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CORPORATE PRESENTATION MAY 2016 All amounts in Canadian dollars - - PowerPoint PPT Presentation

CORPORATE PRESENTATION MAY 2016 All amounts in Canadian dollars unless indicated otherwise Advisory Regarding Forward-Looking Information and Statements This presentation contains forward-looking statements and forward-looking information within


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SLIDE 1

CORPORATE PRESENTATION MAY 2016

All amounts in Canadian dollars unless indicated otherwise

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Advisory Regarding Forward-Looking Information and Statements

May 2016

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; profitably grow production and funds from operations and develop NuVista's resource base, plans to focus on and improve processing and infrastructure; the benefits of NuVista's risk management program; the anticipated benefits of NuVista's asset base; expected supply cost reductions; 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; anticipated well economics including drilling, completion and equipping and tie-in 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; NuVista's ability to fulfill all TOP obligations; guidance with respect to NuVista's capital expenditure program, production mix, netback, funds from operations, targeted net debt levels and net debt to funds from operations ratios; commodity pricing and exchange rates 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; 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:

  • perational 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 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

  • perations. 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

  • perations, 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,

  • r 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.

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NuVista Snapshot

Production (MBoe/d)

27% 50% 75% ~80% 28% 25% 17% 10 - 15% 5 10 15 20 25 30 2013* 2014 2015 2016E Wapiti Montney Wapiti Sweet Other

TSX trading symbol: NVA Market capitalization: ~$0.9 billion Basic shares outstanding: 153.3 million Bank debt capacity: $300 million Percent Drawn (End Q1/16): 77% Net Debt:Cashflow1: 2.1x 2016 Guidance Production: 24,500 – 25,500 Boe/d Capital investment: $115 – $135 million Funds from operations2: $100 – $110 million

1 March 31, 2016 closing debt to Q116 Annualized Funds from Operations 2 Pricing Assumptions: $1.80/GJ AECO and US$45/Bbl WTI

* Pro-forma 2013 Divestitures

Operating areas

WAPITI

EDMONTON CALGARY

GRANDE PRAIRIE

May 2016

NuVista Corporate Info

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NVA Principles and 2016 Guidance

Focused on the Long Term… Flexibly managing the short term

May 2016

  • Well costs down an additional

30% since 2014

  • Continued improvement versus

type curve

  • Infrastructure spend complete

for growth through 2018+

  • Capex focused on well

development in 2016, not on facilities

  • G&A reduced by 1/2 over last

3 years, to $1.75/Boe for 2016

Reducing Costs & Improving Performance

  • Net debt/funds flow from
  • perations target under 2x
  • Flexibility to dial spending

quickly down or upwards as commodity prices change

  • Disciplined approach to capital

spending – large spend reduction for 2016, down nearly to 2016 funds from

  • perations

Maintain Balance Sheet Strength

  • Short term pace of spend

minimized while preserving long term take-away plans

  • Result is 10% to 15%

production growth with minimal increase in debt

  • Optimized 2016 development

well economics 25% to 35% ROR and 2.0 to 3.0 year payout

Profitable Growth Tuned to Market Environment

Efficiency and Flexibility

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The Alberta Condensate-Rich Montney

… A sweet spot in a "world class" play

High Quality Reservoir Overpressured 150-200 m thick Condensate Rich

  • 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

May 2016

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SLIDE 6

The Alberta Condensate-Rich Montney

Industry Drilling and Production growth continues…

*Excludes southern areas of Alberta Condensate-rich Montney (Resthaven and Simonette). Map is an estimate of Industry land positions compiled from public data

  • High level of industry activity continues
  • > 850 Montney HZ wells licensed and/or drilled

to date

  • Montney gas production exceeding 0.8 Bcf/d

Elmworth to Kakwa Montney HZ Activity Update* May 2016

R9 W6 R10 W6 NuVista Encana Paramount Sinopec-Daylight CNRL Seven Generations Shell Apache Montney Licenses and Hz Wells

5

R6W6 R4W6 R2W6 R8W6 T65 T62 T61 T67 T69 T70 T68 T66 T64 T63

Elmworth to Kakwa Production Growth*

50 100 150 200 250 300 350 400 450 500 100 200 300 400 500 600 700 800 900 1000 Producing Hz Well Count

