advantage oil and gas - april 2014

Investor Presentation January 2013Investor Presentation April 2014

“2013 Results, Achievement of our 135 mmcfe/d Phase VI target ahead of schedule and Acceleration of our Phase VII Glacier drilling program sets a solid foundation for multi‐year growth”

Advantage – at a glance

Pure Play Montney Producer Focused on Per Share Growth

Listed on TSX and NYSE AAV

TSX 52 week trading range ($ Cdn) $3.06 - $5.62

Shares Outstanding (basic) 169.1 million

Enterprise Value(1) C$1.1billion

Current Glacier Production 135 mmcfe/d (22,500 boe/d)

Bank Debt at December 31, 2013(2) C$64 million 79% available on $300 million Credit Facility

Total Debt at December 31, 2013(2)(3) C$199 million

Significant Hedging program in place (44% of forecast production hedged at average $3.84/mcf to Q1 2016)

(1) Enterprise value based on market cap as of April 1, 2014 and total pro forma debt as of December 31, 2013. (2) Estimated bank debt and total debt pro forma the net proceeds from the Longview share sale that closed February 28, 2014. (3) Total debt includes bank debt, AAV convertible debentures and working capital.

Recent Achievements

Strong Glacier 2013 Reserve Replacement Efficiencies (1)

Replaced 840% of Glacier 2013 production 2P F&D cost : 2013 @ $1.33/mcfe ($7.99/boe) & 3 year @ $1.06/mcfe ($6.36/boe) 2P Recycle ratio: 2013 @ 2.1x & 3 year @ 2.7x 2P (proven & probable) reserves increased 20% to 1.7 Tcfe

Closed sale of Longview shares for C$94.1 million gross proceeds (February 28, 2014) to strengthen balance sheet in support of three year development program

Created a highly efficient, focused Montney growth company 25 AAV employees (including Executive, Calgary & Field)

Achieved 135 mmcfe/d Phase VI production target one month ahead of schedule with capital spending $13 million below Budget Capital redirected to purchase new Montney lands and acceleration of Phase VII drilling

Glacier Phase VII drilling program accelerated Four new Phase VII wells rig released during Q1 2014. Drilling will continue through spring

break-up on new six-well pad

(1) Based on Sproule’s 2013 Glacier Reserve Report – Gross (before royalties) Working Interest reserves unless otherwise stated. Finding & Development (“F&D”) costs include change in future development capital (“FDC”) . Recycle ratio based on Glacier’s Q4 2013 operating netback of $2.83/mcfe.

What Differentiates Advantage From Other Gas Producers?What Differentiates Advantage From Other Gas Producers?

Industry leading low cost Montney producer with strong cash margins and well economics

Over six years of proven Montney operational experience in growing production/reserves and achieving improvements in cost efficiency and well performance Grew Glacier production to 135 mmcfe/d ahead of Phase VI schedule and grew Proven + Probable (“2P”)

reserves to 1.70 Tcfe(1) since 2008 with a three year F&D cost of $1.06/mcfe(2) & recycle ratio of 2.7x(2)

A well defined three year Glacier development plan that delivers 190% cash flow per share growth and 100% production per share growth by 2017 within existing financial facilities

World Class Montney Glacier asset sufficiently delineated to support natural gas and natural gas liquids development:

16 Tcf TPIIP (3), 1.7 Tcfe 2P reserves(1), 4.2 Tcfe best estimate contingent resource (3) contained in 77 net sections (49,280 acres) of contiguous Montney lands at Glacier

119 wells drilled and completed providing delineation of the Upper, Lower and liquids rich Middle Montney formations across Glacier land block

Approximately 1,400 future drilling locations in five 50 meter individual Montney development layers 100% owned facilities and infrastructure

An additional 43.25 net sections (27,680 net acres) of new Montney acreage that will be evaluated for prospective natural gas & liquids potential Three contiguous land blocks that complement and extends the Montney potential SE of Glacier

(1) Based on Sproule’s 2P Reserve Reports as of December 31, 2013. (2) Based on the 3 year F&D cost of $1.06/mcfe including change in FDC, Q4 2013 Glacier operating netback of $2.83/mcfe and Sproule’s 2013, 2012 & 2011

reserve reports.(3) Based on Sproule’s March 31, 2013 Glacier Resource Assessment (see Appendix).

Advantage – Pure Play Montney ProducerAdvantage – Pure Play Montney Producer

Glacier77 net

sections

Wembley

Valhalla

Recently acquired 43.25 net sections

of Montney Acreage

Located in the heart of the Montneysiltstone fairway (~290 meter average formation thickness at Glacier)

Natural gas & liquids development in progress

16 TCF (1) TPIIP at Glacier represents 64% of total AAV Montney acreage

Approximately 1,400 future drill locations at Glacier alone

100% owned Glacier Gas Plant

(1) Based on Sproule’s March 31, 2013 Glacier Resource Assessment.

Industry Leading Cost Structure Creates Strong MarginsIndustry Leading Cost Structure Creates Strong Margins

Advantage’s full cycle margin between realized price and cash costs is among the top Montney

producers. 2015 liquids production will further increase the realized price and margin.

Glacier 2013 Reserves – 840% Production Replacement, 2.1x Recycle RatioGlacier 2013 Reserves – 840% Production Replacement, 2.1x Recycle Ratio

0.00

0.50

1.00

1.50

2.00

2008YE 2009YE 2010YE 2011YE 2012YE 2013YE

2P F

&D

Cos

t ($/

Mcf

e)

2P F&D 3 year rolling average 2P F&D

580% 2P Reserves growth since 2008

3 Year F&D $1.06/mcfe & 3 Year Recycle Ratio

2.7x

43% Reduction in 3 Year 2P F&D cost

At Year-end 2013: • Replaced 840% of 2013 Glacier production at a

$1.33/mcfe 2P F&D cost• 2P Reserves grew 20% and NGL’s grew 393%

(1.62 Tcfe natural gas and 13.0 million bbls NGL’s) (1)

• Proven reserves grew 17% to 1.03 Tcfe (1)

• PDP reserves grew 18% to 0.21 Tcfe (1)

• 2P Recycle Ratio: 1 year = 2.1x; 3 year = 2.7x• Only 12 of our 22 Phase VI wells had well test

data available for Sproule’s reserves analysis as of December 31, 2013

2P Finding & Development Costs including change in FDC • Improved cost efficiencies and well

performance have reduced F&D costs

• Technical revisions accounted for 25% of 2P reserve additions in 2013

• 55 new, undeveloped locations were booked by Sproule in the Upper, Middle and Lower Montney at YE 2013

• Additional production history from recent wells and future well test results are anticipated to maintain strong reserve replacement efficiencies at Glacier

(1) As compared to Sproule’s 2012 Glacier reserve report.

