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Disciplined Liquids Development in Four Prolific Core Areas Investor - - PowerPoint PPT Presentation

Disciplined Liquids Development in Four Prolific Core Areas Investor Presentation TSX: AAV October 2019 ADVANTAGE AT A GLANCE TSX 52-week trading range $1.35 - $3.89 Shares Outstanding (basic) 187 million Market Capitalization


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SLIDE 1

“Disciplined Liquids Development in Four Prolific Core Areas”

TSX: AAV Investor Presentation October 2019

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SLIDE 2

ADVANTAGE AT A GLANCE

2

Advantage holds 131,840 net acres (206 net sections) in the condensate/light oil-rich Montney Glacier/Pipestone fairway

Glacier Progress Valhalla Pipestone/ Wembley

Advantage Montney Assets

Notes: (1) Forward-looking information. Refer to three year development plan (November 1, 2018 and July 8, 2019 news releases) and Advisory for material assumptions and risk factors.

6 Miles

TSX 52-week trading range $1.35 - $3.89 Shares Outstanding (basic) 187 million​ Market Capitalization $0.3 billion Enterprise Value $0.6 billion​ 2019 Guidance (1)​ Total Production 43,500 to 46,500 boe/d Liquids Production (~100% Increase vs 2018) 2,900 to 3,200 bbls/d​ Q2 2019 Production​ Total Production 42,982 boe/d​ Liquids Production 2,580 bbls/d

BC AB

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SLIDE 3

BUILDING ON FOUNDATIONAL ASSETS, TRANSITIONING TO TOP-TIER LIQUIDS

3

Free Cash Generating Asset Ultra-Low Costs Financial Strength & Flexibility Exposure to AECO < 20%(1)

Solid Today Solid Tomorrow

Reinvest in Our High Return Liquids Assets Retain Competitive Edge with Commanding Infrastructure Minimal Commitments and Self- Funding Program Revenue Diversification to Continue by Increasing Liquids

(1) Forward-looking information. Percent of forecast revenue expected to be exposed to AECO in 2019 & beyond. Refer to three year

development plan (November 1, 2018 and July 8, 2019 news releases) and Advisory for material assumptions and risk factors.

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SLIDE 4

COMMITMENT TO ENVIRONMENTAL LEADERSHIP AND SUSTAINABILITY

4

1,000 2,000 3,000 4,000 5,000

10 20 30 40

Non-Producing Net Wells (AIF 2018)

LMR (Jan 2019)

Non-Producing Wells vs LMR

Advantage

47,393 40,853 57,410 56,999 90,367

2014 2015 2016 2017 2018

CO2 Sequestration

(tonnes CO2e accredited)

0.34% 0.30% 0.22% 0.14%

2015 2016 2017 2018

Plant Flared Volumes as Percent of Production

90,000 tonnes CO2e equates to

  • approx. 20,000 vehicles (1)

Improved operating efficiencies and lower emission equipment design Ultra-low liability exposure

(1) Based on estimates per Environmental Protection Agency emissions per vehicle (2) LMR – Liability Management Ratio as determined by Alberta Energy Regulator

  • Natural gas is the fastest way to reduce

CO2 emissions – by displacing coal

  • Created 650 full-time jobs/year over the

last 5 years

  • Contributed >$1 million to community

programs since inception

  • Fully reclaimed equivalent of 60% of

legacy Advantage field sites to date

  • See Sustainability Report on AAV website

“A Proud Clean Energy Producer – The World Needs More of Our Energy”

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SLIDE 5

5 20% 15% 4% 2% 11% 39% 8% 12% 19% 16% 9% 17% 16% 20% 39% 53% 2019E 2020E 2021E

Total Revenue Diversification

>50% Liquids by 2021

Liquids Midwest US Dawn Fixed Price Empress AECO

Well Diversified Natural Gas Portfolio

LIQUIDS DEVELOPMENT PROGRAM OBJECTIVES

Value Enhancement (1)

  • Transition to >50% liquids revenue

(condensate/light oil)

  • Double digit Adjusted Funds Flow

(“AFF”) per share growth

  • Double digit return on capital

employed

  • Generates significant free cash &

maintains Total Debt to AFF ~2.0x

  • Preserves low cost structure
  • Develops significant AFF from

Wembley, Progress & Valhalla in addition to Glacier

Notes: (1) Forward-looking information. Refer to three year development plan (November 1, 2018 and July 8, 2019 news releases) and Advisory for material assumptions and risk factors.

