Investor Presentation TSX / NYSE: AAV May 2017 ADVANTAGE AT A - - PowerPoint PPT Presentation

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42% Production Growth to 238 mmcfe/d (39,635 boe/d) and a 79% Increase in Cash Flow to $54 Million Fully Funded our Q1 2017 Capital Program. 39% Increase in Undeveloped Montney Land Adds to Long Term Development Upside" Investor

SLIDE 1

“42% Production Growth to 238 mmcfe/d (39,635 boe/d) and a 79% Increase in Cash Flow to $54 Million Fully Funded our Q1 2017 Capital Program. 39% Increase in Undeveloped Montney Land Adds to Long Term Development Upside"

TSX / NYSE: AAV Investor Presentation

May 2017

SLIDE 2

ADVANTAGE AT A GLANCE TSX, NYSE: AAV

TSX 52-week trading range $6.59 - $10.33 Shares Outstanding (basic) 185.1 million Annual Production - 2017 Budget 236 mmcfe/d (39,330 boe/d) Market Capitalization @ May 1, 2017 $1.6 billion As of March 31, 2017: $148 million Bank Debt (37% drawn on $400 million Credit Facility) Total Debt (including working capital deficit) $159 million Q1 2017 Total Debt /Trailing 12 Month Cash Flow 0.8x

View of Glacier Plant Process Train – approximately 1,250 feet long

16% Production Growth

SLIDE 3

3 Own & Operate 100% Plant & Infrastructure Industry Leading N.A. Low Cost Gas Supply Strong Balance Sheet 0.8x D/CF Q1 2017 World Class Montney Asset

(178 net sections total)

OUR STRATEGY – LONG TERM PROFITABLE & SUSTAINABLE GROWTH

1) % of estimated annual future production net of royalties, 45% @ $3.19 Cdn/mcf 2017, 22% @ $3.02 Cdn/mcf 2018 & 18% @ $3.00 Cdn/mcf Q1 2019

Hedging & Market Diversification (1) Operating & Financial Flexibility

24 net undeveloped sections added YTD 2017

(see page 15)

SLIDE 4

LAST 3 YEARS - A SOLID TRACK RECORD OF VALUE GENERATION

98%

23%

Advantage Oil & Gas Ltd. S&P/TSX Composite Index (Total Return) S&P/TSX Capped Energy Index (Total Return) S&P/TSX Oil & Gas Exploration & Production GICS Sub Industry (Total Return)

THREE-YEAR TOTAL SHAREHOLDER RETURN

(Dec. 31/13 to Dec. 31/16)

$/mcfe

Natural gas and liquids sales price including realized hedging gains $2.89 Total Corporate Cash Costs $(0.66) Total Capital Costs, PDP F&D $(0.84) 2016 Full Cycle Netback $1.39 2016 Annual Return on Capital 48% 3 Year Average Annual Return on Capital 29%

2016 RETURN ON CAPITAL

Advantage Oil & Gas Ltd.

1) Corporate cash costs include natural gas transportation fees as of Nov. 1, 2016. Prior to, fees deducted off revenue as per contractual terms. 2) PDP F&D cost based on Sproule year-end 2016 Reserve Report

(2) (1)

SLIDE 5 Land & Other $5 Well Tie-in $9 Other Facilities $12

Plant Expansion $71 Complete 24 wells $71 Drill 21 wells $37

2017 Capital Estimate 2017 Cash Flow…

2017 Cash Flow (2) AECO $2.95/Mcf 2017 Capital Estimate

(1) Midpoint of 2017 Guidance Range. (2) Based on an average AECO Cdn $2.95/mcf ($2.80/GJ) natural gas price for 2017 and Advantage’s current hedge positions

$210

($ million)

2017 BUDGET FUNDED THROUGH CASH FLOW INCLUDING UPSIZED GLACIER GAS PLANT EXPANSION TO 400 MMCF/D

$205

2017 Highlights (1)

16% Annual Production Growth 23% Cash Flow Per Share Growth(2) 236 MMcfe/d (39,330 Boe/d) Annual Average Production $0.91/mcf Total Cash Costs including natural gas transportation Upsized Glacier Gas Plant Expansion to 400 mmcf/d 100% Firm Gas Sales Transportation Service Year-end 2017E Total Debt/Cash Flow 0.7x

SLIDE 6

(1) As of March 31, 2017. Management estimated initial 30 day average well production rate (IP30). (2) As of March 31, 2017

>65 mmcf/d Surplus Completed Well Productivity IP30 Average(1) This group of wells meets our 2017 production requirements 17 wells Uncompleted Standing Wells(2) contribute to 2018 growth 150 mmcf/d Plant Expansion to 400 mmcf/d in progress >180 mmcf/d Additional Sales Gas Pipeline Capacity, Total 400 mmcf/d capacity 308 mmcf/d Total Firm Natural Gas Transportation Service by 2019 Well Pads Planned to 2019