Proven Operating Cost and Production Performance at GlacierProven Operating Cost and Production Performance at Glacier

Advantage grew Glacier production from 0 to 100 mmcfe/d during the

first three years of development and reduced operating costs to current level of $0.28/mcfe. Production was

held at ~100 mmcfe/d during low gas prices in 2012.

135 mmcfe/d Phase VI production target

achieved one month ahead of schedule

• ~1,400 remaining drilling locations• Five 50 meter intervals are available for

development based on four wells per section per layer

• Delineation has proven commercial rates both vertically and laterally across Glacier in the Upper, Middle and Lower Montney

• Three of the five intervals are located in the liquids rich Middle Montney formation

Wells are vertically & laterally offset in each

layer for optimal recovery

Glacier – Five Interval Development (“Pentastack”) Provides Significant Drilling Inventory

Over 1,305 Locations Remain Undrilled Beyond 2017 - Post Development Plan

Remaining Inventory of Locations(1)

# Wells Required in 3Year Development Plan (2)

RemainingUndrilled Locations post 2017

# of Undeveloped Locations Booked in Sproule Dec 31, 2013 Report

Upper Montney 230 39 191 169

Middle Montney 882 39 843 57

Lower Montney 304 33 271 72

Total 1416 111 1305 298

(1) Excludes 117 Developed wells booked in the Sproule Dec. 31, 2013 Reserve Report(2) Includes 12 Phase VI wells drilled in Q1 2014

3 Year Development Plan Financial

Strategy

Strengthened Balance Sheet$94 million gross proceeds from

Longview share sale$64 million YE 2013 bank debt (1)

Downside Natural Gas Protection

44% future production hedged at Aeco Cdn $3.84/mcf to Q1

2016Dev plan based on Aeco Cdn

$3.75/GJ (2)

Credit Facility Capacity79% undrawn ($236 million available) Anticipate credit facility growth due to

increased production

Total Debt/Cash flow 1.5x (3)

over 3 year Dev PlanLow cost structure

Three Year Growth Plan Reinforced by Solid Financial StrategyThree Year Growth Plan Reinforced by Solid Financial Strategy

(1) Estimated bank debt at December 31, 2013 pro forma the net proceeds from the Longview share sale.(2) Strip price as of January 28, 2014 for period 2014 to 2017(3) Based on peak total debt at end of each development phase to forward cash flow

Development Plan (3)

Phase VI Phase VII Phase VIII Phase IXQ2’13 to

Q1’14Q2’14 to

Q1’15Q2‘15 to

Q1’16Q2’16 to

Q1’17Current Approved Estimates Estimates

Production (mmcfe/d)12 month average 114 135 174 209 End of Phase Target 135 183 205 245

WellsDry 22 20 22 24 Liquids Rich 3 13 9 11 Total 25 33 31 35

Capital ($ millions) $165 $265 $255 $215

Commodity Prices (4)

NYMEX ($US/mmbtu) $4.00 $4.40 $4.10 $4.10 AECO ($/GJ) $3.30 $4.10 $3.65 $3.55 WTI ($US/bbl) $98.00 $92.50 $85.00 $80.50

Financial ($ millions)Funds from operations $103 $165 $205 $240Bank debt – peak (5) $105 $265 $325 $290 Total debt – peak (5) $225 $325 $375 $333

Bank debt/cash flow (5) 0.7 1.3 1.4 1.0

Total debt /cash flow (5) 1.4 1.6 1.6 1.1

Three Year Glacier Development Plan Designed to Deliver100% Production per Share and 190% Cash Flow per Share Growth Three Year Glacier Development Plan Designed to Deliver100% Production per Share and 190% Cash Flow per Share Growth

(1) Based on input assumptions illustrated in above table. Growth % represents average production change and CFPS change in each 12 month consecutive Phase.

(2) Based on 168.4 million shares outstanding.(3) All capital and operating input parameters are based on mid-point estimates.(4) Based on strip prices as of January 28, 2014.(5) Estimated peak bank debt & total debt at end of development Phase pro forma Longview share sale.

Total debt includes bank debt, debentures and working capital.Cash flow based on forward period.

NGLs production grows from 900 bbls/d at end of Phase VII to 1,500

bbls/d in Phase IX

Three Year Development Plan – Strong Cash Flow Growth Three Year Development Plan – Strong Cash Flow Growth

Capital required to stay flat at 135

mmcfe/d

Capital required to grow to 183

mmcfe/d


mmcfe/d


mmcfe/d


mmcfe/d


mmcfe/d


mmcfe/d

Total debt/ forward cash flow decreases as cash flow grows significantly based on an average natural gas price of Cdn $3.75/GJ (2014-2017)

PeaThe 12 month period post Q2 2017 generates $160 million of free cash flow at a natural gas price of Cdn $3.65/GJ assuming flat production of 245 mmcfe/d

Netbacks and Recycle Ratios Dry Gas ($/mcfe)Liquids Rich Gas

($/mcfe)

2P F&D Average Undeveloped Location (1) $1.10__ . $1.57__ .

Glacier Operating Netback (2):

Revenue (3) $4.22 $5.76

Royalties 0.21 0.29

Operating Costs 0.28 . 0.30 .

