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
Glacier
77 net
sections
Wembley
Valhalla
Recently acquired
43.25 net sections
of Montney Acreage
 Located in the heart of the Montney
siltstone 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
2PF&DCost($/Mcfe)
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 3
Year Development Plan (2)
Remaining
Undrilled 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
2016
Dev plan based on Aeco Cdn
$3.75/GJ (2)
Credit Facility Capacity
79% undrawn ($236 million available)
Anticipate credit facility growth due to
increased production
Total Debt/Cash flow 1.5x (3)
over 3 year Dev Plan
Low 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 IX
Q2’13 to
Q1’14
Q2’14 to
Q1’15
Q2‘15 to
Q1’16
Q2’16 to
Q1’17
Current Approved Estimates Estimates
Production (mmcfe/d)
12 month average 114 135 174 209
End of Phase Target 135 183 205 245
Wells
Dry 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 $240
Bank 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 Deliver
100% Production per Share and 190% Cash Flow per Share Growth
Three Year Glacier Development Plan Designed to Deliver
100% 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 GrowthThree Year Development Plan – Strong Cash Flow Growth
Capital
required
to stay
flat at
135
mmcfe/d
Capital
required
to grow
to 183
mmcfe/d
Capital
required
to grow
to 245
mmcfe/d
Capital
required
to grow
to 205
mmcfe/d
Capital
required
to stay
flat at
183
mmcfe/d
Capital
required
to stay
flat at
205
mmcfe/d
Capital
required
to stay
flat at
245
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)
Pea
The 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)
Rate of Return (%)
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 performance
Dry Gas
Upper and Lower Montney (2)
Liquids Rich Gas
Middle Montney Intervals (3)

Exceptional Upper Montney Well Performance Across GlacierExceptional Upper Montney Well Performance Across Glacier
21 mmcf/d
record well
10 mmcf/d
15 mmcf/d
14 mmcf/d
Drilled and completed
Drilling or to be drilled
Waiting 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/d
15 mmcf/d
13 mmcf/d
12 mmcf/d
13 mmcf/d
12 mmcf/d
12 mmcf/d
12 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/d
3.7 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/d
4 mmcf/d
Previous LM well
16 mmcf/d
5 mmcf/d
7 mmcf/d
Current Phase VI well test rates (1)(2)
Previous LM wellPrevious LM well
14 mmcf/d
4 mmcf/d
/d10 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 WellsRecent Glacier Upper and Lower Montney Slickwater Wells
Recent Upper and Lower Montney
wells completed with slickwater
fracs are outperforming Phase VII
Budget type curve which is based
on an IP30 6.9 mmcf/d.
Production from new slickwater
wells 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/d
63 bbl/mmcf
26 bbl/mmcf
8 mmcf/d
26 bbl/mmcf
8 bbl/mmcf
1 mmcf/d
18 bbl/mmcf
5 bbl/mmcf
31 bbl/mmcf
8 bbl/mmcf
vertical well
30 bbl/mmcf
10 bbl/mmcf
vertical well
mmcf/d
bbl/mmcf
bbl/mmcf
Test Gas rate (1)
C3+ liquids yield (2)
20 bbl/mmcf
2 mmcf/d
42 bbl/mmcf
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
8 mmcf/d
57 bbl/mmcf
32 bbl/mmcf
40 bbl/mmcf
10 bbl/mmcf
vertical well
4 mmcf/d
27 bbl/mmcf
8 bbl/mmcf
4 mmcf/d
76 bbl/mmcf
45 bbls/mmcf
2 mmcf/d
76 bbl/mmcf
45 bbl/mmcf
Record Well
100/12-2-76-12w6
13 mmcf/d
42 bbl/mmcf
20 bbl/mmcf
Middle Montney - Record 13 MMcf/d Well With Free CondensateMiddle Montney - Record 13 MMcf/d Well With Free Condensate
(2) Based on shallow cut liquids extraction process
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
UpperMiddleLower
MiddleLower
GlacierLiquidsRichLayers
(Upper Missing)
230m
185m
Wembley Type Log
Valhalla
Wembley
Glacier Type Log
UpperMiddleLower
290m
Vertical
scale
change
 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 ending
March 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 20
Liquids rich gas 13
Total 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)
96
39
 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/mmcf
from 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.

