Investor Presentation TSX / NYSE: AAV January 2015 ADVANTAGE: AT A - - PowerPoint PPT Presentation

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World Class Montney Resource, Industry Leading Low Cost Structure & Cash Margin and Operational Excellence Reinforces the Strength of our Three Year Growth Plan Investor Presentation TSX / NYSE: AAV January 2015 ADVANTAGE: AT A GLANCE

SLIDE 1

“World Class Montney Resource, Industry Leading Low Cost Structure & Cash Margin and Operational Excellence Reinforces the Strength of our Three Year Growth Plan”

TSX / NYSE: AAV Investor Presentation

January 2015

SLIDE 2

ADVANTAGE: AT A GLANCE

Canadian Pure Play Montney Producer Listed on TSX and NYSE AAV TSX 52‐week trading range $3.84 ‐ $7.85 Shares Outstanding (basic) 169.8 million Glacier Q3 2014 production 132.5 mmcfe/d (22,087 boe/d) Market Capitalization @ January 15, 2014 $0.9 billion Bank Debt @ September 30, 2014 (18% drawn on $400 million credit facility) $71.0 million Total Debt including working capital deficit @ September 30, 2014 $205.6 million

View of Glacier Plant Process Train – approximately 650 feet long

SLIDE 3

FOCUSED ON MONTNEY GROWTH & VALUE CREATION

3 Year Development Plan 100% Production Increase 245 mmcfe/d in 2017 (40,800 boe/d) 27 employees

World Class Montney Asset Operational Excellence Growth Plan & Financial Strength

SLIDE 4

Advantage – Financial & Operational Strengths

$0.85/mcfe (1)

Total Cash Costs – Industry Leading

51%@$3.90 (2)

2015 Natural gas hedge position (% forecast production & price)

$3.94/mcf (2)

Average Price of natural gas hedges to Q1 2017 (31% 2016, 25% Q1 2017)

$329 million(1)

Available on Credit Facility of $400 million

>120 mmcf/d(3)

Current excess well deliverability available to grow production 36% to 183 mmcfe/d target in June 2015. Plant expansion underway.

75%

Improvement in one year cumulative well production to approximately 2 Bcf due to slickwater frac’s (payout < 1 year)

$2.50/mcf (2)

Generates >30% ROR on Upper, Middle & Lower Montney well economics based on budget type curves

100%

Ownership & Operatorship of Glacier gas plant & pipeline infrastructure delivering sales gas directly into TCPL’s transmission system

(1) Based on Q3 2014 operating and financial results (2) AECO Cdn price $/mcf (3) Includes restricted and new Phase VII tested wells to date

SLIDE 5

Glacier Operating Netback

Actual YTD Q3 2014(1) ($/mcfe) Illustrative $2.50/mcfe

Revenue

$4.39(2) $2.50

Royalties

($0.22) ($0.13)

Operating Costs

($0.31) ($0.31)

Operating Netback

$3.86 $2.06

(Recycle Ratio at 2013 2P F&D $1.33/mcfe (3))

2.9x 1.6x

G&A

($0.17) ($0.17)

Interest Expense & other

($0.19) ($0.19)

Cash Flow Netback

$3.50 or $21.00/boe $1.70 or $10.20/boe

(1) YTD 2014 Netback based on actual results. (2) Revenue is net of transportation costs & hedging loss of $0.33/mcfe. (3) F&D includes Future Development Capital

Q3 ‘14 Operating netback is 88% of revenue

STRONG NETBACKS PROVIDE SUSTAINABILITY

Q3 ‘14 Cash flow netback is 80% of revenue

SLIDE 6

FINANCIAL STRENGTH SUPPORTS DEVELOPMENT PLAN

Credit Facility $329 million currently available (18% drawn on our $400 million credit facility) Balance Sheet 1.4x Total debt to annualized Q3 2014 Cash Flow Hedging Program

% Forecast Production Year Aeco $/mcf 56% 2014 Q4 $3.90 51% 2015 $3.90 31% 2016 $3.93 25% 2017 Q1 $3.95

(1) As of September 30, 2014

(1)