Glacier Gas Plant 100% working interest Current Capacity 250 mmcf/d

PRODUCTIVITY & INFRASTRUCTURE SUPPORTING 2017 THROUGH 2019 GROWTH

SLIDE 7

ADVANTAGE’S 2017 THROUGH 2019 GROWTH

56% Production Growth (2017 thru 2019) $625 Million Capital Investment $735 Million Cash Flow @ Average AECO Cdn $2.95/mcf ($2.80/GJ) 0.2x YE 2019 Total Debt/Trailing Cash Flow 2008 to 2016 0-221 mmcfe/d

2017 thru 2019 Q4 221 to 325 mmcfe/d

2017 thru 2019 Highlights

Post 2019 400 mmcfe/d (66,670 boe/d)

SLIDE 8

$128 $205 $210 $210

2016 2017 Budget 2018E 2019E

Capital Spending ($ millions)

$7,330 $13,000 $11,800 $10,000

2016 2017 Budget 2018E 2019E

ALL-IN Capital Efficiency (3) ($/boe/d)

$0.92 $1.13 $1.27 $1.55

2016 2017 Budget 2018E 2019E

Cash Flow per Share

203 236 272 316

2016 2017 Budget 2018E 2019E

Annual Average Production (mmcfe/d)

ADVANTAGE GROWTH PLAN 2017 THROUGH 2019(1)

Notes: (1) See Appendix pg. 26 for Plan details (2) Compound annual growth rate. (3) Capital Efficiency calculated using 30% per annum decline and includes total annual capital expenditures $11,600/boe/d Average 2017-2019

23% 12% 16% CAGR (2) 16% 15% 16% 22%

Cumulative $625 million 2017-2019 Cumulative Cash Flow $735 million 2017-2019

SLIDE 9

1.0 0.7 0.5 0.2

2016 2017 Budget 2018E 2019E

Year-end Total Debt to Cash Flow (1) Ratio

CASH SURPLUS REDUCES TOTAL DEBT TO CASH FLOW

9 $39 $5 $25 $80

2016 2017 Budget 2018E 2019E

Cumulative Cash Surplus(1) @$2.95/MCF ($2.80/GJ)

$110 million surplus 2017-2019

Note: (1) Based on Advantage 2017 Budget and 2018 & 2019 Development Plan estimates assuming an AECO natural gas price of Cdn $2.95/mcf ($2.80/GJ) & the corporation’s hedging positions

SLIDE 10

2017 2018 2019 2020

Sales Gas Target Firm Contracted Service Pending Request IT Service Estimate 100% firm service secured thru 2019. Advantage’s surplus plant & well capacity provides flexibility to capture high pipeline flow periods.

HEDGING, TRANSPORTATION AND MARKETS

Period Production(1) Hedged (net) Average AECO CDN Fixed Price 2017 45% $3.19/mcf 2018 22% $3.02/mcf 2019 Q1 18% $3.00/mcf

Current Hedges

Fixed price removes commodity price and basis

volatility

Guarantees cash flow for hedged volumes

Market Diversification

57% AECO exposure – 2017
Henry Hub - 25,000 mcf/d at U.S. $0.85/mcf basis

2018 to 2019

Henry Hub - 25,000 mcf/d at U.S. $0.90/mcf basis

2019

55,600 GJ/day (52,800 mcf/d) TCPL mainline

commitment to Dawn market

Evaluating N.A. market options

Alliance Connection Option TCPL Transportation Service

Glacier gas plant Assessing Alliance meter station connection Alliance

(1) % of estimated annual future production, net of royalties

TCPL

TCPL Meter Station Possible Alliance Meter Station

SLIDE 11

$0.94 $0.92 $1.02 $1.03 $1.12 $1.30 $1.12 $1.32 $1.58 $1.20 $1.49 $1.86 2017 2018 2019

Cash Flow per Share Sensitivity (1)

AECO $2.00/mcf AECO $2.50/mcf AECO $3.00/mcf AECO $3.50/mcf

0.8 0.5 0.1 0.7 0.3

0.9 0.6 1.2 1.4 1.3 2017 2018 2019

Total Debt to Trailing Cash Flow Sensitivity (1)

DEVELOPMENT PLAN NATURAL GAS PRICE SENSITIVITY – CFPS & D/CF

(1) Includes Advantage’s current hedge positions

SLIDE 12

$110 million $130 million

Mantenance Capital at 325 mmcfe/d Q4 2019 Cash Flow at AECO $1.45/Mcf Cash Flow at AECO $3.00/Mcf Cash Flow at AECO $3.50/Mcf

