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

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Low Risk Glacier Montney Development, Strong Balance Sheet & Hedging Program Supports Profitable & Sustainable Growth Investor Presentation TSX / NYSE: AAV October 2015 ADVANTAGE AT A GLANCE TSX, NYSE: AAV TSX 52-week trading

SLIDE 1

“Low Risk Glacier Montney Development, Strong Balance Sheet & Hedging Program Supports Profitable & Sustainable Growth”

TSX / NYSE: AAV Investor Presentation

October 2015

SLIDE 2

ADVANTAGE AT A GLANCE TSX, NYSE: AAV

View of Glacier Plant Process Train – approximately 1000 feet long

TSX 52-week trading range $4.51-$8.34 Shares Outstanding (basic) 170.7 million Current production 180 mmcfe/d (30,000 boe/d) Q3 Production estimate (1) 147 mmcfe/d (24,500 boe/d) Market Capitalization @ October 5, 2015 $1.3 billion Bank Debt @ June 30, 2015 (38% undrawn on $450 million Credit Facility) $277 million Total Debt @ June 30, 2015 (including working capital deficit) $293 million

(1) Based on AAV field production estimate

SLIDE 3

POSITIONED FOR PROFITABLE & SUSTAINABLE GAS GROWTH

2015-2017 Development Plan 22% Average Annual Production Growth 245 mmcfe/d in 2017 (40,830 boe/d)

Industry Leading Low Cost Producer

$0.89/mcfe total cash costs 26 Employees

Strong Balance Sheet

1.6x D/CF Average 2015 thru 2017 @$3.00 Cdn/GJ

Attractive Hedging Program

63% Hedged @$3.82 Cdn/mcf 2015 52% Hedged @$3.62 Cdn/mcf 2016 16% Hedged @$3.37 Cdn/mcf 2017

Low Risk Development

No new wells required to achieve 2016 production ramp 60% average ROR well economics

World Class Glacier Montney Asset

>1000 future drill locations

SLIDE 4

WORLD CLASS MONTNEY ASSET WITH INDUSTRY LEADING LOW COSTS & CAPITAL EFFICIENCIES

Glacier

300 meters thick Natural gas and liquids resource Strong economics at current commodity prices

Glacier Montney Siltstone Core Montney Thin Section Photo

SLIDE 5

GLACIER DEVELOPMENT WITH ADDITIONAL MONTNEY LANDS PROVIDES FUTURE UPSIDE

Glacier 81 net sections Wembley Valhalla

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

Current development at Glacier including

dry and liquids rich gas drilling

Glacier future drilling inventory >1,000

locations

New Montney lands at Valhalla,

Wembley & Progress contain multiple layers and requires delineation

Total 137 net Montney sections (87,584

net acres)

Progress

47.25 net Montney sections acquired 2013

SLIDE 6

“PENTASTACK” DEVELOPMENT WITH DECADES OF DRILLING INVENTORY AT GLACIER

(1) Management Estimates (2) Based on Sproule December 31, 2014 Glacier Reserves Report (3) Based on shallow cut liquids extraction process. Represents average liquid yield across Glacier. C5+ average 45% of liquid yield.

# Wells Drilled Production Since C3+ (3) Liquids (bbls/mmcf)

UM 104 2008 Dry MM 22 2012 50 LM 36 2008 11

Capable of maintaining 245 mmcfe/d (40,830 boe/d) for >50 years(1)
>1,000 Future Drill Locations at Glacier support future growth(1)
292 undeveloped locations booked in 2P reserves Year End 2014(2)

SLIDE 7

GLACIER WELL ECONOMICS(1) – STRONG RETURNS @ CURRENT COMMODITY PRICES

7 Upper Montney Lower Montney Middle Montney 50 bbls/mmcf C3+, 45% C5+ %

% % % %

% %

IP30 Bcf Well Cost (DC&E) mmcf/d $million

Type Curve & Cost Lower Well Cost Higher IP & EUR Case Type Curve & Cost Lower Well Cost Higher IP & EUR Case Type Curve & Cost Lower Well Cost Higher IP & EUR Case