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SLIDE 6

6 Valhalla Wembley Pipestone/

6 miles

LIQUIDS DEVELOPMENT UNDERPINNED BY TOP TIER ASSETS (1)

Condensate & Light Oil Focused

  • Glacier asset generating free cash
  • Significant oil pool discovery at

Progress

  • Valhalla and Pipestone/Wembley

liquids development underway

  • Utilize 3rd party gas processing for

initial Pipestone/Wembley wells

  • 5,000 bbls/d liquids hub at

Pipestone/Wembley on-stream Q2 2020 (100% working interest)

  • Existing spare processing capacity

at Glacier Plant to accommodate growth at Progress and Valhalla

(1) Forward-looking information. Refer to three year development plan (November 1, 2018

and July 8, 2019 news releases) and Advisory for material assumptions and risk factors.

Glacier ‘The Foundation’

Multi-zone Premium Liquids Development Throughout the Fairway

Progress BC AB

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SLIDE 7

216 129 11 70 697 244 <25 bbls/mmcf 25-100 bbls/mmcf >100 bbls/mmcf

Deep Liquids-Rich Inventory (1)(2)(3)

Booked Undeveloped Unbooked Upside

OPERATIONS OVERVIEW – SHIFTING TO MIDDLE MONTNEY LIQUIDS

7

  • Total of ~206 net sections (131,840 net acres)
  • Middle Montney is liquids-rich throughout (25 to 280

bbls/mmcf)

  • Only 65 liquids-rich wells drilled to date – 5% of inventory
  • 100% Ownership of Glacier Gas Plant
  • 400 mmcf/d capacity, 6,800 bbls/d liquids handling

Liquids-rich Middle Montney

(1) Management Estimates. Refer to Advisory. (2) Based on Sproule December 31, 2018 Reserves Report. (3) C3+ shallow cut recoveries.

TOTAL future location inventory ~1,400 to 1,500

Glacier Pipestone/ Wembley Valhalla Progress

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SLIDE 8

ADVANTAGE MONTNEY – MULTIZONE DEVELOPMENT THROUGHOUT

8

Advantage Operated HZ Offset Operator HZ

New oil pool discovery Wembley primary target Glacier liquids zones Valhalla liquids appraisal targets

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SLIDE 9

WEMBLEY/VALHALLA (PIPESTONE) LIQUIDS RICH DEVELOPMENT

9

  • 75 net sections in the premium, multi-

layer, liquids fairway

  • Valhalla wells are tied into AAV Glacier

Plant to the West

  • Wembley wells will flow South to

Tidewater and Keyera plants

  • Seven Wembley wells planned for Q3/Q4

2019, plus one water disposal

  • Wembley area continues to show

predictable, top tier results across the fairway (150-300 bbls/mmcf)

  • Valhalla showing similar results, though

earlier in development

Valhalla Pipestone/Wembley

New 5 well pad 7,117 boe/d (22% liquids)(1) 4 well pad drilling

(1) Aggregate initial production rate from 5 wells (2) Rate of Return is the percentage return earned on the capital invested in a well during the well’s producing life assuming initial capital of $5.8 million per well DCE+T (drilling, completion, equipping and tie-in) with natural gas and NGL prices and costs escalated at 1.5% annually. (3) Breakeven based on NPV10 pre-tax equal to zero and calculated AECO Cdn price. (4) Kelt Exploration public disclosure

Competitor well IP30 1,422 boe/d (67% liquids) (4) Confidential competitor well (~41% oil, NGL not available)

Half-cycle Economics(2)(3)

(AECO Cdn $2.00/mcf & $US 60/bbl WTI)