$305 Million

MAINTENANCE CAPITAL AND SURPLUS CASH FLOW SENSITIVITY ILLUSTRATIVE AT 325 MMCFE/D

Notes (1) Assumes 7.5 mmcf/d /7.5 Bcf for Upper/Lower Montney wells and 5.0 mmcf/d /5.0 Bcf for Middle Montney wells (2) Assumes 9 mmcf/d /9 Bcf for Upper/Lower Montney wells and 6 mmcf/d /6 Bcf for Middle Montney wells

Based on average well type curve (1) Based

n top quartile

type well (2)

Cash Surplus $175 million per Year Cash Surplus $230 million per Year

3 Year Cumulative Surplus $525 million 3 Year Cumulative Surplus $690 million

(NO HEDGING INCLUDED) $130 Million $360 Million

“Surplus Cash Flow Above $1.45/mcf”

SLIDE 13

$2.43/mcfe

$- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 AAV TOU PPY BIR CR ARX VII NVA KEL POU

Select Montney Natural Gas Producers Total Cost Structure – Q4 2016

Interest & other ($/mcfe) G&A ($/mcfe) Royalties incl. GCA adjustments ($/mcfe) Operating costs & transportation ($/mcfe) Source: RBC Capital Markets, Public Disclosures and Advantage Q4 2016 reported actual results

Average of Peers

ATTRACTIVE NETBACKS & RECYCLE RATIOS ARE ACHIEVABLE WITHOUT HEDGING

13 Glacier Netbacks Illustrative AECO Cdn $2.00/mcf Illustrative AECO Cdn $3.00/mcf Revenue (Realized Price) $2.15 $3.17 Royalties ($0.10) ($0.15) Operating Costs Transportation Costs ($0.25) ($0.35) ($0.25) ($0.35) Operating Netback $1.45 $2.42 G&A ($0.09) ($0.09) Finance Expense & other ($0.08) ($0.08) Cash Flow Netback $1.28/mcfe or $7.68/boe $2.25/mcfe or $13.50/boe Recycle Ratio based on 3 Year Average 2P F&D @ $0.46/mcfe (3) 2.8x 4.9x

(1) Natural Gas & Liquids revenue includes adjustments for heat value.

“NO HEDGING INCLUDED”

$/Mcfe AAV - $0.83/mcfe Lowest Total Corporate Cash Cost Montney Producer (includes gas transportation)

(3) 2P F&D includes Future Development Capital and is based on Sproule’s 2014, 2015 and 2016 year-end 2P reserves reports. (2) Includes liquids transportation costs of $0.04/mcfe, gas transportation costs of $0.27/mcfe, and gas fuel costs of $0.04/mcfe.

(1) (2)

SLIDE 14

HIGH QUALITY MONTNEY ASSETS, OPERATIONAL EXCELLENCE

SLIDE 15

GLACIER DRIVES GROWTH THROUGH NEXT DECADE, ADDITIONAL MONTNEY LANDS PROVIDES FUTURE UPSIDE

Glacier 91 net sections Wembley Valhalla 100% owned Glacier Gas Plant

Total 178 net Montney sections (113,920 acres)
24 new undeveloped sections added YTD 2017
Current development at Glacier dry and liquids rich gas with

a future drilling inventory >1,100 locations

Industry drilling adjacent to Valhalla, Wembley & Progress

demonstrate multiple layers and liquid rich potential

Progress

Progress, Valhalla and Wembley are each of sufficient size to support scalable drilling programs

(29.75 sections) (30 sections) (28 sections)

Acquired 24 net sections YTD 2017 for $6 million

SLIDE 16

INDUSTRY ACTIVITY ADJACENT TO PROGRESS, WEMBLEY AND VALHALLA LAND BLOCKS – ADVANTAGE TO DRILL DELINEATION WELLS H2 2017

Drill 12-18 Months (28 Net Sections) Drill 4 Wells 2017 (30 Net Sections) Drill 12-18 Months (29.75 Net Sections)

Upper Montney Middle Montney Lower Montney

Multi-Layer Development

New Locations

Progress Pipestone/Wembley Valhalla

Pipestone Development

Total 87.75 net Montney sections
Each area of sufficient size to support

scaleable drilling programs

Multi-Layer Natural Gas and Liquids Potential
Future Processing at Glacier Gas Plant

New lands 2017 New lands 2017

SLIDE 17

ONLY 7% OF GLACIER’S FUTURE WELL INVENTORY REQUIRED FOR 2017 THRU 2019 DEVELOPMENT

(1) Management Estimates (2) Based on Sproule December 31, 2016 Glacier Reserves Report (3) As of December 31, 2016, gross Hz wells

Only 83 of our 1,100 Future Drill Locations at Glacier is required to achieve

growth to 316 mmcfe/d average 2019

Only 307 undeveloped locations booked in 2P reserves Year End 2016

*Interval 6 not assigned reserves or resource

Liquids Rich intervals Average 50 bbls/mmcf, >45% C5+ East Glacier

2P Reserves Undeveloped Wells 307 >1,100 Future Drilling Locations

Upper 108 Middle 26 Lower 47

Other 181

Drilled(3) Wells by Layer

(1) (2)