Netback $3.73 . $5.17 .

2P Recycle Ratios:

3 year average 3.4x . 3.3x .

(1) Based on Sproule’s average 2P reserve booking for undeveloped locations in the Glacier 2013 reserve report: Dry gas $5.65 million/ well at 5.3 Bcfe (Upper & Lower). Liquids rich gas well $6.50 million at 4.13 Bcfe.

(2) Based on January 28, 2014 prices for Phase VII Budget period AECO CDN$4.10/GJ and C3+ at a blended price of $74.00/bbl(3) Revenue is net of transportation costs

Glacier Well Netback and Recycle Ratio Supports Strong Drill Economics

Operating Netback is

89% of revenue

(1) Management estimates. NPV 10% pre-tax(2) Based on $5.8 million per well with 17 frac stages(3) Based on $6.6 million per well with 17 frac stages and NGL yields of 39 bbls/mmcf raw gas(4) Natural gas prices and costs escalated at 2%. Average C3+ NGL price of $60.29/bbl escalated at 2%

Glacier Montney Well Economics(1)Ra

te of R

eturn (%

)

AECO Gas Price $/mcf (4)

Phase VII Budget uses average IP 30

of 4 mmcf/d

Phase VII Budget uses average IP 30 type curve of 6.9

mmcf/d$10.9 million

$8.8 million

$6.7 million

$10.5 million

$7.9 million

$4.9 million

Strong well economics driven by industry leading cost

structure and well performanceDry Gas

Upper and Lower Montney (2)Liquids Rich Gas

Middle Montney Intervals (3)

Exceptional Upper Montney Well Performance Across Glacier Exceptional Upper Montney Well Performance Across Glacier

21 mmcf/d record well

10 mmcf/d15 mmcf/d

14 mmcf/d

Drilled and completed

Drilling or to be drilledWaiting on completion

Phase VI wells are proving up reserves in east Glacier at above well type curve expectations

Upper Montney results from west to east Glacier demonstrated exceptional results and robust economic returns

A total of 86 Upper Montney Hz wells have been drilled and completed to date across Glacier 24 of these wells tested at > 10 mmcf/d 44 wells tested at >7 mmcf/d

Current Phase VI well test rates (1)(2)

(1) Based on well final test rate normalized to average gas gathering system pressure of 3,000 kpa(2) See Appendix for well test information.

19 mmcf/d

17 mmcf/d

18 mmcf/d15 mmcf/d

13 mmcf/d

12 mmcf/d

13 mmcf/d

12 mmcf/d

12 mmcf/d12 mmcf/d

11 mmcf/d

11 mmcf/d

11 mmcf/d

11 mmcf/d

11 mmcf/d

11 mmcf/d

11 mmcf/d 10 mmcf/d

10 mmcf/d

previous wells Denotes

previous wells >10 mmcf/d test rates (1)

10 mmcf/d

9 & 5 mmcf/d

Production from slickwater fracs exhibiting clean-up after test & shallower declines

21 mmcf/d initial production restricted

to 10 mmcf/d

Recent Results Confirm Solid Lower Montney Results Across GlacierRecent Results Confirm Solid Lower Montney Results Across Glacier

3.6 mmcf/d

10.6 mmcf/d

9.4 mmcf/d

6.8 mmcf/d3.7 mmcf/d



Phase VI wells proving up reserves in east and northwest Glacier and confirms commerciality

Lower Montney average type curve yields strong economics

Future completion design changes could further improve results – more stages and high frac rates

A total of 22 Lower Montney Hz wells have been drilled and completed to date across Glacier

3 mmcf/d

11 mmcf/d

9 mmcf/d

7 mmcf/d4 mmcf/d



Previous LM well 16 mmcf/d

(1) Based on well final test rate normalized to average gas gathering system pressure of 3,000 kpa(2) See Appendix for well test information.

5 mmcf/d

7 mmcf/d

Current Phase VI well test rates (1)(2)

Previous LM well Previous LM well 14 mmcf/d

4 mmcf/d

/d 10 mmcf/d initial

production

12 mmcf/d initial

production

Production from slickwater fracs

exhibiting clean-up after test and shallower

declines

Recent Glacier Upper and Lower Montney Slickwater Wells Recent Glacier Upper and Lower Montney Slickwater Wells

Recent Upper and Lower Montney wells completed with slickwaterfracs are outperforming Phase VII Budget type curve which is based on an IP30 6.9 mmcf/d.

Production from new slickwaterwells have come on-production at or above test rates & exhibiting shallower decline

High rate wells are typically rate

restricted to avoid sand erosion issues

26 bbl/mmcf

4 mmcf/d63 bbl/mmcf26 bbl/mmcf



31 bbl/mmcf8 bbl/mmcfvertical well



mmcf/dbbl/mmcfbbl/mmcf

Test Gas rate (1)

C3+ liquids yield (2)

20 bbl/mmcf


• Liquid yields are higher in east Glacier & pervasive through entire land block

Condensate yield

Phase VI wells confirm AAV geological model with increasing liquids up-dip across Glacier lands

Results to date will add reserves and confirms commerciality based on average type curve

Future completion design changes expected to improve well performance – more frac stages and high frac rates

Local variations in Middle Montney highlighting “sweet spots”

A total of 9 Middle Montney Hz wells have been drilled to date across Glacier



4 mmcf/d27 bbl/mmcf

8 bbl/mmcf

4 mmcf/d76 bbl/mmcf

45 bbls/mmcf


Record Well 100/12-2-76-12w6

13 mmcf/d 42 bbl/mmcf20 bbl/mmcf

Middle Montney - Record 13 MMcf/d Well With Free Condensate Middle Montney - Record 13 MMcf/d Well With Free Condensate

(1) Based on well final test rate normalized to average gas gathering system pressure of 3,000 kpa(2) Based on shallow cut liquids extraction process(3) See Appendix for well test information.