(1) Assumptions:

Management Estimates of IP30, 2P EUR & Costs
Cdn Aeco $2.84/GJ
Cdn $28/bbl blended C3+ price based on $50 U.S./bbl

WTI Advantage achieved 16% cost reduction to average $4.6 million DC & E on its last 11 UM wells

SLIDE 8

INDUSTRY LEADING LOW COST STRUCTURE ENHANCES ECONOMIC RETURN…

$0.00 $5.00 $10.00 $15.00 $20.00 $25.00 $30.00 $0.00 $5.00 $10.00 $15.00 $20.00 $25.00 Q2/15 Cash Flow per BOE Q2/15 Cash Costs per BOE Gas Weighted Q2/15 Cash Flow per BOE vs. Cash Costs per BOE Notes: (1) Source: Peters & Co. Limited (2) Gas Weighted: >50% current production is natural gas. Median of $14.25 Median of $14.26

AAV

Lower Costs & Higher Netbacks AAV - Industry leading low cost structure

Source: FirstEnergy Capital Corp. Note: we do not consider royalties as a controllable cash cost, however have included for illustrative purposes * – Restricted; R – under Review 1 – FD&A for Glacier standalone reserves, Allocated $0.25/mcfe in transportation costs as a production expense instead of as a discount to reported wellhead price; 2 – 2013 FD&A figure (2014 figure n/a):

SLIDE 9

Glacier Operating Netback

Q2 2015 ($/mcfe) Illustrative $2.50/mcfe

Revenue (Realized Price)

$3.29 (1) $2.50

Royalties

($0.11) ($0.13)

Operating Costs

($0.37) ($0.35)

Operating Netback

$2.81 $2.02

Recycle Ratio at 2014 2P F&D $1.03/mcfe (2)

2.7x 2.0x

G&A

($0.19) ($0.17)

Finance Expense & other

($0.21) ($0.19)

Cash Flow Netback

$2.41 or $14.55/boe $1.66 or $9.96/boe

(1) Revenue includes adjustments for transportation costs and heat value and hedging gains of $0.76/mcf. (2) F&D includes Future Development Capital

…AND GENERATES STRONG RECYCLE RATIO’S

2014 Capital Efficiency ~$15,000/boe/d

SLIDE 10

2013 SLICKWATER WELLS OUTPERFORM LONG TERM PRODUCTION EXPECTATIONS. 2014 WELLS JUST STARTED…

Production from 21 slick water completed Upper & Lower Montney wells from 2013 program are

utperforming longer term budget decline trend

Data: updated to July 2015

Budget Type Curve (IP30 6.9 mmcf/d & 6.9 Bcf)

3 Wells initially brought on-stream in July 2015 to increase production from 130 to 180 mmcfe/d (one 2013 LM & two 2014 UM). Wells are normally restricted to ≤10 mmcf/d for frac sand flowback control during initial 6 months

SLIDE 11

IMPROVING LIQUIDS RICH MIDDLE MONTNEY WELL PERFORMANCE AT GLACIER

12-2 well (2013) cumulative production >2 Bcfe after 400 days (restricted) with current flowing pressure 1,000 psi. 10 New MM wells Based on 2014 production test rates could exceed historical type curve

Data: updated to July, 2015 Middle Montney Budget Type Curve (IP30 4.0 mmcf/d & 4.0 Bcf)

SLIDE 12 (1) Based on C3+ shallow cut liquids extraction process yields from well test data.

Middle Montney wells to date illustrate higher liquid content(1) from west to east across Glacier East Glacier 30 to 83 bbls/mmcf C3+

2013 Well 12-2 13 mmcf/d 42 bbls/mmcf

Glacier C5+ 57 deg API

2014 Well 8-35 18 mmcf/d 47 bbls/mmcf

22 9 6.6 >9 50 45%

MM wells (hz & vert) drilled since 2011 across Glacier Wells completed & standing from 2014 program (current) MMCF/D average final test rate from ten completed 2014 wells MMCF/D demonstrated by 3

f the 10 wells

BBLS/MMCF of C3+ liquids yield average East Glacier Average condensate in liquid yield