SLIDE 18

Longer Laterals, More Frac Stages

3 LM wells average 2,583 meters (longest 2,880 meters) 28 frac stages, 60 tonnes/stage Avg cost DCE&T $4.3 million/well 1 MM well 2,502 meters, 26 frac stages 11.3 mmcf/d, 30 bbls/mmcf C3+, $5.1 million DCE+T

5-16 8 Well Pad

Lower Montney Middle Montney Upper Montney Notes: (1) Each well produced in-line for average of 48 hours to Glacier gas plant, at an average flow pressure of 11.8 mpa (1,623 psi)

5 longer lateral LM wells (still production restricted) are significantly outperforming average well type curve

LM WELLS FROM RECENT 120 MMCF/D EIGHT WELL PAD OUTPERFORMING PRODUCTION TYPE CURVE

(1)

Shorter Laterals Evaluating Spacing & Recovery

3 LM wells average 1,656 meters Avg cost $3.7 million/well DCE&T

SLIDE 19

UPPER & LOWER MONTNEY WELL PRODUCTION CONTINUES TO IMPROVE

New wells are normally restricted to

~10 mmcf/d for frac sand flowback

control during initial 6 months

24 Upper & Lower Montney Wells, average 20 frac stages, started production July 2015.

“Lower Montney Well results beginning to surpass Upper Montney”

Production updated to February, 2017

Budget Type Curve (IP30 7.5 mmcf/d & 7.5 Bcf) IP30 9.0 mmcf/d & 9.0 Bcf Type Curve Production Average (24 wells)

SLIDE 20

MOST RECENT LOWER MONTNEY WELLS WITH UP TO 30 FRAC STAGES (OPEN-HOLE PACKERS AND CEMENTED PORTS)

Wells restricted to ~10mmcf/d for frac sand flowback control during initial 6 months

“Additional Lower Montney wells with longer laterals, reduced frac spacing and cemented ports are continuing to be brought on production.”

Production updated to February, 2017

Budget Type Curve (IP30 7.5 mmcf/d & 7.5 Bcf) IP30 9.0 mmcf/d & 9.0 Bcf Type Curve Production Average (13 wells)

SLIDE 21

GLACIER MIDDLE MONTNEY WELLS EXCEEDING AVERAGE BUDGET TYPE CURVE

Wells are exceeding current type curves
Ongoing delineation identifies sweet spots within

different Middle Montney layers. Frac designs are tailored to further optimize results.

12-2 well (2013) cumulative production > 3.8 Bcfe

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

Production updated to February, 2017

SLIDE 22

ROR = 76% ROR = 108%

7.5/7.5 @ $4.8MM 9/9 @ $4.8MM

Upper & Lower Montney (Dry Gas) ROR = 75% ROR = 106%

5/5 @ $4.8MM 6/6 @ $4.8MM

Middle Montney (50 bbls/mmcf(1)C3+, 45% C5+)

ROBUST GLACIER MONTNEY WELL ECONOMICS

Type Curve & Cost Higher IP & EUR Case

Assumptions:

Management Estimates of IP30, 2P EUR & Capital Costs and includes a 4 month drill to on-production timeframe.
Cdn Aeco $3.00/mcf, flat
Cdn $37/bbl blended C3+ price based on $50 U.S./bbl WTI

(1) East Glacier average

IP30 mmcf/d Higher IP & EUR Case Type Curve & Cost

Advantage achieved >20% DC & E well cost reduction with >35% increase in frac count

Budgeted 2017 Well Cost (DC&E) Bcf

Recent 11 wells at $4.4 million average per well

SLIDE 23

100% Owned Glacier Gas Plant – Positioned for Production Ramp-up Glacier Gas Plant Site near Major Natural Gas & Liquids Pipelines & Rail Access Sales Pipeline Loop capacity of 400 mmcf/d (Glacier plant to NW TCPL Mainline) Total TCPL Natural Gas Firm Transportation Service of 308 mmcf/d by 2019 Secured

GROWTH BEYOND 400 MMCF/D CAN BE ACCOMMODATED ON EXISTING PLANT SITE

TCPL Sales Meter Stations

Advantage Gas Plant Company Land Company Gas Plant TransCanada Pipeline Pembina Pipeline Advantage Pipeline Alliance Pipeline

400 mmcf/d take away capacity to TCPL NW main sales gas pipeline

Pembina NGL Line

Alliance Sales Gas Line

Room for Additional Expansion Beyond 400 mmcf/d To be expanded from 250 mmcf/d to 400 mmcf/d Dry & Liquids gas processing capacity