Rate of Return % Payout Years Breakeven(3) >100% 1.2 - 1.4 <$1.00/mcf

Recently completed D3 Well 30% liquids (IP30) Confidential competitor well (~44% oil, NGL not available) AAV 12-25 (62% liquids)

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SLIDE 10

SIGNIFICANT LIGHT OIL POOL DISCOVERY AT PROGRESS

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  • 47 net sections assembled at low cost
  • ver 5 years
  • Appraisal drilling began in 2017
  • 4 Advantage wells drilled to date
  • Recent advancement in frac design at

16-36 resulted in >1,000 bbls/d oil rate(1)

  • Recent pressure data indicates majority
  • f lands are over-pressured
  • Pipeline to AAV Glacier Plant to be

constructed November 2019

16-36 Montney D3 (1) 1,038 bbls/d oil 290 bbls/d NGL 4.9 mmcf/d gas

02/2-34 Montney D3 (2018) 5-22 Montney D3 (2018) 13-31 Montney D1 (2017)

(1) Average rate at 5,168 kPa over 72 hours at end of frac flowback and production test. Entrained NGLs calculated using composition from 02/2-34 well and shallow-cut recoveries. Production rates were continuing to increase prior to the well being shut in due to flare limitations. Preliminary results are not necessarily indicative of long-term performance or of ultimate recovery.

Kelt Oil Wells Up to 153,000 bbls CTD Tourmaline Oil Wells Up to 152,000 bbls CTD

Tie in to AAV Glacier Plant

Progress oil wells are expected to be competitive with Wembley/Pipestone

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SLIDE 11

LIQUIDS-RICH MIDDLE MONTNEY AT GLACIER STEPPING UP

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Half-cycle Economics(1)(2)

(AECO Cdn $2.00/mcf & $US 60/bbl WTI)

Rate of Return % Payout Years Breakeven(3)

(AECO Cdn $)

40% - 90% 1.4 – 2.2 <$1.00/mcf

  • Early development was in Upper and Lower

Montney (lean gas)

  • Recent focus on Middle Montney, where liquids

range from 25 to 80 bbls/mmcf

  • 90 net sections
  • 750 well inventory (4), including 480 liquids-rich
  • Low costs = resilient netbacks
  • IP30 well liquids rates up to 400 bbls/d
Middle Montney 3 Middle Montney 4 Middle Montney 2 (1) Management estimates. (2) Rate of Return is the percentage return earned on the capital invested in a well during

the well’s producing life assuming initial capital of $4.8 million per well DCE+T (drilling, completion, equipping and tie-in) with natural gas and NGL prices and costs escalated at 1.5% annually.

(3) Breakeven based on NPV10 pre-tax equal to zero and calculated AECO Cdn price. (4) There are 303 proved and 28 probable undeveloped locations booked by our

independent reserve evaluator in this area. All remaining locations are unbooked estimates by Management. Refer to Appendix and Advisory. Q1 2019 10 Well Middle Montney Pad – Average Final Rate 422 bbls/d (73 bbls/mmcf) Q4 2018 5 Well Middle Montney Pad – Average Final Rate 428 bbls/d per Well (85 bbls/mmcf)

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SLIDE 12

STRATEGIC INFRASTRUCTURE CONTROL, FLEXIBLE PIPELINE ACCESS

Advantage Glacier Gas Plant

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  • NGTL sales gas firm transportation service in-place. Connection to Alliance pipeline completed.
  • >100 mmcf/d surplus capacity available at Glacier Plant
  • Pipeline to tie Progress in to AAV Glacier Plant to be constructed by November 2019
  • 3rd Party processing secured to match early Pipestone/Wembley growth profile

100% Owned Glacier Gas Plant – 400 mmcf/d Raw Gas + 6,800 bbls/d C3+ Liquids Extraction

AAV Liquids Handling Hub 2,000 bbls/d Keyera Pipestone Plant Tidewater Pipestone Plant Company Land Company Gas Plant 3rd Party Gas Plants TransCanada Pipeline Pembina Pipeline Advantage Pipeline Alliance Pipeline Tidewater Pipeline AAV Wembley Liquids Hub 5,000 bbls/d Q2-2020 Future AAV Progress Liquids Hub

