Investor Presentation TSX / NYSE: AAV September 2018 ADVANTAGE AT - - PowerPoint PPT Presentation

▶

Oct 22, 2023 22 likes •414 views

Lowering Natural Gas Production & Increasing Liquids -Rich Development with 15 Liquids-Rich Wells to Commence Drilling in H2 2018. Liquids Production Could Reach 13% or More of Total Production in 2020 Investor Presentation TSX /

SLIDE 1

“Lowering Natural Gas Production & Increasing Liquids-Rich Development with 15 Liquids-Rich Wells to Commence Drilling in H2 2018. Liquids Production Could Reach 13% or More of Total Production in 2020”

TSX / NYSE: AAV Investor Presentation September 2018

SLIDE 2

ADVANTAGE AT A GLANCE

2 TSX 52-week trading range $3.46 - $8.64 Shares Outstanding (basic) 186 million Market Capitalization $0.7 billion 2018 Guidance 240 to 255 mmcfe/d Liquids Production (50% Increase over 2017) 1,800 bbls/d Exit Liquids Production 2,400 bbls/d Corporate Cash Costs $1.10 to $1.30/mcfe Estimated Dec. 31, 2018: Bank Debt (58% drawn on $400 million Credit Facility) $233 million Total Debt (including working capital deficit) $240 million Total Debt/Trailing 12 Month Cash Flow 1.4 - 1.7x (@ AECO $1.50/mcf to $1.75/mcf + WTI $60U.S./bbl)

SLIDE 3

TCFs of Natural Gas Millions of Barrels of Liquids including C5+/Oil wellhead liquids production >200 bbls/mmcf Plans underway to Increase Liquids, Moderate gas Operating flexibility to readily modify capital allocation Lowest Montney total corporate cash costs Access/Market Diversification in place Strong Balance Sheet Execution Track Record

A STRONG FOUNDATION UNDERPINNED BY SIGNIFICANT NATURAL GAS & LIQUIDS-RICH MONTNEY RESOURCES

SLIDE 4

RECENT LIQUIDS DRILLING SUCCESSES ENHANCES UPSIDE POTENTIAL ON ~200 NET MONTNEY SECTIONS (128,000 NET ACRES)

Glacier (94 net sections) Wembley/ Pipestone Valhalla 100% owned Glacier Gas Plant Progress (40 net sections) (42 net sections) (31 net sections)

Alberta B.C. 4

Only 4% of our liquids-

rich lands have been drilled

Total 110 net sections

at Valhalla, Wembley & Progress acquired for a total of $19 million since 2013

Up to 5 layers of dry and

liquids-rich gas

Future drilling inventory

>1,200 locations and growing

4 well pad success 6,410 boe/d (32 mmcf/d gas + 1,075 bbls/d liquids with certain yields up to 100 bbls/mmcf, 90% C5+/oil)

6 miles

First Montney well 624 boe/d with 172 bbls/d liquids including 75 bbls/d wellhead C5+/oil First Montney well 1,312 boe/d with 819 bbls/d liquids including 624 bbls/d wellhead C5+/Oil

East Glacier Middle Montney 50-80 bbls/mmcf C3+

SLIDE 5

255 – 265 240 - 255

2018 Original Guidance 2018 Updated Guidance (2)

Annual Average Production (mmcfe/d)

2018 PLAN UPDATED TO INCREASE FUTURE LIQUIDS PRODUCTION(1)

LOWERING NATURAL GAS, INCREASING LIQUIDS

Reallocating budgeted capital to drill more liquids-rich wells at Valhalla & East Glacier in 2018 (maintain $175

million capital program)

Liquids growth from Valhalla & East Glacier 2018 & 2019, Wembley liquids begin mid-2020
Deferring current standing dry gas well completions to 2019
Lowering natural gas production during low AECO price periods and increased hedges summer 2018/19
Maintaining flexibility to increase gas production winter of 2018 & beyond should prices strengthen

5 4.4% 5% - 6% 6% - 8% 10% - 15%

2018 Guidance Update (2)(3) 2018 Exit 2019 2020

Liquids As % of Total Production

Primarily Valhalla & Glacier liquids growth Wembley mid-2020

(1) Management estimates (2) News Release dated April 19, 2018 (3) Midpoint of 2018 Guidance Range