  • Avg. Calendar Day Gas (MMcf/d)
  • Avg. Gas Rate

Producing Well Count

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1,000 2,000 3,000 4,000 5,000 6,000 5 10 15 20 25 30 35 40 Depth (m) Days 2013 2014 2015

Recent wells: 4,700m in 17 days; 5,500m in 21 days

Recent Wells $0 $2 $4 $6 $8 $10 $12 2013 2014 2015E 2016E ($M)

Relentless Improvement

Efficiency and Well Costs

May 2016

$0 $100 $200 $300 $400 $500 $600 2013 2014 2015E 2016E ($000)

  • Drilling and completion costs coming down steadily

from efficiency improvements

  • Record drilling cost of $2.8 MM with 4,750 metres of

total measured depth

  • Record completion costs of <$2.0 MM; average

completion cost per stage placed has now dropped below $130,000

  • In-field gathering largely in place – majority of 2016

wells will be on-lease tie-ins; limited expiry/step-out drilling Average Annual Montney Drilling Curves Montney Well Cost (DCET) By Year Montney Drilling & Completion Cost per Stage Operational Highlights

Recent Record Wells: 4,750m in 17 days; 5,500m in 21 days

Last 5 wells

  • utperforming

these 2016 budget expectations

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Relentless Improvement

Bilbo Well Performance

May 2016

Bilbo Type Curve Progression

100 200 300 400 6 12 18 24 Cumulative Production (MBoe) Time (Months)

2013 Type Curve (4.4 Bcf; 35 Bbls/MMcf) 2014 Type Curve (4.4 Bcf; 45 Bbls/MMcf) 2015 Type Curve (4.4 Bcf; 75 Bbls/MMcf) 2016 Optimized Locations (5.0 Bcf; 66 Bbls/MMcf)

300 600 900 1,200 1,500 1,800 6 12 18 24 Sales Prod (Boe/d) Time (Months)

2016 Optimized Bilbo Well Production Profile

Two-year CTD production up 13% vs. 2015 and 38% vs. 2013

2016 Optimized Bilbo Total Production (Boe/d) 2016 Optimized Bilbo C5+ Production (Bbls/d)

NuVista's type curve based on Management's best estimates; Type Curve: Bcf = EUR; Bbls/MMcf = C5+ yield

Bilbo Well Production-to-Date

*Production groupings based off spud dates 100 200 300 400 500 600 6 12 18 24 30 36 Cumulative Production (Mboe) Time (Months) 2015 Type Curve (4.4 Bcf, 75 bbl/MMcf) 2011-2013 (11 Wells) 2014 (12 Wells) 2015 (4 Wells)

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Relentless Improvement

Elmworth Well Performance

May 2016

Elmworth Type Curve Progression

100 200 300 400 6 12 18 24 Cumulative Production (MBoe) Time (Months)

2013 Type Curve (4.4 Bcf; 35 Bbls/MMcf) 2014 Type Curve (4.4 Bcf; 45 Bbls/MMcf) 2015 Type Curve (6.0 Bcf; 45 Bbls/MMcf) 2016 Optimized Loc's (6.5 Bcf; 42 Bbls/MMcf)

300 600 900 1,200 1,500 1,800 6 12 18 24 Sales Prod (Boe/d) Time (Months)

2016 Optimized Elmworth Total Production (Boe/d) 2016 Optimized Elmworth C5+ Production (Bbls/d)

2016 Optimized Elmworth Well Production Profile

Two-year CTD production up 7% vs. 2015 and 45% vs. 2013

Elmworth Well Production-to-Date

100 200 300 400 500 600 700 6 12 18 24 30 36 Cumulative Production (Mboe) Time (months) 2015 Type Curve (6 Bcf, 45 bbl/MMcf) Small Frac (3 Wells) Big Frac (9 Wells) NuVista's type curve based on Management's best estimates; Type Curve: Bcf = EUR; Bbls/MMcf = C5+ yield *Production groupings based off spud dates

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2016 Guidance

Agility in Capex Reduction

May 2016

2015 Capital Expenditures ($MM)

$185 $67 $10 $11

DCET & Optimization Facilities & Water Mgmt Maintenance Land, Seismic & Other

2016 Capital Expenditures ($MM)

$100 $10 $8 $6 2015 Highlights:

  • 18 Montney Wells drilled
  • Built Elmworth Compressor Station

2016 Highlights:

  • Flexible capex program; reduced from original

Budget of $140M-$160M

  • 10-11 Montney Wells in Bilbo & Elmworth
  • Minimal infrastructure spend

Development Focused

$273 MM $115-$135 MM

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Montney Operations

Activity Update

Bilbo

31 Producers (IP30) 2 New IP30's – 4 Additional on-stream 1 Well Completing

Elmworth

15 Wells Producing in the Development Block (IP30) 4 Elmworth Extension wells Producing (IP30) 2 New IP 30's – 2 Additional on-stream 1 Rig Drilling

Gold Creek

5 Producers (IP30) No new IP 30's – 1 additional well on-stream

NVA New IP30 NVA Producing Montney (IP30) NVA In-Progress Wells Montney HZ’s

2016 Focus on Capital Efficiency

  • Spud 10-12 wells in 2016 – all development wells
  • Minimal Infrastructure Capex required – filling

existing facilities

  • 2016 well performance expectations up 10-15%
  • ver 2015

Attractive Land Tenure

  • NuVista has over 135,000 gross acres of land

(210 sections @ 86% WI)

  • Minimal 3rd party encumbrances
  • Manageable expiries

Activity Highlights

  • 4 New IP30's in Q1 – 7 additional wells on-stream

late April/Early May

  • Reduced to 1 drilling rig for now
  • Over 60 wells on production

May 2016

T70 T68 T66 R8W6 R6W6 T67 T69 R7W6

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Elmworth Development Block

Volume Ramp in-progress

May 2016

R9W6 T67 T68

NVA Montney IP30's NVA In-Progress Wells Montney Horizontal Wells NVA Compressor Site

Connected to SemCAMS R8W6

2 New IP30's 2 additional Wells just on- stream 1 well drilling

T69

1 2 3 4 5 6 7 8 9

Production (Mboed) Sales Gas NGL's C5+ 39 9 11 Cumulative-to-Date

Bbls/MMcf

Condensate Butane Propane

North Montney Sales Production Elmworth Well Performance

Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) C5+ Yield (Bbl/ MMcf) Well Count IP30

6,442 318 1,330 49 15

IP60

5,884 267 1,189 45 13

IP90

5,375 237 1,078 44 13

IP180

4,170 172 838 41 9

IP360

3,193 126 636 39 8

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Bilbo Development Block

Focus on Efficient Production Additions in 2016

May 2016

NVA Montney IP30 Wells NVA Montney In-Progress Wells Montney Horizontal Wells NVA 3-36 Compressor and connect to Keyera R6W6 T65 T66

2 New IP30's 4 Wells recently on-stream 1 well to be completed

2 4 6 8 10 12 14 16 Production (Mboed) Sales Gas NGL's C5+

76 5 5

Cumulative-to-Date Bbls/MMcf

Condensate Butane Propane

South Montney Sales Production Bilbo Well Performance

Raw Gas (Mcf/d) C5+ (Bbl/d) Total Sales (Boe/d) C5+ Yield (Bbl/ MMcf) Well Count IP30 6,329 628 1,607 99 31 IP60 5,609 514 1,382 92 31 IP90 5,173 463 1,265 90 28 IP180 4,313 328 1,007 76 24 IP360 3,385 233 769 69 20

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A Closer Look at the NuVista 'Boe'

Condensate Underpins Economics and Provides Torque to Oil Price Recovery

May 2016

NuVista Production Mix1

5,000 10,000 15,000 20,000 25,000 30,000 2013 2014 2015 2016E

71% 12% 17% 70%

22%

8%

Nat Gas Condensate NGL's & Oil

NuVista 2016 Revenue Composition2

49%

49%

2% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2016E

1 Pro-forma Divestitures 2 Based on WTI (USD/Bbl): $40.00; AECO (C$/GJ): $2.50; Fx (CAD:USD): 1.4:1

Boe/d

Hedged or Unhedged: Condensate is ~50% of revenue from 22% of total production

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WTI US$50.00/Bbl; AECO C$2.75/GJ Realized Price2 $32.25/Boe Profit $8.25/Boe Margin 26% Recycle Ratio 1.2x