SLIDE 7

THREE YEAR GLACIER GROWTH PLAN

Three Year Plan Summary (1)

245 mmcfe/d (40,830 boe/d) in 2017 $735 million Capital Expenditures 33 New Montney wells per year $3.75/GJ Aeco Cdn average price 1.5x Average Total Debt to Forward Cash Flow per plan pricing

(1) See Plan Details in Appendix page 29

SLIDE 8

THREE YEAR PLAN ‐ PRICE SENSITIVITY REDUCED BY HEDGING & LOW COST STRUCTURE

Downside gas price mitigation while retaining torque to upside

SLIDE 9

50 100 150 200 250 300 350

Million $

Stay Flat Capex Growth Capex Cash Flow

GROWTH LEADS TO SIGNIFICANT FREE CASH FLOW IN EARLY 2017 BASED ON PLAN

Capital required to stay flat at 135 mmcfe/d Capital required to grow to 183 mmcfe/d Capital required to grow to 205 mmcfe/d Capital required to grow to 245 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

Phase VIII Q2 2015 ‐ Q1 2016 Phase IX Q2 2016 ‐ Q1 2017 Q2 2017 ‐ Q2 2018 Phase VII Q2 2014 ‐ Q1 2015

245 mmcfe/d @ $3.65/GJ generates $160 million free annual cash flow

SLIDE 10

INDUSTRY COST STRUCTURE & MARGIN COMPARISON

Advantage’s full cycle margin is among the top Montney producers today.

SLIDE 11

WORLD CLASS MONTNEY ASSET

300 meters Natural gas and liquids resource 16 Tcf TPIIP

Glacier

SLIDE 12

GLACIER – LOCATED IN THE HEART OF THE MONTNEY RESOURCE PLAY

Montney Siltstone Comparison:

700 times more permeability
4x more formation thickness
Very low clay content
Liquids & Improved well efficiencies strong economics

SLIDE 13

FOCUSED ON MONTNEY SURROUNDING GLACIER GAS PLANT

Glacier 77 net sections Wembley Valhalla

9 net Montney sections acquired 2014 100% owned Glacier Gas Plant

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

Current development of 16 TCF (1) TPIIP

at Glacier including liquids drilling

Glacier future drilling inventory ~1,400

locations

New Montney lands at Vahalla,

Wembley & Progress contain multiple layers but require evaluation

Total 129 net Montney sections (82,560

net acres)

Progress

43.25 net Montney sections acquired 2013

SLIDE 14

14 Glacier Gas Plant – Positioned for Production Ramp‐up

Glacier Gas Plant Site & Proximity to Major Natural Gas & Liquids Pipelines & Rail Access Provides Significant Expansion Potential

400 mmcf/d pipeline capacity to TCPL meter station in place

GLACIER 100% OWNED GAS PLANT & PIPELINE ACCESS

400 mmcf/d pipeline capacity to TCPL meter station in place Expansion to 250 MMcf/d Dry and Liquid Gas Processing Capability

SLIDE 15

GLACIER DELINEATION DRILLING HAS CONFIRMED MULTI‐LAYER DEVELOPMENT

EnCana began horizontal drilling in 2005; however, numerous vertical wells had penetrated the Montney providing geological information Advantage has drilled over 140 Montney wells at Glacier since 2008. Delineation drilling was designed to evaluate the Montney across our land block and in each of the multiple layers contained in ~300 meters of formation thickness

Swan & Tupper at 4 to 7 wells/section density today. Potential for 20 wells/section at Glacier

SLIDE 16

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

“PENTASTACK” DEVELOPMENT WITH DECADES OF DRILLING INVENTORY

Development based on four wells

per section per layer

Proven commercial well rates 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 and laterally offset in each layer for optimal recovery

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

Five Development Intervals Containing > 1,400 Future Locations

SLIDE 17

OPERATIONAL EXCELLENCE

SLIDE 18

Production Growth to 135 mmcfe/d & Operating Cost Reduction to ~$0.30/mcfe 73% Reduction in cost per frac despite increasing average number of frac stages from 7 to 16 580% Increase in 2P Reserves to 1.7 Tcfe 43% Reduction in 3 Year 2P F&D cost to $1.06/mcfe $475,000/frac stage $130,000/frac stage

No wells drilled

TRACK RECORD OF OPERATING PERFORMANCE

SLIDE 19

Advantage has significantly improved well performance since 2008. Utilization

f more frac stages and slickwater fracs have recently created another step‐

rate change. We anticipate new technology could further improve results.