BC AB

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SLIDE 13

2019 GUIDANCE AND ESTIMATES (1)(2)

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Average production (boe/day) 43,500 - 46,500 Gas production (mmcf/d) 244 to 260 Liquids production (bbls/d) 2,900 to 3,200 % Liquids / % Condensate/light oil 7% / 76% Royalties ($/boe) and Royalty Rate (%) $0.40 (3%) Operating Cost ($/boe) $2.00 Transportation Cost ($/boe) $3.40 G&A/Finance Cost ($/boe) $1.50 Cash Used in Investing Activities (4) (millions) $180 to $200 Net Capital Expenditures (3)(4) (millions) $180 to $200

Notes: (1) Forward-looking information. Refer to Advisory for cautionary statements regarding Advantage’s budget and three-year development plan including material assumptions and risk factors. (2) Refer to Three Year Plan news release dated November 1, 2018 and 2019 capital expenditure guidance in news release dated July 8, 2019. (3) Non-GAAP Measure which may not be comparable to similar non-GAAP measures used by other entities. Refer to Advisory. (4) Net Capital Expenditures is the same as Cash Used in Investing Activities as no change in non-cash working capital is assumed between years and

  • ther differences are immaterial.
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SLIDE 14
  • Capital program calibrated to maintain

strong balance sheet

  • Flexibility exists to manage gas production

with minimal impact on adjusted funds flow

$0.40 $0.75 $1.20 $2.00 $2.60 $2.95 $3.40 $3.55 $3.65 $1.50 $1.60 $1.55 2019G 2020E 2021E

Costs ($/boe)

THREE YEAR DEVELOPMENT PLAN – LIQUIDS TRANSITION(1)

14 7% 15% 22%

43,500 to 46,500 46,000 to 48,000 48,500 to 52,500

2019G 2020E 2021E

Total Production (boe/d)

Gas Liquids % of Total 76% 76% 78%

2,900 to 3,200 6,500 to 7,500 10,500 to 11,500

2019G 2020E 2021E

Liquids Production and Composition (bbls/d) C5+ / light oil

Notes:

(1) Forward-looking information. Refer to three year development plan (November 1, 2018 and July 8, 2019 news releases)

and Advisory for material assumptions and risk factors. G – Guidance, E - Estimates

14,000 bbls/d Exit

Three Year Development Plan

Royalties Operating Transport G&A and Finance

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SLIDE 15

1.6 1.4 1.0 1.8 1.8 1.3

2019 2020 2021

Gas Price Sensitivity

Total Debt to Adjusted Funds Flow (2)

(@ WTI US$58/bbl Flat)

DEVELOPMENT PLAN PRICE SENSITIVITY(1)

15

AECO $1.30/mcf AECO $1.70/mcf

1.6 1.2 0.6 1.9 2.0 1.6

2019 2020 2021

Oil Price Sensitivity

Total Debt to Adjusted Funds Flow (2)

(@ AECO Cdn$1.65/mcf Flat)

WTI US$50.00/bbl WTI US$70.00/bbl

Notes: (1) Forward-looking information. Refer to three year development plan (November 1, 2018 and July 8, 2019 news releases) and

Advisory for material assumptions and risk factors.

(2) Non-GAAP measure which may not be comparable to similar non-GAAP measures used by other entities. Refer to Advisory. (3) Estimated average three-year C5+/Light Oil differential to WTI of US$7.50/bbl and FX $0.755 Cdn/US. Other market

diversification based on future prices as of April 2, 2019.

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SLIDE 16

STRONG HEDGES AND TRANSPORTATION IN-PLACE (1)

16

Notes:

(1) Forward-looking information. Refer to three year development plan (November 1, 2018 and July 8, 2019 news releases)

and Advisory for material assumptions and risk factors.