Sand
Silt
Shale
The Montney formation is a siltstone and sand matrix which
leads to better permeability and higher recovery factors than
pure shale plays
The Montney formation at Glacier is over pressured and is
deposited at depths from 2250 to 2715 meters
Technological 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 SlidesSummary 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 -
00/10-07-76-13W6-Horizontal Lower Montney 9.6 109 16,652 15.6 11
00/07-15-76-13W6-Vertical Middle Montney 0.2 77 380 0.2 30
00/15-04-76-13W6-Horizontal Middle Montney 1.1 144 420 1.1 18
00/09-09-76-12W6-Horizontal Middle Montney 1.8 99 3,135 1.8 42
02/13-29-76-12W6-Horizontal Middle Montney 7.3 72 7,882 8 57
02/07-07-77-13w6-Horizontal Lower Montney 6.0 72 9,412 6.8 9
00/16-33-76-13w6-Horizontal Lower Montney 4.5 72 9,270 5.1 11
(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 Wells
2P Recovery
(bcf/well)
Developed Undeveloped Total Developed Undeveloped
Interval 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 5.4
2 5 8 16 38 21 46 2.7 3.9 4.0 4.2
3 1 4 0 19 1 23 2.5 2.7 0.0 3.1
4 0 0 0 0 0 0 0.0 0.0 0.0 0.0
5 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 SummaryAdvantage 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 SummaryGlacier Reserve Summary
Sproule Price Forecasts
The present value of future net revenue at December 31, 2013 was based upon crude oil and natural gas pricing assumptions prepared by Sproule
effective 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 March
31, 2013:
Resource Categories (AAV Working Interest, Best Estimate, Raw) (1) Tcf
Total Petroleum Initially In Place (TPIIP) 16.03
Discovered Petroleum Initially in Place (DPIIP) (2) 13.98
Undiscovered 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
Estimate
Best
Estimate
High
Estimate
Natural Gas
Cumulative Production (Tcf) (4) 0.100 0.100 0.100
Reserves (Tcf) (5) 0.927 1.526 1.770
Contingent Resources (Tcf) 2.316 3.540 4.898
Unrecoverable DPIIP (Tcf) 9.574 7.751 6.149
Natural Gas Liquids
Cumulative Production (mbbls) (4) - - -
Reserves (mbbls) (5) 5,949 11,071 12,732
Contingent Resources (mbbls) 72,472 110,274 152,013
Unrecoverable 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
Estimate
Best
Estimate
High
Estimate
Natural Gas
Prospective Resources (Tcf) 0.342 0.556 0.776
Unrecoverable UPIIP (Tcf) 1.561 1.347 1.127
Natural Gas Liquids
Prospective Resources (mbbls) 7,381 11,691 16,274
Unrecoverable UPIIP (mbbls) 25,558 21,248 16,665

Appendix – Glacier Contingent and Prospective Resource Assessment
2C (Best Estimate) Contingent Resources Net Present Values
Before Income Taxes
($ millions)
Interval
Gross Number of Hz
Well Locations
Gross 2C Recoverable
Resources per Location
(Raw – Bcf per Well) 0% 10% 15%
1 60 3.425 777 46 13
2 286 4.035 6,031 1,791 1,153
3 280 3.120 4,869 565 226
4 260 3.030 4,598 379 127
5 234 4.440 4,135 802 420
Facility 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 feet
bbls/d barrels per day mmcf million cubic feet
mmcf/d million cubic feet per day
mbbls thousand barrels bcf billion cubic feet
boe barrels of oil equivalent of natural gas, on the basis of 1 barrel of oil or NGLs
for 6 thousand cubic feet of natural gas
bcfe billion cubic feet of natural gas equivalent on the basis of 1 barrel of oil or
NGLs to 6 thousand cubic feet of natural gas
mboe thousands of barrels of oil equivalent tcf trillion cubic feet
boe/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 gas
2P proved plus probable reserves 2C best estimate contingent resources
NGLs natural gas liquids GGS gas gathering system

Advantage Contact Information
www.advantageog.com
Listed 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 Relations
1.866.393.0393
ir@advantageog.com
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

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