TCPL NW ALBERTA Main Sales Gas Line

SLIDE 24

Clear Vision for Growth Financial Strength Proven Expertise

SLIDE 25

APPENDIX

SLIDE 26

16% 15% 16% 2017 Budget 2018E 2019E

Annual Average Production Growth

GLACIER GROWTH PLAN DETAILS

16% ANNUAL AVERAGE PRODUCTION GROWTH 2017 THRU 2019

16% average growth per year (“CAGR”)

203 236 272 316 2016 2017 Budget 2018E 2019E

Annual Average Production (mmcfe/d)

SLIDE 27 21 mmcf/d 18 mmcf/d 13 mmcf/d 11 mmcf/d 6 mmcf/d 10 mmcf/d 13 mmcf/d 18 mmcf/d 13 mmcf/d 16 mmcf/d 18 mmcf/d 12 mmcf/d 9 mmcf/d

IMPROVING WELL PERFORMANCE AND LOWER WELL COSTS THROUGH DRILLING & COMPLETION TECHNOLOGY

Lower Montney Middle Montney Upper Montney (1) Initial on production rate based on approximately first ten days of in line test at gas gathering system pressure. Wells are then choked to ≤10 mmcf/d to manage frac sand flow back per AAV operating practices (2) As of August 4, 2016

Recent “TOP Quartile” Wells (1)

Increasing frac count has improved long term production performance in all layers

$5.5 $4.8

2014 2017 UPPER MONTNEY

$6.6 $4.8

2014 2017 MIDDLE MONTNEY

$5.8 $4.8

2014 2017 LOWER MONTNEY

Well Costs Reduced ($ millions)

(18 fracs) (18 fracs) (>25 fracs) (>25 fracs) (18 fracs) (>25 fracs)

NOTE: 2017 cost estimate includes an allowance for inflation

SLIDE 28

CONTINUOUS IMPROVEMENT HAS CREATED INDUSTRY LEADING EFFICIENCIES

SLIDE 29

UPPER AND LOWER MONTNEY WELLS - IMPROVING PERFORMANCE SINCE 2008

Data: updated to February 2017 Budget Type Curve (IP30 7.5 mmcf/d & 7.5 Bcf)

Newer wells restricted for frac sand flow back

SLIDE 30

LIQUIDS RICH MIDDLE MONTNEY WELL PERFORMANCE IMPROVEMENTS SINCE 2011

2015/16 Middle Montney wells with frac design

changes including >20 frac stages and cemented ports to be evaluated

20 total Middle Montney wells on-production across

Glacier land block.

2012-13 4 wells Gen 2: Poly CO2, & Slickwater Plug and Perf Avg 13 frac stages

Note: (1) Production plot affected by low number of producing wells >350 days and wells being choked.

2011-12 2 wells Gen 1: Poly CO2, Sand Plugs, Avg 15 frac stages 2013-14 3 wells Gen 3: Slickwater, OH Packers Avg 15 frac stages 2014-15 10 wells(1) Gen 4: Slickwater, OH Packers Avg 19 frac stages

Middle Montney Budget Type Curve (IP30 5.0 mmcf/d & 5.0 Bcf) Middle Montney IP30 6.0 mmcf/d & 6.0 Bcf Type Curve

2015-16 1 Well Slickwater, OH Packers 26 frac stages

SLIDE 31

EXCEPTIONAL UPPER & LOWER MONTNEY WELL ECONOMICS

(1)

(1) Management estimates. NPV 10% pre-tax. (2) Capital of $4.8 million per well based on management’s estimate of DCE+T capital cost and includes a 4 month drill to on-production timeframe (3) Natural gas and NGL prices and costs escalated at 1.5%. Average C3+ Cdn NGL price of $37/bbl based on $50 U.S./bbl WTI

Upper & Lower Montney Dry Gas (2)

Budget Type Curve. Some recent Upper & Lower Montney wells are outperforming type curve

(3)

SLIDE 32

EXCEPTIONAL EAST GLACIER MIDDLE MONTNEY WELL ECONOMICS

(1)

Middle Montney at 50 bbls/mmcf C3+ (2)

Budget type curve. Some recent MM wells are exceeding type curve.

SLIDE 33

GLACIER MONTNEY ASSIGNED 2P EUR PER WELL & INTERVAL

(1) Based on Sproule year-end reserve reports. Indicated raw gas volumes per well.