Current Phase VI well test rates (1) (3)

volumes

9.5 mmcf/d initial production

restricted to 6 mmcf/d due to

high liquid volumes

Middle Montney wells have consistently shown increasing

productivity as we optimize frac’s. Recent wells exceeding

Budget type curve

Frac design changes include open hole packer design with higher

pump rates. Previous wells were completed with cluster frac and

lower pump rates.

New Completion Techniques – Middle Montney 3x Production Improvement at Glacier (graphs updated to March 23, 2014)

Production Rate vs Cumulative Production

Production Rate vs Time

New Phase VI 12-2 well started production at restricted rate of

9.5 mmcf/d. Restricted to 6 mmcf/d to manage handling of

high liquid volumes

Note: Type curve used by Sproule for March 31, 2013 estimate of contingent resources. Sproule 2C is best estimate and 3C is high case contingent resource well type curve. See Appendix A.

New 12-02 Middle Montney Well

100/12-02-076-12W6 (Slickwater)

New Montney Lands – Prospective for Natural Gas Liquids(1)

Phase VI drilling results confirm increasing liquids in east Glacier and extends liquids potential to new lands

Technical work to date indicates thick Montney formation and multiple layer potential in the new lands

Additional 43.25 net sections of Montney

Acreage

Glacier 77 net

Montney sections

(1) Liquids yields shown on map are based on a shallow cut liquids extraction process

High Liquid Yield Middle Montney Wells

New 12-2 well restricted to 6 mmcf/d to manage handling of high liquid

volumes

New Montney Lands – Type Logs Show Thick Formation & Multiple Layer PotentialNew Montney Lands – Type Logs Show Thick Formation & Multiple Layer Potential

Valhalla Type Log

Upp

erM

iddl

eLo

wer

Mid

dle

Low

er

Gla

cier

Liq

uids

Ric

h La

yers

Gla

cier

Liq

uids

Ric

h La

yers

(Upper Missing)

230

m

185

m

Wembley Type LogValhalla

Wembley

Glacier Type Log

Upp

erM

iddl

eLo

wer

290

m Vertical scale change

Gla

cier

Liq

uids

Ric

h La

yers

Thick resource potential at Valhalla and Wembley

Multiple layer potential

Log porosity is similar to Glacier

Approved Glacier Phase VII Budget and GuidanceApproved Glacier Phase VII Budget and Guidance

Approved Phase VII Budget & Guidance(1) 12 Months endingMarch 31, 2015

Average Production (mmcfe/d) 134 to 139

Royalty Rate (%) 5% to 6%

Operating Costs ($/mcfe) $0.25 to $0.30

Capital Expenditures ($ million) $260 to $270

Wells Required (net) Dry gas 20Liquids rich gas 13Total 33

Note: Upon completion of Phase VII, production in the second quarter of 2015 is expected to grow to 183 mmcfe/d including 900 to 1,100 bbls/d of NGLs.

(1) Refer to input assumptions included in page 11 under Phase VII development(2) Average well type curves used in Phase VII Budget include IP30 of 6.9 mmcf/d for dry gas (Upper

& Lower Montney) & 4 mmcf/d for liquids rich gas (Middle Montney)

Glacier Phase VII – Middle Montney Liquids Extraction Plans

(1) 39 bbls/mmcf based on Sproule December 31, 2013 Reserves Report. Liquids yield: Pentanes Plus 16 bbls/mmcf; Butane 13 bbls/mmcf; Propane 10 bbls/mmcf

0 50 100 150

Shallow Cut C3+

Deep Cut C2+

Middle Montney – Average C3+ Liquids Yield(1)(bbls/mmcf raw gas)

9639

Shallow cut liquids extraction process to be installed in Q2 2015 at existing 100% owned Glacier gas plant

Phase VII program targets initial 25 mmcf/d of liquids rich natural gas generating ~ 900 to 1,100 bbls/d of NGL’s in Q2 2015

Pipeline commitment made for natural gas liquids transportation beginning in 2015

Phase VII program will concentrate Middle Montney wells in east Glacier where well tests show higher C3+ liquids yields (up to 76 bbls/mmcf) compared to field average

Estimated liquids production in the development plan is based on the average Middle Montney liquid yield of 39 bbls/mmcffrom wells tested across Glacier

Advantage 100% W.I. Glacier Gas Plant

Advantage Summary – Growing Our Montney at Glacier

Focused on our world class 16 Tcf TPIIP Glacier Montney property and development of its 4.2Tcfe contingent resources & 1.7 Tcfe 2P reserves(1)

Additional 43.25 net sections of new undeveloped Montney lands provides further upside

Strong Glacier 2013 Reserve Replacement Efficiencies and Production Performance 840% Production replacement at F&D cost of $1.33/mcfe and one year recycle ratio of 2.1x Achieved 135 mmcfe/d Phase VI production target ahead of schedule with capital

spending $13 million below Budget

Glacier Three Year Development Plan • Grow production per share by ~100% in 2017 • Increase cash flow per share ~ 190%(2) with at an average Total Debt/Cash of 1.5x (2)(3)

• Solid financial strategy and operational expertise underpins execution capability

Recent drilling achievements improved well productivity in the Upper, Middle and Lower Montney across Glacier resulting in robust well economics

• Record Upper Montney well at 21 mmcf/d and record Middle Montney well at 13 mmcf/d

Phase VII Budget (2014/15) approved by Board• Grows Glacier production in 2014/15 by 36% to 183 mmcfe/d

(1) Based on Sproule’s March 31, 2013 Resource Assessment & Glacier 2P Reserve report as of December 31, 2013. See Appendix A. (2) Assumes an average price of AECO Cdn $3.75/GJ (strip price as of January 28, 2014 for 2014 to 2017).(3) Based on end of development phase peak total debt to forward cash flow.