NuVista Montney Recycle Ratio and Profitability… Tremendous Torque to Oil and Gas Price

May 2016

Full-Cycle Bilbo F&D Cost

Well Cost (DCET) $7.3 MM Land/Seismic/Facilities $0.6 MM Full-Cycle Cost $7.9 MM 2016 Bilbo Type Curve EUR1 1.12 MBoe Full-Cycle F&D Cost $7.00/Boe

2016E Montney Cash Costs

Operating Cost $11.00/Boe Transportation $1.75/Boe Royalties $1.50/Boe G&A $1.75/Boe Interest $1.00/Boe Total Cash Cost $17.00/Boe

1NuVista's type curve based on Management's best estimates 2Unhedged Bilbo realized price

Torque to Oil and Gas Prices

WTI US$60.00/Bbl; AECO C$3.25/GJ Realized Price2 $38.00/Boe Profit $13.75/Boe Margin 36% Recycle Ratio 2.0x WTI US$40.00/Bbl; AECO C$2.25/GJ Realized Price2 $27.00/Boe Profit $3.50/Boe Margin 13%

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Wapiti Montney … Firm Egress Counts

Built-in growth with generous capital flexibility in the short term … … and multiple options for the long term

CNRL Gold Creek Plant Keyera Simonette Plant SemCAMS K3 Plant SemCAMS Raw Gas Pipeline Keyera Raw Gas and c5+ Pipeline Alliance Sales Line TCPL Sales Line

NuVista (100%) Bilbo Compressor Station Raw Gas Capacity – 80 MMcf/d Condensate Cap'y – 8,000 Bbl/d NuVista (100%) Elmworth Compressor Station Raw Gas Capacity – 80 MMcf/d Condensate Cap'y – 4,000 Bbl/d NuVista (50%) North Compressor Station Raw Gas Capacity – 20 MMcf/d

Grande Prairie

Proposed 2018 Wapiti Area Gas Plants May 2016

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5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 20 40 60 80 100 120 140 160 180 200

Montney Capacity – Boe/d Montney Raw Gas Capacity - MMcf/d SemCAMS Keyera Min TOP Commitment

30 MMcf/d

2016 Montney Production 20,000+ Boe/d 15,000+ Boe/d of Future Growth Capacity in Place

2013 2016 2015 2014

Wapiti Montney Processing Capacity

Firm Capacity with TOP flexibility built in All products have virtually 100% FIRM downstream take-away

2017 15 MMcf/d 30 MMcf/d 35 MMcf/d 17 MMcf/d 30 MMcf/d

May 2016

New Sour Gas Plant

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2015 Year-end Reserves Report

2015 Year-end Reserves Report – GLJ Petroleum Consultants Ltd.

  • PDP reserves volume increased 40% before production and dispositions, or 13% after
  • Corporate TP+PA reserves volume increased by 15%
  • Corporate TP+PA F&D of $3.69/Boe & TP F&D of $8.11/Boe – 2015 Corporate Netback

$15.28/Boe – TP+PA Recycle Ratio 4.1x & TP Recycle Ratio 1.9x

  • Corporate TP+PA B-Tax NPV10% decreased 25% to $1.1 billion primarily due to a ~30%

reduction in GLJ's price forecast*

  • Reserve Life Index now at ~27 years and ~13 years on a TP+PA and TP basis, respectively
  • Montney TP+PA average reserves per well increased 4% vs. 2014; Montney TP+PA well

locations now 253, an increase of 23% compared to year end 2014

12 29 86 184 225 98 65 53 36 28 50 100 150 200 250 300 2011 2012 2013 2014 2015 Other Wapiti Montney

Corporate TP+PA Reserves (MMBoe)

253

87 167 847 1,155 938 1,197 612 476 251 120 200 400 600 800 1,000 1,200 1,400 1,600 2011 2012 2013 2014 2015 Other Wapiti Montney

Corporate TP+PA NPV10% ($MM)

1,058

Corporate TP+PA Reserves by Area

* Based on first 3 yr avg prices See Appendix for important disclosures regarding Reserves

May 2016

89% 9% 2% MTY W6 SWT Non-W6

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Commodity Price Risk Management

We are well hedged with under 10% AECO exposure for 2016

May 2016

Floor C$ WTI price of $77.17/Bbl on ~53% of 2016 Q2-Q4 net production Floor AECO price of $3.30/Mcf on ~73% of 2016 Q2-Q4 net production

Basis includes some Chicago pricing. Includes NYMEX hedges converted to an AECO equivalent price.