Transportation

  • Sufficient current and future

transportation capacity available to meet requirements of 2019-2021 development plan

  • Actively manage contracted

transportation capacity to optimize portfolio

Hedging Strategy

  • Summer 2019 AECO hedges mitigate

volatility

  • Expect to hedge both liquids and natural

gas in future periods

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 20 40 60 80 100 120 140

Q1-19 Q2-19 Q3-19 Q4-19 Q1-20 Q2-20 Q3-20 Q4-20

Current Hedging Transactions (MMcf/d)

AECO ($Cdn/Mcf) Dawn ($US/Mmbtu) % of AECO Exposure Hedged % of Dawn Exposure Hedged

$2.83 $1.84 $1.84 $2.12 $2.26 $1.36 $1.36 $1.36 $3.01 $2.87 $2.87 $3.16 $3.01
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SLIDE 17

Returns Focus Financial Discipline Operationally Nimble

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SLIDE 18

APPENDIX

18

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SLIDE 19

GLACIER – LOCATED IN THE HEART OF THE MONTNEY RESOURCE PLAY

Montney Siltstone Comparison:
  • 700 times more permeability
  • 4x more formation thickness
  • Very low clay content
  • Liquids & Improved well efficiencies strong economics
Up to 83 bbls/MMcf

19

Glacier

Pipestone Liquids Fairway

Source: Geoscout, Corporate Presentations

BC AB

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SLIDE 20

CONTINUOUS IMPROVEMENT HAS LED TO EXCEPTIONAL EFFICIENCIES

20

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SLIDE 21

MIDDLE MONTNEY PRODUCTION CONTINUES TO INCREASE

  • 2017+ Middle Montney wells with frac design changes

including >30 frac stages & numerous mechanical systems evaluated

  • 39 total Middle Montney wells on-production across

Glacier land block.

2013 4 wells Gen 2: Poly CO2, & Slickwater Plug and Perf Avg 13 frac stages 2012 2 wells Gen 1: Poly CO2, Sand Plugs, Avg 15 frac stages 2014 3 wells Gen 3: Slickwater, OH Packers Avg 15 frac stages 2015 13 wells Gen 4: Slickwater, OH Packers Avg 19 frac stages

Middle Montney Budget Type Curve (IP30 5.0 mmcf/d & 5.0 Bcf) 21

2018/19 11 wells Gen 6: Slickwater, OH Packers, Stage completions Avg 33 frac stages 2016/17 6 Wells Gen 5: Slickwater, OH Packers, Cased hole & Stage completions Avg 27 frac stages

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SLIDE 22

GLACIER MONTNEY ASSIGNED 2P EUR PER WELL & INTERVAL

(1) Based on Sproule 2016 - 2018 year-end reserve reports. Indicated raw gas volumes per well. Refer to Statement of Reserves Data and Other Oil and Gas Information in the Corporation’s Annual Information Forms which are available at www.sedar.com and www.advantageog.com.

22 Glacier - 2P Recoveries per Interval(1)

Interval

# of Gross HZ Wells 2P Recovery [bcf/well]

Developed Undeveloped Total Developed Undeveloped Total YE 2016 YE 2017 YE 2018 YE 2016 YE 2017 YE 2018 YE 2016 YE 2017 YE 2018 YE 2016 YE 2017 YE 2018 YE 2016 YE 2017 YE 2018 YE 2016 YE 2017 YE 2018 1 UM 103 111 115 141 133 130 244 244 245 4.9 5.1 5.2 5.9 5.8 5.8 5.4 5.5 5.5 2 MM 12 15 22 52 65 61 64 80 83 5.8 5.6 6.4 5.2 5.6 5.4 5.3 5.6 5.7 3 MM 8 10 13 25 35 40 33 45 53 4.5 4.4 4.6 4.1 4.4 4.4 4.2 4.4 4.5 4 MM 2 3 4 5 11 14 7 14 18 6.1 7.4 7.7 5.9 6.6 6.6 6.0 6.7 6.8 5 LM 43 51 54 84 81 86 127 132 140 7.1 7.7 7.8 6.4 6.5 6.4 6.6 6.9 6.9 Total 168 190 208 307 325 331 475 515 539 Interval