Notes:

~5%

SLIDE 6

Blended Liquids Price (C3+) $55/bbl Royalties $(2.75) Operating Cost $(2.25) Transportation $(5.00) Liquids Operating Netback $45/bbl

Estimated Liquids Operating Netback 2020

(excluding hedging)

INCREASING LIQUIDS STRENGTHENS REVENUE & NETBACKS(1)(2) (SENSITIVITIES + IMPACTS)

6 4.4% 5% - 6% 6% - 8% 10% - 15%

2018 Guidance 2018 Exit 2019 2020

Liquids As % of Total Production

20% 21% - 24% 30% - 38%

2018 2019 2020

Annual Liquids Revenue % of Total Revenue (Excluding Hedging)

1% Liquids ≈ 3% - 5% of Total Revenue Impact

(1) 2018 average AECO price of $1.67/mcf based on strip as of June 29, 2018 then $2/mcf AECO, $2.55 US/mcf Dawn and WTI $60US/bbl for 2019 and 2020 at Fx$0.79 (2) Management estimate. Liquids price based on blended C3+ volumes in 2020.

$45 $58 - $65 $100 - $125

2018 2019 2020

Annual Liquids Revenue ($ Millions) $/bbl

SLIDE 7

Other $10 Plant & Value Add Facilities $85 Well Operations $80

2018 Cash Flow 2018 Capital Estimate

(1) Midpoint of 2018 Guidance Range. (2) Based on an average AECO Cdn $1.50/mcf to $1.75/mcf ($1.42/GJ to $1.66/GJ) and average Dawn US $2.80/mmbtu natural gas price and Advantage’s current hedge positions

$155-$165 ($ million)

2018 UPDATED PLAN SUMMARY

$175

2018 SUMMARY (1) (2)

$155 to $165 Million Cash Flow
≈1.5x Year-end 2018 Total Debt/Cash Flow
240 to 255 mmcfe/d Annual Production Range
50% Annual Liquids Production Growth to 1,800

bbls/d exiting the year at 2,400 bbls/d (>70% C5+)

$30 Million to Advance Liquids Development at

Valhalla, Wembley and Progress

Drill 15 additional Valhalla & east Glacier liquids-rich

wells through Q1 2019

Completed Glacier Gas Plant Expansion to 400

mmcf/d & 6,800 bbls/d of liquids extraction Q2 2018

$1.10-$1.30/mcfe Total Cash Costs
$13,300/boe/d All-In Capital Efficiency

7 $130 $45

Glacier Valhalla, Wembley, Progress

SLIDE 8

24% 24% 25%

28% 22% 26% 23% 21% 4% 5% 1% 8% 12% 17% 23% 37%

2018E 2019E 2020E

Liquids Midwest U.S. Henry Hub Dawn Fixed Price AECO

Notes: (1) Graph represents % of estimated revenue based on strip pricing at May 10, 2018. (2) Includes Dawn hedges of 30,000 mmbtu/d at an average price of US $2.86/mmbtu for 2018 and 6,250 mmbtu/d at an average price of US $3.13/mmbtufor 2019 (3) Includes AECO hedges of 81,680 mmcf/d at avg price of AECO Cdn $2.59/mcf 2018 and 75,155 mmcf/d at avg price of $2.26/mcf 2019

MARKET & REVENUE DIVERSIFICATION ENHANCES NETBACKS (<25% REVENUE EXPOSURE TO AECO PRICES THRU 2020)

Glacier Netbacks ($/mcfe) 2018 Estimates at AECO Cdn $1.75/mcf Revenue (1) $2.62 Hedging $0.34 Royalties ($0.10) Operating Costs ($0.31) Transportation Costs(2) ($0.58) Operating Netback $1.97 G&A ($0.09) Finance & other ($0.12) Cash Flow Netback $/mcfe $/Boe $1.77 $10.62 Recycle Ratio based on 3 Year Average 2P F&D @ $0.52/mcfe (3) 3.4x

Notes: (1) Includes Dawn and Chicago natural gas revenue, adjustments for heat value (realized price) and natural gas liquids revenue. (2) Includes liquids transportation costs of $0.04/mcfe, AECO gas transportation costs of $0.29/mcfe and AECO to Dawn transportation costs of $1.10/mcfe. (3) 2P F&D includes Future Development Capital and is based on Sproule’s 2015, 2016 and 2017 year-end 2P reserves reports. (2)