UPPER AND LOWER MONTNEY AVERAGE WELL TYPE CURVE IMPROVEMENT

Data: updated to November 2014 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 0.0 0.5 1.0 1.5 2.0 2.5

Raw Gas Production Rate (mcf/d) Cumulative Raw Gas Production (Bcf)

Current Budget Type Curve (IP30 6.9 mmcf/d)

14 24 28 31 10 Well Count

Phase VI 2013 Phase IV & V 2011/12

Phase III 2010 Phase II 2009 Phase I 2008

SLIDE 20

IMPROVING UPPER & LOWER MONTNEY WELL PERFORMANCE WITH SLICKWATER

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. Graph illustrates production from 14 recent Montney wells (5 Upper and 9 Lower)

Phase VII Upper & Lower Budget Type Curve (IP30 6.9 mmcf/d) Data: updated to November 2014

SLIDE 21

(1) Based on Advantage Operating Netback of $3.86/mcfe for the first nine months of 2014

Upper and Lower Montney well performance

has improved through frac design & increased reservoir knowledge.

Some recent wells were initially restricted as

noted by the slope change in their cumulative production trend.

Top Tier Wells Trending toward Payout of <10 months(1) Cumulative production of >2 Bcf in first year

IMPROVING UPPER & LOWER MONTNEY WELL PAYOUT

Data: updated to November 2014

SLIDE 22

EXCEPTIONAL UPPER MONTNEY WELL ECONOMICS

(1)

(1) Management estimates. NPV 10% pre‐tax (2) Based on $5.5 million per well with 18 frac stages (3) Natural gas prices and costs escalated at 2%. Average C3+ Avg NGL price of $63.44/bbl escalated at 2%

Upper Montney Dry Gas (2)

Frac optimization of 108 Upper and Lower Montney wells since 2008 at Glacier has increased the average Budget type curve to an IP of 6.9 mmcf/d.

mmcf/d IP30 / Bcf

(3)

SLIDE 23

EXCEPTIONAL LOWER MONTNEY WELL ECONOMICS

(1)

(1) Management estimates. NPV 10% pre‐tax (2) Based on $5.8 million per well with 18 frac stages and C3+ NGL yields of 11 bbls/mmcf raw gas (3) Natural gas prices and costs escalated at 2%. Average C3+ Avg NGL price of $63.44/bbl escalated at 2%

AECO Gas Price $/mcf (3)

Lower Montney at 11 bbls/mmcf C3+(2)

Budget type curve 6.9 mmcf/d. Lower Montney wells have improved with frac design changes and are similar to Upper Montney wells mmcf/d IP30 / Bcf

SLIDE 24

EAST GLACIER CONTAINS HIGHER MIDDLE MONTNEY LIQUID CONTENT

30 bbl/mmcf 10 bbl/mmcf vertical well

Results have commercialized Middle

Montney play

Future completion design changes

expected to further improve well performance

Local variations in Middle Montney

highlighting “sweet spots”

(1) Based on shallow cut liquids extraction process yields from well test data.

Middle Montney wells to date illustrate higher liquid content from west to east across Glacier 63 27 18 40 42 30 76 57 31 26 76

Record Well 100/12‐2‐76‐ 12w6 13 mmcf/d 42 bbl/mmcf

C3+ Liquids Yield bbl/mmcf

Glacier C5+ 57 deg API Follow‐up Well 100/8‐35‐76‐12w6 11.4 mmcf/d 47 bbl/mmcf

42 47

No Wells Drilled

SLIDE 25

IMPROVING LIQUIDS RICH MIDDLE MONTNEY WELL PERFORMANCE AT GLACIER

New Phase VI 12‐2 well started production at restricted rate of 9.5 mmcf/d. Currently restricted at 5 mmcf/d after 250 days @ 1,100psi