# of Gross HZ Wells 2P Recovery [bcf/well] Developed Undeveloped Total Developed Undeveloped Total

YE 2016 YE 2017 YE 2018 YE 2016 YE 2017 YE 2018 YE 2016 YE 2017 YE 2018 YE 2016 YE 2017 YE 2018 YE 2016 YE 2017 YE 2018 YE 2016 YE 2017 YE 2018 1 UM 2 4 4 5 5 2 9 9 2.9 6.6 6.8 7.9 7.5 2.9 7.3 7.2 2 MM 1 2 2 5 7 1 7 9 4.4 4.3 5.0 4.1 4.2 4.4 4.2 4.4 4 MM 1 1 2 2 3 3 2.1 3.8 2.1 3.4 2.1 3.5 Total 3 7 7 12 14 3 19 21

Valhalla - 2P Recoveries per Interval(1)

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SLIDE 23

WEMBLEY MONTNEY ASSIGNED 2P EUR PER WELL & INTERVAL

(1) Based on Sproule 2017 and 2018 year-end reserve reports. Indicated raw gas volumes per well. Refer to Statement of Reserves Data and Other Oil and Gas Information in the Corporation’s Annual Information Forms which are available at www.sedar.com and www.advantageog.com.

23 Wembley Montney Assigned 2P EUR Per Well & Interval(1)

Interval

# of Gross HZ Wells 2P Gas & Free Liquids Recovery [bcf/well mstb/well]

Developed Undeveloped Total Developed Undeveloped Total YE 2017 YE 2018 YE 2017 YE 2018 YE 2017 YE 2018 YE 2017 YE 2018 YE 2017 YE 2018 YE 2017 YE 2018 4 MM 1 11 12 2.3 358 2.3 358 2.3 358 Total 1 11 12
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SLIDE 24

Forward-Looking Information and Statements The information in this presentation contains certain forward-looking information and forward-looking statements (collectively, "forward-looking statements") within the meaning of applicable securities laws relating to the Corporation's plans and other aspects of its anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. These statements relate to future events or our future intentions or performance. All statements other than statements of historical fact may be forward-looking statements. The statements have been prepared by management to provide an

  • utlook of the Corporation's activities and results and may not be appropriate for other purposes. Forward-looking statements are often, but not always, identified

by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “guidance”, “demonstrate”, “expect”, “may”, “can”, “will”, “project”, “predict”, “potential”, “target”, “intend”, “could”, “might”, “should”, “believe”, “would” and similar expressions and include statements relating to, among other things, the Corporation's 2019 to 2021 Development Plan (the "Plan"), the Plan's development focus and the timing thereof, the expected sources of funding for the Plan; expected results and benefits to be derived from the Plan include, but are not limited to, increasing the anticipated amount of annual average liquids production, increasing C5+/light oil production mix and the expected amount of C5+/light oil production mix, diversifying the Corporation's revenue sources including the composition of natural gas and liquids, developing additional operational and infrastructure optionality and how this will be achieved; annual production average and the expected amount by which total annual average production will be increased by in 2019 to 2021; expected net capital expenditures for 2019 to 2021, including the expected focus and allocation of such expenditures; the expected cumulative capital investment over the Plan's three years; resource development potential beyond the Plan and the Corporation's future drilling inventory; the benefits derived from third party processing arrangements the Corporation entered into with two midstream firms; and other matters. Advantage’s actual decisions, activities, results, performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that Advantage will derive from them. With respect to the forward-looking statements contained in this presentation, Advantage has made a number of material assumptions regarding, but not limited to: current and future commodity prices; the Corporation's current and future hedging program; future exchange rates; future production and composition including natural gas and liquids; royalty regimes and future royalty rates; future operating costs; future transportation costs and availability of product transportation capacity; future general and administrative costs; the estimated well costs including frac stages and lateral lengths per well; the number of new wells required to achieve the objectives of the Plan; that the Corporation will be able to complete its infrastructure projects on a timely basis; the timing for the construction to be completed on third party mid-stream facilities; timing and amount of net capital expenditures; and that the Corporation will have sufficient financial resources required to fund its capital and operating expenditures and requirements as needed.