Revenue Diversification(1)

(3)

Added 62 mmcf/d AECO settled puts @$1.42/mcf June to Sept 2018 & 62 mmcf/d fixed price swaps @ $1.77/mcf Apr to Oct 2019

SLIDE 9

NATURAL GAS TRANSPORTATION SERVICE IN PLACE ACCESSING SEVERAL HUBS

100 200 300 400 500

2018 2019 2020 2021 Firm Contracted Service Evergreen Contract Renewals

AECO Transportation Service

393 mmcf/d as of April, 2021

Alliance Pipeline Connection Q4 2018

Glacier gas plant

Proceeding with Alliance meter station connection for 2018

Alliance TCPL

TCPL Meter Station Alliance Meter Station

Increasing firm service secured to 2021
Ability to reduce future total service

commitments through evergreen contract renewals

Physical Downstream Transport Capacity

25 50 75 100 125

2018 2019 2020 2021 Dawn Chicago Ventura Ability to further diversify downstream markets and capture revenue optimization opportunities

(mmcf/d) (mmcf/d)

SLIDE 10

$115 Million

280 mmcfe/d Q4 2018 AECO $1.20/Mcf

$100 Million

Cash Flow at AECO $2.50/Mcf

$215 Million

MAINTENANCE CAPITAL AND SURPLUS CASH FLOW SENSITIVITY ILLUSTRATIVE AT 280 MMCFE/D (Q4 2018)

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 Dawn at $3.30/mcf and a WTI price of $55 US/bbl.

Annual Surplus Cash

f $100 million

(NO HEDGING INCLUDED)

$115 Million

(2)

CASH FLOW MAINTENANCE CAPITAL CASH FLOW

Capable of Maintaining Production at AECO $1.20/mcf

SLIDE 11

ONGOING VALUE CREATION FROM OUR HIGH QUALITY ASSETS THROUGH OPERATIONAL EXCELLENCE

SLIDE 12

EXTENSIVE LIQUIDS-RICH MONTNEY RESOURCE

Source: Canadian Discovery Digest/Advantage

Progress

50-100 bbls/mmcf

Wembley

>250 bbls/mmcf

Valhalla

20 to >100 bbls/mmcf

E Glacier

50-80 bbls/mmcf C3+

Source: Canadian Discovery Digest/Advantage

Increasing Total C3+ and C5+/Oil liquids content from East Glacier to Wembley Only 4% of liquids-rich lands have been drilled Multi-layer Montney development potential

Recent Advantage Evaluation/Delineation wells

Wells drilled within last 18 months

SLIDE 13

13 Progress Glacier Valhalla Wembley Pipestone

First AAV Progress well (LM) 63 bbls/mmcf AAV Valhalla 20-100 bbls/mmcf First AAV Wembley 12-25 277 bbls/mmcf East Glacier 50-80 bbls/mmcf

6 miles

NOTE: Liquid yields indicated are propane plus (“C3+”) based on a Glacier shallow cut liquids extraction process

Glacier gas well rates up to 20 mmcf/d

SIGNIFICANT NATURAL GAS AND LIQUIDS UPSIDE ACROSS LAND HOLDINGS

~200 net sections (128,000

net acres)

110 net sections Progress,

Valhalla, Wembley

Only 169 dry gas Upper &

Lower Glacier wells drilled to date (7 standing wells)

Only 48 liquids-rich wells

drilled to date (13 standing wells)

>1,200 future locations

(Glacier & Valhalla only)

100% Ownership of Glacier

gas plant with 400 mmcf/d, 6,800 bbls/d C3+ liquids provides capacity for development of AAV’s land blocks

Glacier gas plant

SLIDE 14

WEMBLEY/PIPESTONE – ULTRA RICH LIQUIDS PRODUCTION

~625 bopd IP30 - Oil

Average Initial Production (boe/d) Average over 1-Year Production (boe/d) TOTAL EUR (boe)

Oil 581 303 361,000 Gas 409 260 384,000 NGL 160 101 150,000 Total 1,150 664 895,000 Liquid Yield Bbls/mmcf 300 260 225