Glacier - 2P Recoveries per Interval(1)

Interval

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

YE 2012 YE 2013 YE 2014 YE 2015 YE 2016 YE 2012 YE 2013 YE 2014 YE 2015 YE 2016 YE 2012 YE 2013 YE 2014 YE 2015 YE 2016 YE 2012 YE 2013 YE 2014 YE 2015 YE 2016 YE 2012 YE 2013 YE 2014 YE 2015 YE 2016 YE 2012 YE 2013 YE 2014 YE 2015 YE 2016 1 UM

73 83 99 100 102 174 169 157 148 141 247 252 256 248 243 4.3 4.4 4.5 4.7 4.9 4.7 5.4 5.3 5.5 5.9 4.6 5.1 5.0 5.2 5.4

2 MM

5 6 7 10 12 16 38 42 43 52 21 44 49 53 64 2.7 3.9 4.6 4.7 5.8 4.0 4.2 4.6 4.8 5.2 3.7 4.2 4.6 4.8 5.3

3 MM

1 4 6 7 8 19 20 23 25 1 23 26 30 33 2.5 2.7 3.3 4.6 4.5 0.0 3.1 3.2 4.2 4.1 2.5 3.0 3.2 4.3 4.2

4 MM

1 2 2 1 5 2 2 7 0.0 0.0 2.5 3.7 6.1 0.0 0.0 4.0 0.0 5.9 0.0 0.0 3.3 3.7 6.0

5 LM

15 22 27 34 43 76 72 72 83 84 91 94 99 117 127 2.9 3.8 5.4 5.6 7.1 5.0 5.1 5.9 5.9 6.4 4.7 4.8 5.8 5.8 6.6

Total 94 115 140 153 167 266 298 292 297 307 360 413 432 450 474

SLIDE 34

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

SLIDE 35

2012 CORE AND COMPLETION STUDIES: INCREASED RESOURCE AND IMPROVED WELL RESULTS

(1) Composite log and core from several wells located across the Glacier land block

Completion Study included 135 wells and over 1,400 fracs in the immediate Glacier area covering the EnCana Swan and Murphy Tupper properties Findings revealed that high frac pump rates and open hole packer system resulted in optimal performance

IP30’s on open hole wells improved by 1.6x First year cumulative production improved by 1.7x from 0.7 bcf to 1.2 bcf First year cumulative production improved by 2.4x from 0.7 bcf to 1.7 bcf IP30’s with pump rates > 4m3/minute improved by 1.7x

Core study determined original density porosity logs have to be re- calibrated Re-calibration aligned log to actual core porosities evident through entire 290 meters of Montney formation at Glacier Well tests in all the Montney layers proved gas saturation and productivity

Completion Study Area

SLIDE 36

ADVISORY

Certain statements contained in this presentation constitute forward-looking information, which relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. In particular, this presentation contains forward-looking statements pertaining to, but not limited to, the following: details of Advantage's 2017 to 2019 development program; expected number of wells required to be drilled to achieve certain levels of production; expected well economics associated with certain type curves; expected sensitivities in cash flow per share and debt to cash flow levels to changes in commodity prices; projections of market prices and costs; anticipated number of future drilling locations and inventory and Advantage's focus on developing such locations including the timing thereof; the proposed expansion of Advantage's Glacier gas plant processing capacity, including the amount of such expansion, the anticipated timing of completion of the proposed expansion and the expected benefits to Advantage from such expansion; Advantage's 2017 capital program, including the amount thereof, the amount to be allocated to increase annual production, to drilling and completions, to land and to facilities and infrastructure; Advantage's drilling plans for 2017, 2018 and 2019, including the number of wells to be drilled and the timing of completion of certain wells; estimated three year annual return on capital; Advantage's anticipated capital expenditures, annual production, royalty rates,

perating costs, liquids transportation costs, netbacks, annual cash flow, cash flow per share, funds from operations, total debt to trailing cash flow ratio, total debt to cash flow, cumulative cash surplus, well

costs, bank debt and total corporate cash costs for 2017; Advantage's anticipated capital expenditures, annual production, annual cash flow per share, funds from operations, all-in capital efficiency, netbacks, cumulative cash surplus, bank debt and total debt to trailing cash flow ratio for each of 2018 and 2019; expected increases in production in 2017, 2018 and 2019 resulting from Advantage’s development plan; Advantage's future hedging positions; and other matters. 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, industry and business conditions; impact of significant declines in market prices for oil and natural gas; actions by governmental or regulatory authorities including increasing taxes or royalties and changes in investment, or other regulations; changes in tax laws, environmental 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; unexpected drilling results; changes in commodity prices, currency exchange rates, 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; changes or fluctuations in production levels; delays in anticipated timing of drilling and completion of wells; delays in completion of the expansion of the Glacier gas plant; lack of available capacity on pipelines; individual well productivity; the lack of availability of qualified personnel or management; 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; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; ability to obtain required approvals of regulatory authorities; ability to access sufficient capital from internal and external sources; and certain other risks and uncertainties described in Advantage's Annual Information Form which is available at www.sedar.com and www.advantageog.com. Readers are cautioned that the foregoing lists of factors are not exhaustive. With respect to forward-looking statements contained in this presentation, Advantage has made assumptions regarding, but not limited to: conditions in general economic and financial markets; effects of regulation by governmental agencies; current and future commodity prices, royalty regimes, exchange rates, royalty rates, operating costs, cash costs, well costs and liquids transportation costs; frac stages and lateral lengths per well; estimated EURs; availability of skilled labor and drilling and related equipment; timing and amount of capital expenditures; the impact of increasing competition; that Advantage will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that Advantage's conduct and results of