ADVISORY

24

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SLIDE 25

Management has included the summary of assumptions and risks related to forward-looking information in order to provide shareholders with a more complete perspective on Advantage's future operations and such information may not be appropriate for other purposes. Advantage’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Advantage will derive there from. Management does not have firm commitments for all the costs, expenditures, prices or other financial assumptions used to prepare the forward-looking information or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. Readers are cautioned that the foregoing lists of factors are not exhaustive. The Corporation and management believe that the statements have been prepared on a reasonable basis, reflecting management's best estimates and judgments. However, because this information is highly subjective and subject to numerous risks including the risks discussed above, it should not be relied on as necessarily indicative of future results. These forward-looking statements are made as of the date of this presentation and Advantage disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or

  • therwise, other than as required by applicable securities laws.

These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond Advantage’s control, including, but not limited to: changes in general economic, market and business conditions; industry conditions; impact of significant declines in market prices for oil and natural gas; actions by governmental or regulatory authorities including increasing taxes and changes in investment or other regulations; changes in tax laws, royalty regimes and incentive programs relating to the oil and gas industry; the effect of acquisitions; Advantage's success at acquisition, exploitation and development of reserves; failure to achieve production targets on timelines anticipated or at all; unexpected drilling results; changes in commodity prices, currency exchange rates, net capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties, including hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; changes or fluctuations in production levels; individual well productivity; lack of available capacity on pipelines; delays in anticipated timing of drilling and completion of wells; delays in completion of infrastructure; lack of available capacity on pipelines; individual well productivity; competition from other producers; the lack of availability of qualified personnel or management; credit risk; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; our ability to comply with current and future environmental or

  • ther laws; stock market volatility and market valuations; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil

and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; ability to obtain required approvals of regulatory authorities; and ability to access sufficient capital from internal and external sources. Many of these risks and uncertainties and additional risk factors are described in the Corporation’s Annual Information Form dated February 28, 2019 which is available at www.Sedar.com and www.advantageog.com. Readers are also referred to risk factors described in other documents Advantage files with Canadian securities authorities.

ADVISORY

25

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SLIDE 26

Oil and Gas Information Barrels of oil equivalent ("boe") and thousand cubic feet of natural gas equivalent ("mcfe") may be misleading, particularly if used in isolation. Boe and mcfe conversion ratios have been calculated using a conversion rate of six thousand cubic feet of natural gas equivalent to one barrel of oil. A boe and mcfe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. This presentation discloses drilling inventory in the Glacier, Valhalla, Progress and Pipestone/Wembley areas in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from Sproule Associates Limited reserves evaluation effective December 31, 2018 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 1,400 to 1,500 total drilling locations identified herein, 327 are proved locations, 29 are probable locations and 1,044 to 1,144 are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Corporation will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations,

  • ther unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir

and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. References in this presentation to production test rates, initial production rates, IP30 rates, flow rates, yields and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of Advantage. Advantage cautions that the test results should be considered to be preliminary.

ADVISORY

26

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SLIDE 27

Advantage has presented certain type curves and well economics for its Montney areas. The type curves presented are based on Advantage's historical

  • production. Such type curves and well economics are useful in understanding management's assumptions of well performance in making investment

decisions in relation to development drilling in the Montney area and for determining the success of the performance of development wells; however, such type curves and well economics are not necessarily determinative of the production rates and performance of existing and future wells and such type curves do not reflect the type curves used by our independent qualified reserves evaluator in estimating our reserves volumes. The type curves differ as a result of varying horizontal well length, stage count and stage spacing. The type curves represent the average type curves expected. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented; however, there is no certainty that Advantage will ultimately recover such volumes from the wells it drills. In presenting such type curves, inputs and economics information and in this presentation generally, Advantage 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 DCE+T, "EUR", "NPV10", "payout", "rate of return" (or "ROR"), "half cycle ROR", and “operating netback". EUR represents the estimated ultimate recovery of resources associated with the type curves presented. NPV10 represents the anticipated net present value of the future net revenue discounted at a rate of 10% associated with the type curves presented. Payout means the anticipated years of production from a well required to fully pay for the DCE+T 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. Half cycle ROR means the rate of return of a well or the discount rate required to arrive at a NPV equal to zero when taking into account "half cycle" costs, which include drilling, completion, equip and tie-in capital expenditures. Production estimates contained herein are expressed as anticipated average production over the calendar year. In determining anticipated production for the years ended 2019 to 2021 Advantage considered historical drilling, completion and production results for prior years and took into account the estimated impact on production of the Corporation’s 2019 to 2021 expected drilling and completion activities.