Appendix

SandSilt

Shale

The Montney formation is a siltstone and sand matrix which leads to better permeability and higher recovery factors than pure shale playsThe Montney formation at Glacier is over pressured and is deposited at depths from 2250 to 2715 metersTechnological improvements in drilling and completion designs are resulting in increased initial production rates and reserves

Montney Siltstone Supports High Reserve Recoveries

84 gross (77 net) sections -Historic type curve based

on 86 wells with an average of 11.5 fracs per

well

(1) Source: TD Securities – WCSB Gas Resources Drive LNG Export Strategies, November 21, 2012 (page 49)

Recent wells are out-performing this

type curve

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 & productivity

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

Completion Study Area

2012 Core & Completion Studies – Increased Resource & Improved Well Results

Recent Glacier Upper Montney wells are indicating higher type curves. Each subsequent Phase

has demonstrated improving well performance

Recent Glacier Upper Montney wells show up to

2x-3x improvement and significantly outperform on

cumulative production

New Completion Techniques – Upper Montney 2x - 3x Production Improvement at Glacier (graphs updated to March 23, 2014)



New 5-20 Phase VI well started production up to 20

mmcf/d & restricted to manage frac sand flowback

Average of 10 Glacier Upper Montney wells with revised

completion techniques


Recent Glacier Lower Montney wells show up to

3x improvement & significantly outperform

offset wells on cumulative production

New 10-31 & 15-31 Phase VI wells above

Budget type curve

New Completion Techniques – Lower Montney 3x Production Improvement at Glacier (graphs updated to March 23, 2014)


Recent Glacier Lower Montney wells are indicating higher type

curves. AAV 7-7 well is one of the top performing wells in the entire

region and was treated with a higher frac pump rate than 10-7



Summary of Well Tests Referenced in Presentation Slides Summary of Well Tests Referenced in Presentation Slides

Well Formation

Final Gas Test Rate

(mmcf/d)

Test Period(hrs)

Final Flow Pressure

(kpa)

Normalized Final Gas Test Rate (1)

(mmcf/d)

Estimated C3+ liquid yield (bbls/mmcf) (2)

00/01-27-76-13W6-Horizontal Upper Montney 11.2 78 4,601 11.4 -02/10-07-76-13W6-Horizontal Upper Montney 6.8 94 7,900 7.6 -00/05-20-76-12W6-Horizontal Upper Montney 18.4 71 8,633 21.2 -02/01-16-76-12W6-Horizontal Upper Montney 9.2 71 6,205 9.8 -00/01-18-76-12W6-Horizontal Upper Montney 12.8 60 7,920 14.4 -00/08-18-76-12W6-Horizontal Upper Montney 13.6 72 10,773 17.4 -00/10-07-76-13W6-Horizontal Lower Montney 9.6 109 16,652 15.6 1100/07-07-76-13W6-Horizontal Lower Montney 12.5 66 8,241 13.7 1100/15-31-75-13W6-Horizontal Lower Montney 9.8 72 7,772 10.6 1300/10-31-75-13W6-Horizontal Lower Montney 8.8 57 7,064 9.4 1500/01-16-76-12W6-Horizontal Lower Montney 6.7 72 4,218 6.8 1602/01-18-76-12W6-Horizontal Lower Montney 3.6 72 4,928 3.7 1102/05-02-76-12W6-Horizontal Lower Montney 3.3 70 3,736 3.3 1900/07-15-76-13W6-Vertical Middle Montney 0.2 77 380 0.2 3000/04-21-76-13W6-Vertical Middle Montney 0.5 72 809 0.5 3100/04-19-76-12W6-Vertical Middle Montney 0.2 63 315 0.2 4000/15-04-76-13W6-Horizontal Middle Montney 1.1 144 420 1.1 1800/09-09-76-12W6-Horizontal Middle Montney 1.8 99 3,135 1.8 4203/01-16-76-13W6-Horizontal Middle Montney 3.7 120 3,345 3.7 2700/07-07-77-13W6-Horizontal Middle Montney 7.5 85 8,625 8.4 2602/13-29-76-12W6-Horizontal Middle Montney 7.3 72 7,882 8 5703/01-09-76-12W6-Horizontal Middle Montney 4.0 88 7,437 4.3 7603/01-18-76-12W6-Horizontal Middle Montney 3.5 72 5,570 3.6 6300/05-02-76-12W6-Horizontal Middle Montney 1.6 72 3,161 1.6 7600/12-02-76-12W6-Horizontal Middle Montney 11.6 72 9,410 13.1 4202/07-07-77-13w6-Horizontal Lower Montney 6.0 72 9,412 6.8 900/16-33-76-13w6-Horizontal Lower Montney 4.5 72 9,270 5.1 1100/09-03-76-13W6-Horizontal Upper Montney 4.7 72 6,652 5.1 -00/16-03-76-13W6-Horizontal Upper Montney 7.1 54 9,544 8.5 -02/09-04-76-12W6-Horizontal Lower Montney 3.7 72 5,795 3.9 1100/13-08-76-12W6-Horizontal Upper Montney 7.5 58 11,934 10.2 -

(1) Based on well test final rate normalized to average gas gathering system pressure of 3000 kpa.(2) Estimated recovery from shallow cut extraction process.

Glacier Drilling Economics & 2P Recoveries per Interval

AECO C natural gas price ($/mcf)(2)Dry Gas(3) Liquids Rich Gas(4)

$3.00 $4.00 $5.00 $3.00 $4.00 $5.00

IP30’s and 2P Reserves:

4 mmcf/d & 4 Bcf N/A N/A N/A $2.8 $4.9 $7.1

5 mmcf/d & 5 Bcf $1.8 $4.6 $7.4 $5.2 $7.9 $10.5

6 mmcf/d & 6 Bcf $3.4 $6.7 $10.0 $7.7 $10.5 $13.1

7 mmcf/d & 7 Bcf $5.0 $8.8 $12.4 $9.6 $12.7 $15.6

8 mmcf/d & 8 Bcf $6.5 $10.9 $14.3 N/A N/A N/A

(1) Management estimates(2) Natural gas prices and costs escalated at 2%. Average C3+ NGL price of $60.29/bbl escalated at 2%(3) Based on $5.8 million per well with 17 frac stages(4) Based on $6.6 million per well with 17 frac stages and NGL yields of 39 bbls/mmcf raw gas(5) Based on Sproule December 31, 2013 reserves report