Oil Production Rate (bbls/d)

Volatile oil – sample area production

Pipestone

Kelt ECA CNRL Blackbird Cenovus/NuVista Pipestone HUSKY

Recent offset wells confirm Ultra- rich C5+/oil potential on all sides

f our Wembley land block

AAV 12-25 Mid Montney 1,312 boe/d 624 bbls/d free C5+/Oil, 819 bbls/d C3+

SLIDE 15

Upper Montney Middle Montney Lower Montney Taqa

Gaswells

CNRL Gaswells

Kelt Oilwells

AAV 13-31 First Well Tourmaline

Oilwells

T77 T76 T78 R8 R10 R9

CNRL

On 2015/01 Cum Oil: 125,700 bbls to 2017/12 (36 months)

On 2016/08 Cum Oil: 101,000 bbls to 2017/12 (17 months)

On 2016/09 Cum Oil: 13,300 bbls to 2017/12 (16 months)

AAV 5-22 Uncompleted

Advantage’s First Delineation Well 13-31-77-9W6

Lateral Length 2,313 meters
44 frac stages
624 boe/d average rate (2.7

mmcf/d gas)

75 bbls/d free condensate/oil (45

deg API)

172 bbls/d C3+ liquids (shallow

cut)

Wellhead (free) C5+ 28 bbls/mmcf
C3+ 63 bbls/mmcf
Only 13% load fluid recovered
Production increasing over test

period 40% reservoir draw down during flow up production casing

Limited testing time due to lack of

area process capacity

PROGRESS FIRST DELINEATION WELL – C3+ LIQUIDS YIELD OF 63 BBLS/MMCF

Middle Montney

SLIDE 16

ADVANTAGE INFRASTRUCTURE PLANS WILL ACCESS PIPESTONE AREA

16 Glacier

Wembley/ Pipestone

Valhalla

100% owned Glacier Gas Plant, 400 mmcf/d & 6,800 bbls/d liquids

Progress Alberta B.C.

Advantage Valhalla Compressor and Liquids Handling Facility (Q4 2018) AAV 100% owned existing gathering pipeline

Pembina LaGlace Liquids Terminal Pembina Pipeline Cenovus Wembley Plant

Secured up to 10 mmcf/d of firm 3rd party processing capacity in Wembley/Pipestone area beginning H2 2019. AAV’s Wembley to Glacier planned pipeline routing work

continuing. Several new gas plants

proposed in Pipestone area.

Keyera Pipestone Plant (2021) Tidew ater Pipestone Plant (2019)

Future Advantage Wembley Compressor and Liquids Handling Facility

CSV Albright Plant (2020) Keyera Pipestone / Wapititi Compressor (2019) SemCAMS Pipestone Plant (2020)

SLIDE 17

SIGNIFICANT AND GROWING LIQUIDS & DRY GAS DRILLING INVENTORY

(1) Management Estimates (2) Based on Sproule December 31, 2017 Reserves Report (3) As of December 31, 2017, gross Hz wells (includes producing and standing developed wells) *Interval 6 not assigned reserves or resource

Liquids-Rich intervals Ranges from C3+ yields of 20 to >250 bbls/mmcf (45% to 90% C5+)

Multi-Layer Montney Development Potential across Advantage Land Blocks

Upper 115 Lower 51 Middle 31

>900

Glacier & Valhalla Undrilled

337

2P Reserves Undeveloped Locations Booked(2)

>1,200 Future Drilling Locations(1)

Proved Developed Wells by Layer(3) TOTAL 197

# of locations are expected to grow as delineation drilling continues at Valhalla, Wembley & Progress

SLIDE 18

RECENT GLACIER MIDDLE MONTNEY WELLS OUTPERFORMING

Lower Montney Middle Montney

16-8 8 Well Pad

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

Production from 6 Middle Montney wells on 16-8 well pad

Evaluating Higher # of Frac Stages – knowledge to be applied to upcoming liquids-rich wells

Average 34 stages
76% increase in frac density over previous MM wells
75% higher average production after 120 days

compared to MM well type curve

SLIDE 19 Budget Type Curve (IP30 7.5 mmcf/d & 7.5 Bcf)

Evaluating Longer Laterals and More Frac Stages (up to 2880 meters and 28 frac stages)

