Type Well Economics
August 2019
Hi-Fi Type Curve Economic Sensitivities
$55/Bbl $60/Bbl $65/Bbl
$2.70/MMBtu 2.4 1.9 1.5
$3.10/MMBtu 1.7 1.4 1.2
$3.50/MMBtu 1.3 1.2 1.1
Type Curve Comparison Plot
Hi-Fi Type Curve Production
Raw Gas (Mcf/d)
C5+ (Bbl/d)
TotalSales
(Boe/d)
IP90 7,000 280 1,370
IP180 7,000 280 1,370
IP360 6,007 239 1,174
Hi-Fi Type Curve Inputs
DCET Capital ($MM) $8.4
EUR (Raw Gas) (Bcf) 7.0
EUR (MMBoe) 1.4
CGR (C5+ Bbls/MMcf) 40
Opex ($/Boe) $10.50
Horizontal Length (m) 2,000
Stage Count 40
WTI
NY
MEX
Payout (Years)
$55/Bbl $60/Bbl $65/Bbl
$2.70/MMBtu 30% 40% 50%
$3.10/MMBtu 40% 55% 65%
$3.50/MMBtu 60% 75% 90%
WTI
NY
MEX
Rate of Return
$55/Bbl $60/Bbl $65/Bbl
$2.70/MMBtu $2.6 $3.7 $4.8
$3.10/MMBtu $4.4 $5.5 $6.5
$3.50/MMBtu $6.1 $7.2 $8.2
WTIN
YM
EX
Net Present Value @ 10% ($MM)
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
* 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
38
Gold Creek Development BlockResults To-Date and Type Well Economics
August 2019
Hi-Fi Type Curve Economic Sensitivities
$55/Bbl $60/Bbl $65/Bbl
$2.70/MMBtu 1.8 1.4 1.2
$3.10/MMBtu 1.4 1.2 1.1
$3.50/MMBtu 1.2 1.1 1.0
Type Curve Comparison Plot
Hi-Fi Type Curve Production
Raw Gas (Mcf/d)
C5+ (Bbl/d)
TotalSales
(Boe/d)
IP90 7,000 420 1,545
IP180 7,000 420 1,545
IP360 5,684 341 1,254
Hi-Fi Type Curve Inputs
DCET Capital ($MM) $10.8
EUR (Raw Gas) (Bcf) 6.0
EUR (MMBoe) 1.3
CGR (C5+ Bbls/MMcf) 60
New GP Opex ($/Boe) $8.00
Horizontal Length (m) 3,000
Stage Count 60
WTI
NY
MEX
Payout (Years)
$55/Bbl $60/Bbl $65/Bbl
$2.70/MMBtu 40% 50% 65%
$3.10/MMBtu 50% 65% 80%
$3.50/MMBtu 70% 80% 100%
WTI
NY
MEX
Rate of Return (Pct.)
$55/Bbl $60/Bbl $65/Bbl
$2.70/MMBtu $4.9 $6.3 $7.6
$3.10/MMBtu $6.5 $7.9 $9.2
$3.50/MMBtu $8.1 $9.4 $10.7
WTIN
YM
EX
Net Present Value @ 10% ($MM)
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
* 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
39
0
1
10
0 1000 2000 3000 4000 5000 6000 7000 8000
Gas
Rat
e (
MM
cf/d
)
Cumulative Gas (MMcf)
Existing Wells (2207m) Existing Wells Norm. (3000m) Risked Type Curve
Pipestone Development BlockRich Type Curves & Well Economics
August 2019 40
Type Curve Comparison Plot
Type Curve Economic Sensitivities
WTI
$60/Bbl $65/Bbl $70/Bbl
AEC
O
$1.50/GJ 1.3 1.1 1.0
$1.75/GJ 1.2 1.1 1.0
$2.00/GJ 1.1 1.0 0.9
Payout (Years)
WTI
$60/Bbl $65/Bbl $70/Bbl
AEC
O
$1.50/GJ 72% 89% 108%
$1.75/GJ 84% 102% 122%
$2.00/GJ 96% 115% 136%
Rate of Return
WTI
$60/Bbl $65/Bbl $70/Bbl
AEC
O
$1.50/GJ $6.7 $8.0 $9.2
$1.75/GJ $7.8 $9.1 $10.3
$2.00/GJ $8.9 $10.1 $11.3
Net Present Value @ 10% ($MM)
Type Curve Inputs
DCET Capital ($MM) $9.3
EUR (Raw Gas) (Bcf) 7.0
EUR (MMBoe) 1,380
CGR* (C5+ Bbls/MMcf) 80↓48
Opex ($/boe) $8.00
Hz Length (m) 3,000
Frac Intensity (T/m) 2.0
* Monthly CGR declines over first 6 months then flat
Initial rates restricted due to facility
constraints
Avg. Fracintensity only
1.1 T/m
* Existing Wells dataset is the average of 45 slick-water wells with an average frac intensity of 1.1 T/m
* Refer to the "Advisory Regarding Oil and Gas Information" and the advisory regarding "Economic Input Assumptions".