($ millions unless otherwise indicated)

Glacier Drilling Economics – PV’s @ 10% Discount(1)

# of Gross Hz Wells2P Recovery(bcf/well)

Developed Undeveloped Total Developed UndevelopedInterval YE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE 2013

1 73 83 174 169 247 252 4.3 4.4 4.7 5.42 5 8 16 38 21 46 2.7 3.9 4.0 4.23 1 4 0 19 1 23 2.5 2.7 0.0 3.14 0 0 0 0 0 0 0.0 0.0 0.0 0.05 15 22 76 72 91 94 2.9 3.8 5.0 5.1

Total 94 117 266 298 360 415

Glacier – 2P Recoveries per Interval(5)

Advantage Glacier Reserve Summary Advantage Glacier Reserve Summary

Advantage engaged our independent qualified reserves evaluator, Sproule Associates Ltd. (“Sproule”) ,to update the reserves analysis for the Company (the “Sproule Report”) as at December 31, 2013 in accordance with National Instrument 51-101 (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook. Reserves and production information included herein is stated on a Gross (before royalties) Working Interest Reserves basis unless noted otherwise. This summary contains several cautionary statements that are specifically required by NI 51-101.

Natural Gas Liquids Natural Gas Equivalent (mmbl) (mmcf) (mboe) Proved Developed Producing 731 204,220 34,767 Developed Non-producing 243 27,648 4,851 Undeveloped 6,084 759,424 132,655 Total Proved 7,058 991,292 172,273 Probable 5,945 626,360 110,338 Total Proved + Probable 13,003 1,617,652 282,611


(1) Advantage’s crude oil, natural gas and natural gas liquid reserves were evaluated using Sproule’s product price forecast effective December 31, 2013 prior to the provision for income taxes, interests, debt services charges and general and administrative expenses. It should not be assumed that the discounted future revenue estimated by Sproule represents the fair market value of the reserves.

(2) Assumes that development of each property will occur, without regard to the likely availability to the Company of funding required for that development.(3) Future development capital increase from $1.54 billion to $1.81 billion is included in the Reserve Report

Glacier Present Value of Future Net Revenue using Sproule price and cost forecasts (1)(2) ($000) Before Income Taxes Discounted at 0% 10% 15% Proved

Developed Producing $802,614 $466,482 $394,415 Developed Non-producing 117,124 68,895 57,977 Undeveloped 2,585,106 682,770 391,751 Total Proved 3,504,844 1,218,146 844,143

Probable 3,136,407 889,960 590,598 Total Proved + Probable $6,641,251 $2,108,106 $1,434,741

Advantage Glacier Reserves SummaryAdvantage Glacier Reserves Summary

Glacier Reserve Summary Glacier Reserve Summary

Sproule Price ForecastsThe present value of future net revenue at December 31, 2013 was based upon crude oil and natural gas pricing assumptions prepared by Sprouleeffective December 31, 2013. These forecasts are adjusted for reserve quality, transportation charges and the provision of any applicable sales contracts. The price assumptions used over the next seven years are summarized in the table below:

Alberta AECO-C Henry Hub Edmonton Edmonton Edmonton Exchange Natural Gas Natural Gas Propane Butane Pentanes Plus Rate Year ($Cdn/mmbtu) ($US/mmbtu) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($US/$Cdn) 2014 4.00 4.17 45.78 69.05 103.50 0.94 2015 3.99 4.15 44.14 66.57 99.78 0.94 2016 4.00 4.17 44.30 66.81 100.14 0.94 2017 4.93 5.04 50.22 75.74 113.53 0.94 2018 5.01 5.12 50.98 76.88 115.24 0.94 2019 5.09 5.19 51.74 78.03 116.97 0.94 2020 5.18 5.27 52.52 79.20 118.72 0.94

Advantage engaged our independent qualified reserves evaluator Sproule Associates Ltd. (“Sproule”) to update the resource analysis and provide a 2C evaluation (“Sproule 2C Contingent Resource Evaluation”) at Glacier as of March 31, 2013 in accordance to the Canadian Oil and Gas Evaluation Handbook (COGEH) resource definitions that are consistent with the standards of National Instrument 51-101. The estimates of reserves and resources for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

The following three tables summarize the results of Sproule’s resource assessment of Advantage’s Glacier Montney resources as at March31, 2013:

Resource Categories (AAV Working Interest, Best Estimate, Raw) (1) TcfTotal Petroleum Initially In Place (TPIIP) 16.03Discovered Petroleum Initially in Place (DPIIP) (2) 13.98Undiscovered Petroleum Initially in Place (UPIIP) (3) 2.05

Appendix – Glacier March 31, 2013 Contingent and Prospective Resource Assessment

DPIIP (AAV Working Interest, Sales) (2)Low

EstimateBest

EstimateHigh

EstimateNatural GasCumulative Production (Tcf) (4) 0.100 0.100 0.100Reserves (Tcf) (5) 0.927 1.526 1.770Contingent Resources (Tcf) 2.316 3.540 4.898Unrecoverable DPIIP (Tcf) 9.574 7.751 6.149Natural Gas LiquidsCumulative Production (mbbls) (4) - - -Reserves (mbbls) (5) 5,949 11,071 12,732Contingent Resources (mbbls) 72,472 110,274 152,013Unrecoverable DPIIP (mbbls) 225,654 182,730 139,330

(1) See Appendix C for the definitions from the COGE Handbook of the various resource categories used herein.(2) There is no certainty that it will be commercially viable to produce any portion of the DPIIP.(3) There is no certainty that any portion of the UPIIP will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the