5-16 8 Well Pad

Lower Montney Middle Montney Upper Montney

PROLIFIC DRY GAS RESULTS CONTINUES TO REDUCE WELL ECONOMIC THRESHOLDS AT GLACIER – 8 WELL PILOT PAD ON-PROD 2016

Evaluating Shorter Laterals Spacing & Recovery (1,656 meters)

Budget Type Curve (IP30 7.5 mmcf/d & 7.5 Bcf)

Wells significantly exceeding type curve after 500+ days production

Production updated to August, 2018

1.3 year payout at Cdn $2.00/mcf gas price Top Tier LM wells

SLIDE 20

ATTRACTIVE WELL ECONOMICS ACROSS ADVANTAGE LAND HOLDINGS

1) Management estimates. 2) Capital of $4.8 million per well for Glacier and Valhalla and $6.5 million per well for Wembley 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%, based on $60 U.S./bbl WTI 4) Breakeven based on NPV10 pre-tax equal to zero at a WTI U.S. $60/bbl and calculated AECO Cdn price

Half-cycle Economics(1)(2)(3)

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

ROR% Payout Years Breakeven(4)

(AECO Cdn $)

Glacier Dry (Upper & Lower Montney) 33% - 67% 1.7 - 2.8 $1.25/mcf East Glacier/Valhalla Liquids-Rich 40% - 90% 1.4 – 2.2 <$1.00/mcf Wembley 160% - 200% 0.8 – 1.0 <$1.00/mcf Progress In early delineation stage, initial well results encouraging

SLIDE 21

LIQUIDS-RICH EAST GLACIER MIDDLE MONTNEY WELL ECONOMIC SENSITIVITY

(1)

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

(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 U.S.$60/bblWTI. C3+ NGL yields of 50 bbls/mmcf raw gas (3)

Break-even below $1.00 Cdn gas price at U.S. $60/bbl WTI

SLIDE 22

DRY GAS – GLACIER UPPER & LOWER MONTNEY WELL ECONOMIC SENSITIVITY(1)

Upper & Lower Montney Dry Gas (2)

Break-even approximately $1.25/mcf Cdn with top tier Glacier dry gas wells

(3)

SLIDE 23

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

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 393 mmcf/d by 2021 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 TCPL NW ALBERTA Main Sales Gas Line New Alliance Meter Station to be Installed 2018

SLIDE 24

Clear Vision for Growth Financial Strength Proven Expertise

SLIDE 25

APPENDIX

SLIDE 26

2018 GUIDANCE UPDATED (APRIL 2018)

Average Annual Production 240 to 255 mmcfe/d (40,000 to 42,500 boe/d) Liquids Annual 1,800 bbls/d Liquids Exit 2,400 bbls/d Royalty Rate 3% to 5% Operating Costs ($/mcfe) $0.28 to $0.33 Transportation Costs ($/mcfe) $0.55 to $0.62 Total Corporate Cash Costs ($/mcfe) $1.10 to $1.30 Capital Expenditures $175 million

SLIDE 27

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 28

NGTL OPERATIONS DEMONSTRATE SMALL WCSB SUPPLY/DEMAND IMBALANCE (~0.5 BCF/D)

Recent changes to NGTL’s methodology for balancing their system by cutting delivery service rather than

receipt service makes storage inaccessible and causes extreme price volatility

Old Methodology:

Cut Receipts – restrict gas
nto the system
Result: Price declines, but

floor established as more gas moves into storage

New Methodology:

Cut Deliveries –restrictions to

getting gas off the system or into storage

Result: Storage no longer a

safety net for prices

Maintenance schedules resulting in EGAT restrictions drives down prices until producers shut-in production Prices consistently recover as soon as EGAT restrictions are lifted “Production changes of ~0.5 Bcf/d create large price swings”

SLIDE 29

ADVANTAGE - LEADING LOW COST NATURAL GAS SUPPLY

(1) Advantage 2018 estimates at April 26, 2018. (2) RBC Capital Markets 2018 average cost estimate including ARX, BIR, CR, KEL, NVA, PPY, POU, TOU and VII at April 12, 2018. (3) Tudor, Pickering, Holt & Co. 2018 average cost estimate including AR, CNX, COG, EQT, RICE and RRC at April 26, 2018 using a USD$/CAD$ foreign exchange rate of $0.78.