Only slick-water MNTN Hz's are included in the
dataset
Pipestone Development BlockVery-Rich Type Curves & Well Economics
August 2019 41
Type Curve Comparison Plot
Type Curve Economic Sensitivities
WTI
$60/Bbl $65/Bbl $70/Bbl
AEC
O
$1.50/GJ 1.2 1.0 0.9
$1.75/GJ 1.1 1.0 0.9
$2.00/GJ 1.1 0.9 0.8
Payout (Years)
WTI
$60/Bbl $65/Bbl $70/Bbl
AEC
O
$1.50/GJ 91% 114% 140%
$1.75/GJ 98% 122% 148%
$2.00/GJ 104% 129% 156%
Rate of Return
WTI
$60/Bbl $65/Bbl $70/Bbl
AEC
O
$1.50/GJ $9.1 $10.5 $11.8
$1.75/GJ $9.7 $11.1 $12.4
$2.00/GJ $10.3 $11.7 $13.0
Net Present Value @ 10% ($MM)
Type Curve Inputs
DCET Capital ($MM) $9.3
EUR (Raw Gas) (Bcf) 4.5
EUR (MMBoe) 1,110
CGR* (C5+ Bbls/MMcf) 225↓89
Opex ($/boe) $6.00
Hz Length (m) 3,000
Frac Intensity (T/m) 2.0
* Refer to the "Advisory Regarding Oil and Gas Information" and the advisory regarding "Economic Input Assumptions".
* Existing Wells dataset is the average of 23 slick-water wells with an average frac intensity of 2.1 T/m
0
1
10
0 1000 2000 3000 4000 5000
Gas
Rat
e (
MM
cf/d
)
Cumulative Gas (MMcf)
Existing Wells (2721m) Existing Wells Norm. (3000m) Risked Type Curve
Only slick-water MNTN Hz's are included in the
dataset
Avg. Fracintensity 2.1 T/m
* Monthly CGR declines over first 6 months then flat
August 2019
• 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 but in the short term there can be some volatility
• Condensate must be transported to Alberta – "we're on the right end of the pipe"
• Long term, the premium for condensate should always reflect the cost of transportation to deliver to Alberta while demand outstrips local Alberta production,
• Domestic production has decreased from peak Q418 levels
Western Canadian Condensate Production (MB/d)
Condensate PricingStrong Demand and Premium Price for the Long-Term
Western Canadian Condensate Supply and Demand (MB/d)
42
Sources: Peters & Co. Limited estimates, Government data (Note: March 2019 production data for B.C. is not available yet; March production shown for B.C. assumes a 2% increase MoM), AER, geoSCOUT, and Company Reports.
100
150
200
250
300
350
400
450
500
Ja
n-1
4
Apr-
14
Ju
l-14
Oct-
14
Ja
n-1
5
Apr-
15
Ju
l-15
Oct-
15
Ja
n-1
6
Apr-
16
Ju
l-16
Oct-
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Ja
n-1
7
Apr-
17
Ju
l-17
Oct-
17
Ja
n-1
8
Apr-
18
Ju
l-18
Oct-
18
Ja
n-1
9
B.C. Alberta
0
50
100
150
200
250
300
350
400
450
500
550
600
650
700
750
800
19
98
19
99
20
00
20
01
20
02
20
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20
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20
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20
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20
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20
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20
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21
Demand (Blending) Supply (WCSB Production) FORECAST