perations will be consistent with its expectations; that Advantage will have the ability to develop its properties in the manner currently contemplated; available pipeline capacity; that Advantage will be able

to complete the expansion and increase capacity at the Glacier gas plant; that Advantage's production will increase; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated; and that the estimates of Advantage's production and reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects. Production estimates contained herein for the years ended December 31, 2017, 2018 and 2019 are expressed as anticipated average production over the calendar year. In determining anticipated production for the years ended December 31, 2017, 2018 and 2019 Advantage considered historical drilling, completion and production results for prior years and took into account the estimated impact on production of Advantage's 2017, 2018 and 2019 expected drilling and completion activities. Management has included the above summary of assumptions and risks related to forward-looking information in order to provide shareholders with a more complete perspective on Advantage's future

perations and such information may not be appropriate for other purposes. Advantage’s actual decisions, activities, 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. 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 otherwise, other than as required by applicable securities laws.

SLIDE 37

ADVISORY

Advantage discloses several financial measures that do not have any standardized meaning prescribed under International Financial Reporting Standards ("IFRS"). These financial measures include total debt to trailing cash flow ratio, total cash costs, funds from operations and operating netbacks. Total debt to trailing cash flow ratio is calculated as bank indebtedness under Advantage's credit facilities plus working capital deficit divided by funds from operations for the prior twelve month period. Total cash costs includes royalties, operating costs, liquids transportation, cash G&A, interest & other cash expenses. Funds from operations is based on cash provided by operating activities, before expenditures on decommissioning liability and changes in non-cash working capital, reduced for finance expense excluding accretion. Operating netbacks are calculated by deducting royalties and operating costs from revenue on a unit (boe or mcfe) basis. Management believes that these financial measures are useful supplemental information to analyze operating performance and provide an indication of the results generated by Advantage’s principal business activities. Investors should be cautioned that these measures should not be construed as an alternative to net income, cash provided by operating activities or other measures of financial performance as determined in accordance with IFRS. 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. Please see Advantage’s most recent Management’s Discussion and Analysis, which is available at www.sedar.com and www.advantageog.com for additional information about these financial measures, including a reconciliation of funds from operations to cash provided by

perating activities.

This presentation and, in particular the information in respect of Advantage's prospective cash flow debt to trailing cash flow ratio, total cash costs and cash costs per share, operating costs, capital expenditures, annual cash flow and funds from operations may contain future oriented financial information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by management to provide an outlook of Advantage's activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions, including the assumptions discussed above, and assumptions with respect to the costs and expenditures to be incurred by Advantage, capital equipment and operating costs, foreign exchange rates, taxation rates for Advantage, general and administrative expenses and the prices to be paid for Advantage's production. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the FOFI 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. The actual results of operations of Advantage and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. Management believes that the FOFI has 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. FOFI contained in this presentation was made as of the date of this presentation and Advantage disclaims any intention or obligations to update or revise any FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. References in this presentation to initial test production rates, production type curves, initial "productivity", initial "flow" rates, final gas flow rates, average gas flow rates, average type curves, "flush" production rates and "30 day IP rates" 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 for Advantage. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, Advantage cautions that the test results should be considered to be preliminary. Certain type curves presented herein represent estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. The 7.5 mmcf/d IP (which represents the average 30 day initial production rate) and 7.5 Bcfe (which represents the ultimate volumes expected to be recovered from the wells over the life of the well based on the type curve) Upper and Lower Montney type curve and the 5 mmcf/d IP and 5 Bcfe Middle Montney type curve are management generated type curves based on a combination of historical performance of older wells and management's expectation

f what might be achieved from future wells. The type curves represent what management thinks an average well will achieve. Individual wells may be higher or lower but over a larger number of wells

management expects the average to come out to the type curve. Over time type curves can and will change based on achieving more production history on older wells or more recent completion information on newer wells. Other type curves presented herein, including the 9 mmcf/d IP and 9 Bcf Upper and LowerMontney type curve and the 6 mmcf/d IP and 6 Bcf Middle Montney type curve have been provided to demonstrate the economics associated with wells that could potentially have that type of productivity and recovery but do not represent management estimates of how such wells will actually perform. This presentation discloses over 1,100 undeveloped future drilling locations in the following categories: (i) proved (247 locations); (ii) proved + probable (307 locations); and (iii) unbooked (over 793 additional locations). Proved locations and probable locations are derived from Advantage’s most recent independent reserves evaluation as prepared by Sproule Associates Limited as of December 31, 2016 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on Advantage’s 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. Unbooked locations have been identified by