UPIIP.(4) The cumulative production represents the actual total historic production from Advantage's Glacier Montney resources and as such is not a Low, Best or High Estimate.(5) For reserves, the Low Estimate is proved reserves, the Best Estimate is proved plus probable reserves and the High Estimate is proved plus probable plus possible

reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Appendix – Glacier Contingent and Prospective Resource Assessment

UPIIP (AAV Working Interest, Sales) (3)Low

EstimateBest

EstimateHigh

EstimateNatural GasProspective Resources (Tcf) 0.342 0.556 0.776Unrecoverable UPIIP (Tcf) 1.561 1.347 1.127Natural Gas LiquidsProspective Resources (mbbls) 7,381 11,691 16,274Unrecoverable UPIIP (mbbls) 25,558 21,248 16,665

Appendix – Glacier Contingent and Prospective Resource Assessment

2C (Best Estimate) Contingent Resources Net Present ValuesBefore Income Taxes

($ millions)

IntervalGross Number of Hz

Well Locations

Gross 2C Recoverable Resources per Location

(Raw – Bcf per Well) 0% 10% 15%

1 60 3.425 777 46 132 286 4.035 6,031 1,791 1,1533 280 3.120 4,869 565 2264 260 3.030 4,598 379 1275 234 4.440 4,135 802 420Facility Costs N/A N/A (758) (368) (296)

Total 1,120 4,619 $19,652 $3,215 $1,642

Sproule evaluated the economics of Advantage's Best Estimate contingent resources based on a development scenario that was provided by Advantage. The development plan included the drilling of 1,120 future contingent locations with a total undiscounted capital expenditure of $8.3 billion which includes the

necessary facilities and infrastructure costs. For the evaluation of proved plus probable reserves, the development plan assumed a maximum production rate of 200 mmcf/d is reached in 2015 and maintained

until 2026. The proved plus probable reserves evaluation included the drilling of 313 future undeveloped locations with a total undiscounted capital expenditure of $1.9 billion.

In estimating the Glacier contingent resources, Sproule assumed based on Advantage's development plan that gas plant capacity would increase over and above the proved plus probable reserves forecast by 100 mmcf/d per year of raw gas starting in 2015 to a total throughput of 600 mmcf/d raw gas by 2018. The 600 mmcf/d raw facility throughput capacity was then maintained to the year 2032 by drilling wells as required.

The 2C contingent resources at Glacier are all considered to be Economic Contingent Resources based on the forecast commodity prices, capital costs and operating costs as at March 31, 2013. The crude oil and natural gas pricing assumptions used for the estimate were prepared by Sproule effective March 31, 2013.

Appendix – Glacier Contingent & Prospective Resource Assessment

Other Notes about Resource Estimates:

TPIIP, DPIIP and UPIIP have been estimated using a zero percent porosity cut-off (sandstone log scale). The Montney formation is approximately 300 meters thick. Sproule’s analysis utilized 6 potential layers consisting of 1 layer in the Upper Montney, 3 layers in the Middle Montney and 2 layers in the Lower Montney. With the exception of the lowest layer in the Lower Montney, all other layers exist across the entire Glacier land block.

Recoverable gas volumes were estimated using a 4 well per section development in each of the layers within the Montney formation at Glacier. Recovery factors were assigned to each layer based on the performance of existing wells in the layer or in similar layers.

Reserves have only been assigned to Layer 1 (Upper Montney), Layers 2 & 3 (Middle Montney) and Layer 5 (Lower Montney). Contingent Resources are assigned to all five layers except the sixth layer of the Lower Montney (all of Layer 6 is prospective).

Contingent Resources for each section and layer were assigned if there was a sustained gas test within 3 miles of the section, otherwise, the resource was classified as prospective undiscovered resources.

Liquid yields are unique to each layer and were estimated based on the gas composition of gas samples combined with any free liquids obtained from well production tests in each layer.

The contingencies Sproule identified to convert Contingent Resource into reserves are specific to each layer and generally include the following: Development maturity including the number of sustained well tests and the amount of production information. Sproule indicates that

very few sections in Layers 2 and 3 (Middle Montney) have reserves assigned; however, there are sufficient tests spread geographically across the lands to classify the bulk of the sections as Contingent Resources. No reserves have been assigned to Layer 4 (Middle Montney); however, there have been sufficient testing of a few wells located very low in Layer 3 and spread geographically across the lands to classify many sections as contingent in Layer 4.

The lack of infrastructure to facilitate full development in the short term including the required processing facilities to extract NGLs in certain Montney layers.

Economic contingencies dictating a slower pace of development with current low gas prices in sections that are farther from existing gas gathering infrastructure and farther from existing tests.

Prospective resources account for only 9.6% of the estimated ultimate recoverable resources in the 2C best estimate case and demonstrates that the vast majority of the Montney formation at Glacier has been shown to be productive.

Appendix — Reserve and Resource Definitions

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total resources" is equivalent to "Total Petroleum Initially-In-Place". Resources are classified in the following categories:Total Petroleum Initially-In-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.Discovered Petroleum Initially-In-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.The recoverable portion of discovered petroleum initially in place includes production, reserves, and Contingent Resources; the remainder is unrecoverable.Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.Economic Contingent Resources are those contingent resources that are currently economically recoverable.Undiscovered Petroleum Initially-In-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as "prospective resources" and the remainder as "unrecoverable."Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and resources as follows:Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