20.00 40.00 60.00 80.00 100.00 500 1,000 1,500 2,000 2,500 3,000 3,500 2016 Q2 2016 Q3 2016 Q4 2017 Q1 2017 Q2 Price, C$/Bbl Hedged Volume, Bbl/d

Crude Oil Hedge Position

Bbl/d Capped Bbl/d Uncapped

  • Avg. Floor
  • Avg. Ceiling

0.75 1.50 2.25 3.00 3.75 4.50 20,000 40,000 60,000 80,000 100,000 120,000 2016 Q2 2016 Q3 2016 Q4 2017 Q1 2017 Q2 2017 Q3 2017 Q4 2018 Q1 2018 Q2 2018 Q3 2018 Q4 2019 Q1 Price, C$/GJ Hedged Volume, GJ/d

Natural Gas Hedge Position

GJ/d Capped GJ/d Uncapped GJ/d AECO-NYMEX Basis

  • Avg. Floor
  • Avg. Ceiling

Only 5% of gas volumes exposed to AECO this summer

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Funds from Operations and netbacks hanging in there despite low commodity prices

45% 31% 52% 66% 72% 72% 79% 81%

17,823 14,493 18,030 23,165 23,215 21,448 21,622 23,355 25,484

  • 5,000

10,000 15,000 20,000 25,000 30,000 Q114 Q214 Q314 Q414 Q115 Q215 Q315 Q415 Q116 Wapiti Montney Other Properties

NuVista Operating Results

2016 Guidance

Corporate Production (Boe/d) Funds from Operations

2016 Actual Production (Boe/d) Guidance (Boe/d)

Q1 25,484 24,500 - 25,000 2016 FY

  • 24,500 - 25,500

$19.26 $11.42 $16.47 $17.22 $14.52 $15.53 $16.00 $15.15 $13.06 $0 $5 $10 $15 $20 $25 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 $50 Q114 Q214 Q314 Q414 Q115 Q215 Q315 Q415 Q116 ($/BOE) ($MM)

Funds from Operations ($MM) Funds from Operations ($/BOE)

May 2016

2016 Actual Capex ($MM) 2016 Capex Guidance Range ($MM) Q1 $61

  • 2016 FY

$115 - $135

76%

2016 Actual Funds from Operations ($MM) 2016 Funds from Operations Guidance Range ($MM) (1) Q1 $30

  • 2016 FY

$100 - $110

(1) Based on commodity pricing of US$45/Bbl WTI and $1.80/GJ AECO

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  • Balance sheet comes first
  • Top plays win at any price, wells keep improving
  • Focused capital discipline & reducing unit costs
  • No material unutilized TOP cost concerns
  • 2016 Growth despite muted spending
  • Hedging – strong downside protection through 2016+

NuVista: Looking Forward

Flexibility and Strength in a Volatile Environment

We have the Assets We have the Will We have the Team We have the Strategy… To Deliver

May 2016

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Advisory Regarding Oil and Gas Information & Other Advisories

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

  • f 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

  • f 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 which are based on NuVista’s historical production in the Bilbo and Elmworth development areas, in addition to production history from analogous Montney developments located in close proximity to the Wapiti 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 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. 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", "raw EUR", "NPV10", "PIR", "payout", "ROR", "netback", "F&D" and "capital efficiency". 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. 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. 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. NON-GAAP MEASUREMENTS Within this presentation, references are made to terms commonly used in the oil and natural gas industry. Management uses funds flow, debt to annualized funds from operations and netback to analyze operating performance and leverage. Funds from operations as presented, does 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 cash 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. Debt (net debt) is calculated as long-term debt plus current assets less current liabilities and excludes the current portions of the commodity derivative asset or liability.

May 2016

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Advisory Regarding Reserves Disclosure

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, 2015 and is based on an independent evaluation by GLJ using January 1, 2016 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.