AAV Montney Marcellus

Select Montney and Marcellus Natural Gas Producers Cash Costs 2018 Estimates (Cdn$/mcfe)

Operating costs & transportation ($/mcfe) Royalties incl. GCA adjustments ($/mcfe) G&A ($/mcfe) Interest & other ($/mcfe)

$1.18 $2.39 $2.82

(3) (1) (2)

SLIDE 30

RETURN ON AVERAGE CAPITAL EMPLOYED COMPARISON 5-YEAR AVERAGE (2013 TO 2017 ESTIMATE)

Notes: 1. Advantage return on average capital employed (ROACE) is calculated by Management for the development of Glacier, Valhalla, Pr ogress and Wembley since inception (legacy property disposition impacts have been excluded). 2. Comparative data is based on Macquarie Research September 11, 2017 and Peers Average includes ARX, BIR, BNP, CR, KEL, NVA, PEY, POU and VII. 3. ROACE as defined by Macquarie Research includes revenue and realized hedging gains/losses less royalty expense, operating expense, transportation expense, G&A expense, depreciation expense and income taxes (excludes unrealized hedging gains/losses and financing expense a fter taxes) divided by average capital employed.

Before tax 7.9% 3.9% 3.9% 3.5% 0.8% 5.2% 1.4% After tax 5.6%

US Small/Mid Caps Average US Large Caps Average Cdn Yields Average Cdn Small/Mid Caps Average Cdn Large Caps Average Peers Average Advantage Montney Development

Comparative data is shown

n an after-tax basis.

Advantage was not taxable in the last 5 years and is not expected to be taxable for the next 5 years or more due to its significant tax pools.

SLIDE 31

INDUSTRY LEADING LOW COSTS GENERATES STRONG NETBACK MARGINS AMONGST DRY OR LIQUIDS-RICH GAS PRODUCERS

ARX KEL NVA CR TOU BIR AAV PEY $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00

$/mcfe

2017 Total Cash Costs Including PDP FD&A

2017 PDP FD&A 2017E Cash Costs (Excludes Hedging Gains) 48% 44% 51% 45% 58% 52% 66% 73%

ARX KEL NVA CR TOU BIR AAV PEY

2017 Netbacks Percentage of Revenue

Source: TD Securities data based on company’s 2017 actuals reported as of March 1, 2018.

SLIDE 32

CONTINUOUS IMPROVEMENT HAS CREATED INDUSTRY LEADING EFFICIENCIES

Production restrictions

SLIDE 33

LIQUIDS-RICH GLACIER MIDDLE MONTNEY WELL PERFORMANCE IMPROVEMENTS SINCE 2011

2015+ Middle Montney wells with frac design changes

including >20 frac stages & numerous mechanical systems to be evaluated

34 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

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

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) 33

2018 6 wells Gen 6: Slickwater, OH Packers, Stage completions Avg 34 frac stages 2016-17 6 Wells Gen 5: Slickwater, OH Packers, Cased hole & Stage completions Avg 27 frac stages

SLIDE 34

DRY GAS GLACIER UPPER AND LOWER MONTNEY WELLS - IMPROVING PERFORMANCE SINCE 2008

Data: updated to December, 2017

Budget Type Curve (IP30 7.5 mmcf/d & 7.5 Bcf)

Production restrictions

SLIDE 35

GLACIER MONTNEY ASSIGNED 2P EUR PER WELL & INTERVAL

(1) Based on Sproule 2017 year-end reserve reports. Indicated raw gas volumes per well.