Middle Montney wells have sequentially demonstrated improved productivity as we optimize frac design. Recent wells exceeding Budget type curve

Data: updated to November, 2014

4.0 mmcf/d Budget Type Curve

SLIDE 26

STRONG EAST GLACIER MIDDLE MONTNEY WELL ECONOMICS

(1)

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

Current Budget Type Curve 4 mmcf/d IP 30 Continued frac design changes have shown improving rates in each subsequent MM program. mmcf/d IP30 / Bcf

(1) Management estimates. NPV 10% pre‐tax (2) Based on $6.4 million per well with 18 frac stages and C3+ NGL yields of 50 bbls/mmcf raw gas (3) Natural gas prices and costs escalated at 2%. Average C3+ Avg NGL price of $63.44/bbl escalated at 2%

(3)

SLIDE 27

ADVANTAGE SUMMARY: GROWING OUR MONTNEY AT GLACIER

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

Additional 52.25 net sections of new undeveloped Montney lands provides further

upside

Three Year Development Plan Grows Production to 245 mmcfe/d (40,830 boe/d)

190% CFPS, 100% PPS(2), 1.5x Total Debt to Forward Cash Flow(3)
Multi‐year Hedging program & low cost structure strengthens growth plan

Industry Leading Low Cost Producer with top decile cash margin Improving well performance further enhances economics in Upper, Middle & Lower Montney Financial strength to support capital program

(1) Based on Sproule’s March 31, 2013 Resource Assessment and Glacier 2P Reserve report as of December 31, 2013. See Appendix. (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.

SLIDE 28

APPENDIX

SLIDE 29

THREE YEAR FULLY FUNDED GLACIER GROWTH PLAN DETAILS:

100% PRODUCTION PER SHARE AND 190% CASH FLOW PER SHARE GROWTH

Development Plan (3) Phase VII Phase VIII Phase IX Q2’14 to Q1’15 Q2‘15 to Q1’16 Q2’16 to Q1’17 Current Estimates Estimates Production (mmcfe/d) 12 month average 135 174 209 End of Phase Target 183 205 245 Wells Upper & Lower 20 22 24 Liquids Rich, Middle Montney 13 9 11 Total 33 31 35 Capital ($ millions) $265 $255 $215 Commodity Prices (4) NYMEX ($US/mmbtu) $4.40 $4.10 $4.10 AECO ($/GJ) $4.10 $3.65 $3.55 WTI ($US/bbl) $92.50 $85.00 $80.50 Financial ($ millions) Funds from operations $165 $205 $240 Bank debt – peak (5) $265 $325 $290 Total debt – peak (5) $325 $375 $333 Bank debt/cash flow (5) 1.3 1.4 1.0 Total debt/cash flow (5) 1.6 1.6 1.1

(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 and 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. Production includes NGL’s increasing from 900 bbls/d to 1,500 bbls/d in Phases VIII and IX

SLIDE 30

SOLID UPPER & LOWER MONTNEY WELL RESULTS ACROSS GLACIER

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

Upper Montney - Strong well results throughout block show tremendous upside potential in future development locations. record well 21 mmcf/d record well

10 mmcf/d 15 mmcf/d 14 mmcf/d 19 mmcf/d 17 mmcf/d 15 mmcf/d 13 mmcf/d 12 mmcf/d 13 mmcf/d 12 mmcf/d 12 mmcf/d 11 mmcf/d 11 mmcf/d 11 mmcf/d 11 mmcf/d 10 mmcf/d 10 mmcf/d 13 mmcf/d Recent 4 well pad 39 mmcf/d 18 mmcf/d

Lower Montney – Recent wells with revised completions have markedly improved wells in West area. Advancing delineation to Northwest and East areas.