May 2016

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APPENDIX

May 2016

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Significant New Wells On-stream

New Record Wells at Bilbo and Significant Step-out at Elmworth

May 2016

Bilbo 01-34 Well Bilbo 16-27 Well Elmworth 01-01 Step-out Well

3,000 6,000 9,000 12,000 15,000 18,000 1,000 2,000 3,000 4,000 5,000 6,000 10 20 30 40 50 Gas Rate (mcf/d) C5+ Rate (bbl/d) Production Days

C5+ Actual (bbl/d) C5+ Type Curve (bbl/d) Gas Actual (mcf/d) Gas Type Curve (mcf/d)

3,000 6,000 9,000 12,000 15,000 1,000 2,000 3,000 4,000 5,000 10 20 30 40 50 Gas Rate (mcf/d) C5+ Rate (bbl/d) Production Days

C5+ Actual (bbl/d) C5+ Type Curve (bbl/d) Gas Actual (mcf/d) Gas Type Curve (mcf/d)

2,000 4,000 6,000 8,000 10,000 12,000 400 800 1,200 1,600 2,000 2,400 5 10 15 20 Gas Rate (mcf/d) C5+ Rate (bbl/d) Production Days

C5+ Actual (bbl/d) C5+ Type Curve (bbl/d) Gas Actual (mcf/d) Gas Type Curve (mcf/d)

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Condensate Pricing

Strong demand and premium price for the long term

  • Condensate is used in Alberta as a diluent

to ship heavy oil on pipelines

  • 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 Canada Condensate Supply and Demand

May 2016

Western Canadian Condensate Pricing

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WAPITI

MONTNEY FAIRWAY

Focus on Wapiti

Our lands contain the Montney with the bonus

  • f significant Deep Basin uphole potential

Wapiti Uphole Zones

DUNVEGAN NOTIKEWIN FALHER BLUESKY GETHING CADOMIN NIKANASSIN A NIKANASSIN C LOWER MONTNEY MIDDLE MONTNEY CADOTTE

Wapiti Montney area uphole potential: The Montney is overlain by a 1.5 km thickness of high potential wet gas and oil Jurassic/Cretaceous deep basin formations … over an area of 100,000+ Ac

Acres 000's Dunvegan Falher Wilrich Cadomin Nikanassin Gross 90 112 104 111 119 Net 48 49 48`` 57 97

  • 1,000

2,000 3,000 4,000 5,000 6,000 Production (Boe/d) Liquids Natural Gas

Downstream Nova Restrictions

May 2016

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Montney Delineation

Large Portfolio of Development Opportunities

May 2016

Elmworth Development Block Expanded Bilbo Development Block

Gold Creek Development Area is Emerging

  • 5 producers and 1 test indicative of an emerging development block
  • Area tied-in to NuVista Infrastructure
  • Gas IP30's up to 7 MMcf/d (choked) and Condensate rates over 475 Bbls/d
  • IP30 CGR's range from 55 to 161 Bbls/MMcf
  • Sub-block type-curve(s) to be established with additional well results

Bilbo Development Block Expanded

  • Powerful South step-out well – far above typecurve
  • Expands Bilbo Development block to include all NuVista lands

NVA Producing Montney

Montney HZ’s

New Block SW of Elmworth is Emerging

  • Three successful step-out results
  • Encouraging initial gas rates and evidence of material condensate content

extending to the southwest

  • H2S in-line with Elmworth Block
  • Specifics of type-curve to be established

R8W6 R6W6 T65 T67 T69

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Lower Montney Activity

NuVista Data Collection In Progress

Elmworth Wapiti South Wapiti Gold Creek Bilbo Kakwa Karr Pipestone

SCL 1-33-67-5W6 Producing 7Gen 13-24-65-5W6 Producing (dual lateral) 7Gen 12-32-64-5W6 Producing 7Gen 15-22-63-3W6 Producing Confidential 30-Jan-2016

NVA Lands Montney Wells LWR Montney A Wells LWR Montney Cores

  • 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 pilot deferred until

commodity price recovery

NVA 15-13-68-7W6 Vertical Over-pressured – 133 Bbls/MMcf condy

May 2016

ACL 1-7-67-7W6 Producing Confidential: 07-Oct-2015 SCL 9-27-66-7W6 Confidential: 14-Feb-2016 T70 T68 T66 R9W6 R7W6 R5W6 R3W6