35 Glacier - 2P Recoveries per Interval(1)

Interval

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

Developed Undeveloped Total Developed Undeveloped Total YE 2015 YE 2016 YE 2017 YE 2015 YE 2016 YE 2017 YE 2015 YE 2016 YE 2017 YE 2015 YE 2016 YE 2017 YE 2015 YE 2016 YE 2017 YE 2015 YE 2016 YE 2017 1 UM 100 103 111 148 141 133 248 244 244 4.7 4.9 5.1 5.5 5.9 5.8 5.2 5.4 5.5 2 MM 10 12 15 43 52 65 53 64 80 4.7 5.8 5.6 4.8 5.2 5.6 4.8 5.3 5.6 3 MM 7 8 10 23 25 35 30 33 45 4.6 4.5 4.4 4.2 4.1 4.4 4.3 4.2 4.4 4 MM 2 2 3 5 11 2 7 14 3.7 6.1 7.4 0.0 5.9 6.6 3.7 6.0 6.7 5 LM 34 43 51 83 84 81 117 127 132 5.6 7.1 7.7 5.9 6.4 6.5 5.8 6.6 6.9 Total 153 168 190 297 307 325 450 475 515 Interval

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

YE 2015 YE 2016 YE 2017 YE 2015 YE 2016 YE 2017 YE 2015 YE 2016 YE 2017 YE 2015 YE 2016 YE 2017 YE 2015 YE 2016 YE 2017 YE 2015 YE 2016 YE 2017 1 UM

2 4 5 2 9 2.9 6.6 7.9 2.9 7.3

2 MM

1 2 5 1 7 4.4 4.3 4.1 4.4 4.2

3 MM

1 2 3 2.1 2.1 2.1

Total

3 7 12 3 19

Valhalla - 2P Recoveries per Interval(1)

SLIDE 36 Certain statements contained in this presentation constitute forward-looking information, which relate to future events or our future performance. All statements other than statementsof 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 2018 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 and 2018; 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 hedgingpositions; andother matters. These statements involve substantial known and unknown risksand uncertainties, certain ofwhich 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 ofdrilling and completion ofwells; delays in completion ofthe expansion ofthe Glacier gas plant; lack ofavailable 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 andwww.advantageog.com. Readers are cautioned that the foregoinglists offactors are notexhaustive. 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 resultsfor prior years and took into account the estimated impact onproductionofAdvantage's 2017,2018 and2019 expected drillingand 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 ifany 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-lookingstatements, whether as a result ofnew information, future events or results or otherwise, other thanas required by applicable securities laws. .

ADVISORY

SLIDE 37 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'scredit 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 analyzeoperating performance and providean indication ofthe 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 ofthe 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 ofthe 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 inrespect of all wells. Accordingly, Advantage cautions that the test results shouldbe 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 ofolder 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 curvescan 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 couldpotentiallyhave thattype ofproductivity and recovery but do notrepresent managementestimates ofhow such wells willactually perform. This presentation discloses over 1,100 undeveloped future drilling locations at Glacier 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 management as an estimation ofour multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Advantage

ADVISORY

SLIDE 38 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 ofthe 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 willresult in additionaloiland gas reserves, resources or production. This presentation also containsprojections of production growth based on drilling and recompletion opportunities identified by management ofAdvantage. Certain ofthe drilling opportunities identified have no associated reserves or resources which can presently be classified as recoverable. As such the initial ratesof production and reserves per well identified herein do not represent estimates of future production

r reserves associated with the drilling opportunities. The initial rates ofproduction, 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 ofproduction, reserves and capital costswillmost likely be different thanprojected. Throughout this presentation the terms boe, mcfe (thousand ofcubic feet of gas equivalent), mmcfe, bcfe and tcfe are used. Such terms may be misleading, particularly ifused in isolation. The conversion ratio used herein ofsix thousand cubic feet per barrel (6 mcf: 1 bbl) ofnatural gas to barrels of oil equivalent and the conversion ratio used herein of1 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 ofcrude oil as compared to naturalgas is significantlydifferent from the energy equivalency of6:1, utilizinga conversion on a 6:1basis may be misleading as an indication ofvalue. 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, recycleratio 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 ofthe 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 costsfrom 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 ofother issuers are also presented to compare such metrics to Advantage'sresults. Such other issuers were included to show how Advantage's performance compares to some

f its peers. The financial and operating metrics ofsuch issuers have been obtained from public sourcesand have not been independently verified by Advantage. Readersshould not base an investment decision

for the securities ofsuch issuers based on the informationavailable herein. Advantage disclaims any responsibility or liability for the accuracy ofthe information relating to suchother 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 ofproperties may not reflectthe same confidence level as estimates ofreserves and future net revenue for all properties, due to the effects ofaggregation.

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

David Sterna

Vice President Marketing and Commercial

Advantage 100% W.I. Glacier Gas Plant