Certain statements contained in this presentation constitute forward-looking statements. These statements 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 "seek", "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 the Corporation’s development plan to increase production at Glacier and the anticipated production levels and timing thereof; anticipated effect of three year development plan at Glacier on production per share growth and cash flow per share growth, including the Corporation's expectations as to the levels of such growth and the timing of achievement of such levels; estimated debt levels following the sale of the Longview common shares; number of expected future drilling locations; the Corporation's plans to evaluate additional sections of Montney acreage for prospective natural gas and liquids potential; anticipated effect of production history from recent wells and future well test results on reserve replacement efficiencies at Glacier; the Corporation’s anticipated drilling and completion plans, including drilling inventory, future locations, additional wells required for three year development plan and available wells after 2017; effect of refinement of drilling and completion techniques; effect of termination of TSA on general and administrative expenses and financial and operational complexity; the Corporation's expectations regarding increase to borrowing base for it credit facilities; anticipated increases to production at Glacier, including Advantage's guidance in respect of anticipated production levels (including the commodities expected), end of phase production rates, capital expenditures, number and types of wells drilled, wellhead deliverability, commodity prices, funds from operations, bank debt, funds from operations, and debt to cash flow ratios for Phase VI, Phase VII, Phase VIII and Phase IX and Advantage's guidance in respect of capital expenditures and debt to cash flow ratios for the period from Q2 2017 to Q2 2018; expected continued improvements in cost efficiencies and design changes on drilling and completion plans and well performance; Advantage's guidance in respect of anticipated production levels, end of phase production rates, royalty rates, operating costs, capital expenditures and number and types of wells drilled for the 12 months ended March 31, 2015; the Corporation's expectations as to the benefits from its natural gas hedges; expectations of facilities expenditures and details thereof; plans to proceed with the installation of a liquids extraction process; ability to enhance initial production rates, rates of return and reserves; estimated three year recycle ratios and netbacks; and projections of market prices and costs. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described can be profitably produced in the future. 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; actions by governmental or regulatory authorities including increasing taxes and changes in investment or other regulations; the effect of acquisitions; Advantage's success at acquisition, exploitation and development of reserves; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; fluctuations in commodity prices and foreign exchange and interest rates; stock market volatility and market valuations; volatility in market prices for oil and natural gas; 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; 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; delays in anticipated timing of drilling and completion of wells; individual well productivity; competition from other producers; the lack of availability of qualified personnel or management; credit risk; our ability to comply with current and future environmental or other laws; 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; 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 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. 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 commodity prices and royalty regimes; future exchange rates; royalty rates; future operating costs; current commodity prices and royalty regimes; availability of skilled labor; availability of drilling and related equipment; timing and amount of capital expenditures; the impact of increasing competition; the price of crude oil and natural gas; that the Corporation 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 the Corporation’s conduct and results of operations will be consistent with its expectations; that the Corporation will have the ability to develop the Corporation’s properties in the manner currently contemplated; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated; and the estimates of the Corporation’s production and reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects.

Advisory

AdvisoryAdvisory

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. Except as required by law, Advantage undertakes no obligation to publicly update or revise any forward-looking statements. For additional risk factors in respect of Advantage and its business, please refer to it Annual Information Form dated March 26, 2013 which is available on SEDAR at www.sedar.com and www.advantageog.com.

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 "behind pipe production“ 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. 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, the Corporation cautions that the test results should be considered to be preliminary.

Throughout this presentation the terms boe (barrels of oil equivalent), mcfe (thousand of cubic feet of gas equivalent), mmcfe (millions of cubic feet of gas equivalent), bcfe (billions of cubic feet of gas equivalent) and Tcfe (trillion of cubic feet of gas equivalent) 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.

The Corporation discloses several financial measures that do not have any standardized meaning prescribed under International Financial Reporting Standards ("IFRS"). These financial measures include funds from operations, net debt to cash flow ratio, enterprise value and operating netbacks. Management believes that these financial measures are useful supplemental information to analyze operating performance and provide an indication of the results generated by the Corporation’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. Funds from operations, as presented, is based on cash provided by operating activities, adjusted for expenditures on decommissioning liability, changes in non-cash working capital and interest on bank indebtedness. Net debt to cash flow ratio is calculated as indebtedness under Advantage's credit facilities plus working capital deficit divided by funds from operations. Enterprise value has been calculated by adding market capitalization as at March 10, 2014 (based on the number of issued and outstanding common shares as at March 10, 2014 multiplied by the market price of the common shares on the Toronto Stock Exchange on March 10, 2014) to the total pro forma debt as of December 31, 2013 after giving effect to the sale of shares of Longview Oil Corp. Operating netbacks are calculated by deducting royalties and operating costs from revenue on a unit (boe or mcfe) basis. Please see 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 of these financial measures, including a reconciliation of funds from operations to cash provided by operating activities.

The following abbreviations used in this press release, including in the appendices hereto, have the meanings set forth below:

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.

This presentation includes calculations of finding and development ("F&D") costs which have been calculated in accordance with Section 5.15 of NI 51-101 by adding together exploration costs, development costs and the change in future development costs and dividing the sum by reserves additions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.

In this presentation certain financial and operating metrics of other issuers are presented to compare such metrics to Advantage's results. Such other issuers were included to show how Advantage's performance compares to some of 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.

This presentation 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 or 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.

Advisory

bbls barrels mcf thousand cubic feetbbls/d barrels per day mmcf million cubic feet

mmcf/d million cubic feet per daymbbls thousand barrels bcf billion cubic feetboe barrels of oil equivalent of natural gas, on the basis of 1 barrel of oil or NGLs

for 6 thousand cubic feet of natural gasbcfe billion cubic feet of natural gas equivalent on the basis of 1 barrel of oil or

NGLs to 6 thousand cubic feet of natural gasmboe thousands of barrels of oil equivalent tcf trillion cubic feetboe/d barrels of oil equivalent per day tcfe trillion cubic feet of natural gas equivalent on the basis of 1 barrel of oil to 6

thousand cubic feet of natural gas2P proved plus probable reserves 2C best estimate contingent resourcesNGLs natural gas liquids GGS gas gathering system

Advantage Contact Information

www.advantageog.comListed on NYSE & TSX: AAV

Advantage Oil & Gas Ltd.Suite 300, 440 – 2nd Avenue SW

Calgary, Alberta T2P 5E9 Main: 403.718.8000 Facsimile: 403.718.8332

Investor [email protected]

Andy Mah, P.Eng.Director, President & Chief Executive Officer

Craig Blackwood, C.A.VP Finance & Chief Financial Officer

Advantage 100% W.I. Glacier Gas Plant

advantage oil and gas - april 2014

Investor Relations