ADVISORY

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ADVISORY

Non-GAAP Measures The Corporation discloses several financial and performance measures that do not have any standardized meaning prescribed under International Financial Reporting Standards ("IFRS" or “GAAP”). These financial and performance measures include “net capital expenditures”, “adjusted funds flow”, “total debt”, and “total debt to adjusted funds flow”. Such financial and performance measures should not be considered as alternatives to, or more meaningful than measures determined in accordance with GAAP including “net income”, “comprehensive income”, “cash provided by operating activities”, or “cash used in investing activities”. Management believes that these measures provide an indication of the results generated by the Corporation’s principal business activities and provide useful supplemental information for analysis of the Corporation’s operating performance and liquidity. Advantage’s method of calculating these measures may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies. “Net capital expenditures” include total capital expenditures related to property, plant and equipment and exploration and evaluation assets incurred during the period. Management considers this measure reflective of actual capital activity for the period as it excludes changes in working capital related to other

  • periods. The Corporation considers “adjusted funds flow” to be a useful measure of Advantage’s ability to generate cash from the production of natural gas

and liquids, which may be used to settle outstanding debt and obligations, and to support future capital expenditures plans. Changes in non-cash working capital are excluded from adjusted funds flow as they may vary significantly between periods and are not considered to be indicative of the Corporation’s

  • perating performance as they are a function of the timeliness of collecting receivables or paying payables. Expenditures on decommissioning liabilities are

excluded from the calculation as the amount and timing of these expenditures are unrelated to current production, highly variable and discretionary. “Total debt” is the total of bank indebtedness and working capital deficit. “Total debt to adjusted funds flow” is a ratio calculated as total debt divided by adjusted funds flow for the previous four quarters. Total debt to adjusted funds flow is considered by management to be a useful measure as it is commonly used to evaluate the leverage of a company and the ability to settle outstanding debt and obligations with cash generated from operations. Refer to the Corporation’s most recent Management’s Discussion and Analysis, which is available at www.sedar.com and www.advantageog.com, for additional information about certain financial measures, including reconciliations to the nearest GAAP measures, as applicable.

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ADVISORY

Abbreviations The following abbreviations used in this presentation have the meanings set forth below. bbl barrel bbl/d barrel per day bbls/d barrels per day bbls/mmcf barrels per million cubic feet boe barrels of oil equivalent of natural gas, on the basis of one barrel of oil or natural gas liquids for six thousand cubic feet of natural gas boe/d barrels of oil equivalent per day GJ Gigajoule mcf thousand cubic feet Mcfe thousand cubic feet equivalent on the basis of six thousand cubic feet of natural gas for one barrel of oil or natural gas liquids mmcf/d million cubic feet per day mmcfe/d million cubic feet equivalent per day NGL natural gas liquids DCE+T drill, complete, equip and tie-in C3+ propane plus C5+ pentanes plus

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ADVANTAGE CONTACT INFORMATION

Investor Relations

1.866.393.0393 ir@advantageog.com www.advantageog.com Listed on TSX: AAV

Advantage Oil & Gas Ltd.

Suite 2200, 440 – 2nd Avenue SW Calgary, Alberta T2P 5E9 Main: 403.718.8000 Facsimile: 403.718.8332

Andy Mah, P.Eng. Director, President & Chief Executive Officer Mike Belenkie, P.Eng. Chief Operating Officer Craig Blackwood, C.A. Chief Financial Officer

Advantage 100% W.I. Glacier Gas Plant