SLIDE 38 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 Advantage will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. This presentation also contains projections of production growth based on drilling and recompletion opportunities identified by management of Advantage. Certain of the drilling opportunities identified have no associated reserves or resources which can presently be classified as recoverable. As such the initial rates of production and reserves per well identified herein do not represent estimates of future production

r reserves associated with the drilling opportunities. The initial rates of production, reserves per well and the capital costs associated with drilling and recompletion identified below are based on Advantage's

historical results and analogous public information received from other producers using similar technologies as Advantage intends to use in the same or similar areas and formations. The initial rates of production, reserves per well and capital costs associated with the wells have been provided herein to give an indication of management's assumptions used for budgeting, planning and forecasting purposes. The initial rates of production, reserves and capital costs will most likely be different than projected. Advantage uses certain abbreviations in this presentation and the appendices hereto, including: (a) "bbls" means barrels; (b) "bbls/d" means barrels per day; (c) "mbbls" means thousand barrels; (d) "boe" means barrels of oil equivalent of natural; (e) "mboe" means thousands of barrels of oil equivalent; (f) "boe/d" means barrels of oil equivalent per day; (g) "mcf" means thousand cubic feet; (h) "mmcf" means million cubic feet; (i) "mmcf/d" means million cubic feet per day; (j) "bcf" means billion cubic feet; (k) "bcfe" means billion cubic feet of natural gas equivalent; (l) "tcf" means trillion cubic feet; (m) "tcfe" means trillion cubic feet of natural gas equivalent; (n) "1P" means proved reserves and "2P" means proved plus probable reserves; and (o) "NGLs" means natural gas liquids. Throughout this presentation the terms boe, mcfe (thousand of cubic feet of gas equivalent), mmcfe, bcfe and tcfe are used. Such terms may be misleading, particularly if used in isolation. The conversion ratio used herein of six thousand cubic feet per barrel (6 mcf: 1 bbl) of natural gas to barrels of oil equivalent and the conversion ratio used herein of 1 barrel per six thousand cubic feet (1 bbl: 6 mcf) of barrels of oil to natural gas equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. This presentation contains certain oil and gas metrics, including EUR, PDP F&D, 2P F&D, 1P F&D, operating netbacks, cash flow netbacks, all-in netbacks, recycle ratio and CAGR which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate Advantage's performance; however, such measures are not reliable indicators of the future performance of Advantage and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. EUR represents the 2P estimated ultimate recoverable conventional natural gas volumes per well assigned by Advantage's internal non-independent qualified reserves evaluator in accordance with the Canadian Oil & Gas Evaluation Handbook. PDP F&D is calculated by adding together all capital expenditures including exploration and development costs and dividing the sum by PDP reserves additions. 2P F&D is calculated by adding together all capital expenditures including exploration and development costs and the change in future development costs and dividing the sum by 2P reserve additions. 1P F&D is calculated by adding together all capital expenditures including exploration and development costs and the change in future development costs and dividing the sum by 1P reserve additions. The aggregate of the exploration and development costs incurred in the most recent financial year generally will not reflect total finding and development costs related to reserve additions for that year. Operating netbacks are calculated by deducting royalties, operating costs and transportation costs from revenue on a unit (mcfe) basis. Cash flow netbacks are calculated by deducting royalties, operating costs, transportation costs, cash G&A and cash finance expenses from revenue on a unit (mcfe) basis. All-in netbacks are calculated by deducting royalties, operating costs, transportation costs, cash G&A, cash finance expenses and PDP F&D from revenue on a unit (mcfe) basis. Recycle ratio is calculated as Cash flow netbacks divided by 2P F&D. CAGR is the Compound Annual Growth Rate representing the measure of average annual growth over multiple time periods. In this presentation certain financial and operating metrics of other issuers are also presented to compare such metrics to Advantage's results. Such other issuers were included to show how Advantage's performance compares to some

f its peers. The financial and operating metrics of such issuers have been obtained from public sources and have not been independently verified by Advantage. Readers should not base an investment decision

for the securities of such issuers based on the information available herein. Advantage disclaims any responsibility or liability for the accuracy of the information relating to such other issuers presented herein. Where any disclosure of reserves data and resources is made in this presentation that does not reflect all reserves of Advantage, the reader should note that the estimates of reserves, future net revenue and resources for individual properties or groups of properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

ADVISORY

SLIDE 39

ADVANTAGE CONTACT INFORMATION

Investor Relations

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

Advantage Oil & Gas Ltd.

Suite 300, 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

Craig Blackwood, C.A.

VP Finance & Chief Financial Officer

Neil Bokenfohr, P.Eng.

Senior Vice President

Advantage 100% W.I. Glacier Gas Plant