3 mmcf/d 11 mmcf/d 9 mmcf/d 7 mmcf/d 4 mmcf/d Recent Completions 12 mmcf/d 10 mmcf/d 4 mmcf/d 14 mmcf/d

record well 16 mmcf/d record well Denotes test rates (1)(2)

Recent 4 well pad 55 mmcf/d Recent 4 well pad 57 mmcf/d

SLIDE 31

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

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

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

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

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

Completion Study Area

SLIDE 32

GLACIER DRILLING ECONOMICS AND 2P RECOVERIES PER INTERVAL

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

AECO C natural gas price ($/mcf)(2) Upper Montney Layer 1(6) Lower Montney Layer 5(3) Middle Montney Liquids Rich Gas (East Glacier)(4) $3.00 $4.00 $5.00 $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 N/A N/A N/A $5.8 $7.9 $9.8 5 mmcf/d & 5 Bcf $1.4 $4.5 $7.6 $2.6 $5.5 $8.4 $8.5 $10.8 $12.9 6 mmcf/d & 6 Bcf $2.9 $6.5 $10.0 $4.3 $7.8 $10.6 $10.9 $13.5 $15.9 7 mmcf/d & 7 Bcf $4.3 $8.6 $11.9 $6.1 $9.7 $12.7 $13.2 $16.2 $18.8 8 mmcf/d & 8 Bcf $5.8 $10.3 $13.8 $7.8 $11.5 $14.8 N/A N/A N/A

(1) Management estimates (2) Natural gas prices and costs escalated at 2%. Average C3+ NGL price of $63.44/bbl escalated at 2% (3) Based on $5.8 million per well with 18 frac stages and NGL yields of 11 bbls/mmcf raw gas (4) Based on $6.4 million per well with 18 frac stages and NGL yields of 50 bbls/mmcf raw gas (5) Based on Sproule December 31, 2013 reserves report (6) Based on $5.5 million per well with 18 frac stages and NGL yields of 0 bbls/mmcf raw gas

($ millions unless otherwise indicated)

Glacier – 2P Recoveries per Interval(5)

# of Gross Hz Wells 2P Recovery (bcf/well) Interval Developed Undeveloped Total Developed Undeveloped YE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE 2013

1 UM 73 83 174 169 247 252 4.3 4.4 4.7 5.4 2 MM 5 8 16 38 21 46 2.7 3.9 4.0 4.2 3 MM 1 4 19 1 23 2.5 2.7 0.0 3.1 4 MM 0.0 0.0 0.0 0.0 5 LM 15 22 76 72 91 94 2.9 3.8 5.0 5.1 Total 94 117 266 298 360 415

SLIDE 33

GLACIER MARCH 31, 2013 CONTINGENT AND PROSPECTIVE RESOURCE ASSESSMENT

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

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

SLIDE 34

GLACIER CONTINGENT AND PROSPECTIVE RESOURCE ASSESSMENT

(1) See Appendix 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.

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

SLIDE 35

GLACIER CONTINGENT AND PROSPECTIVE RESOURCE ASSESSMENT

2C (Best Estimate) Contingent Resources Interval Gross Number of Hz Well Locations Gross 2C Recoverable Resources per Location (Raw – Bcf per Well) Net Present Values Before Income Taxes ($ millions) 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
ver 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.

SLIDE 36

GLACIER CONTINGENT AND 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 and 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
btained 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.

SLIDE 37

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

r 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.

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ADVISORY

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; 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; 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 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

f 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.

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ADVISORY

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 27, 2014 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, total debt to cash flow ratio, and convertible debenture face value outstanding 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. Total debt to cash flow ratio is calculated as indebtedness under Advantage's credit facilities plus working capital deficit divided by funds from operations. 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.

SLIDE 40

ADVISORY

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

pportunities 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.

SLIDE 41

ADVANTAGE CONTACT INFORMATION

Investor Relations

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

Advantage Oil & Gas Ltd.

Suite 300, 440 – 2nd Avenue SW Calgary, Alberta T2P 5E9 Main: 403.718.8000 Facsimile: 403.718.8332

Advantage 100% W.I. Glacier Gas Plant

Andy Mah, P.Eng.

Director, President & Chief Executive Officer

Craig Blackwood, C.A.

VP Finance & Chief Financial Officer