West Glacier 18 to 30 bbls/mmcf C3+

2014 MIDDLE MONTNEY PROGRAM FOCUSED ON HIGHER LIQUID CONTENT IN EAST GLACIER

2014 Well 13-17 9.8 mmcf/d 54 bbls/mmcf 2014 Well 12-20 9.3 mmcf/d 43 bbls/mmcf 2014 Well 8-9 5.7 mmcf/d 83 bbls/mmcf

2014 Middle Montney wells completed & standing 2014 Middle Montney wells waiting on completion

SLIDE 13

LOW RISK DEVELOPMENT WITH A WELL DEFINED GROWTH PLAN

SLIDE 14

33 19 130+ 11 205

Wells Drilled in 2014 program Wells Completed & Standing (current) MMCF/D IP30 from the 19 wells Wells Drilled, not completed MMCF/D April 2016 target attainable with no additional drilling

LARGE INVENTORY OF STANDING WELLS & PRODUCTION CAPABILITY

8 Lower Montney 13 Middle Montney 2014 Drilling Program Wells 12 Upper Montney

Only 3 Wells Utilized to Initially Increase Production from 130 to 180 mmcfe/d in July 2015

Note: Wells will be choked to ≤10 mmcf/d to manage frac sand flow back issues per AAV operating practices

9-35 UM (2014) 17 mmcf/d 5-3 UM (2014) 12 mmcf/d 2-18 LM (2013) 21 mmcf/d

SLIDE 15

Commissioning of Inlet & New Compressors Began July 17, 2015, tested up to 200 mmcfe/d
Commissioning of two 125 mmcf/d Liquid Extraction Units in September & October 2015
Plant Process Capacity 250 mmcf/d after completion of testing October 2015 (provides 70

mmcfe/d of spare plant capacity for future growth)

Only $15 to $30 million of facilities and pipeline capital required in 2016 & 2017 per Plan
100% ownership of the Glacier plant provides flexibility to control the amount of dry or

liquids rich gas being processed to optimize netbacks

EXPANDED GLACIER GAS PLANT PROVIDES SPARE CAPACITY FOR FUTURE GROWTH & OPERATIONAL FLEXIBILITY

SLIDE 16 Created in AccuMap™, a product of IHS

16 100% Owned 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 Additional 35 mmcf/d TCPL Firm Service for 2018 Confirmed

GROWTH BEYOND 2017 CAN BE ACCOMMODATED ON EXISTING PLANT SITE

Expansion to 250 MMcf/d Dry and Liquid Gas Processing Capability

TCPL Sales Meter Stations 400 mmcf/d capacity by April 2016

Advantage Gas Plant

TCPL NW ALBERTA Main Sales Gas Line

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

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

Pembina NGL Line Alliance Sales Gas Line

New Refrigeration & Compression

Potential Area Expansion to 500 MMcf/d Capacity Potential Area Expansion to 750 MMcf/d Capacity

SLIDE 17

PLAN TARGETS 22% PRODUCTION GROWTH (CAGR) THROUGH 2017

Plan Summary 2015 thru 2017 (1)

245 mmcfe/d (40,830 boe/d) in 2017 $545 million Capital Expenditures

(5% service cost reduction included in 2015 only)

70 New Montney wells

(10 drilled Q1 2015)

$3.00/GJ AECO Cdn average Plan price 1.6x Average Total Debt to Cash Flow 2015 63% @$3.82/Mcf Hedging (2) 2016 52% @$3.62/Mcf 2017 16% @$3.37/Mcf

(1) See Plan details in Appendix page 22. 2015 Estimate

updated August 6, 2015.

(2) AECO Cdn $ (3) CAGR – compound annual growth rate over the period (CAGR) (3)

SLIDE 18

GROWTH PLAN LEADS TO SIGNIFICANT FREE CASH FLOW IN EARLY 2017

Cash flow significantly exceeds maintenance capital each year. Maintenance capital levels can be achieved at ≈$1.50/mcfe cash flow netback each year to keep production flat 245 mmcfe/d @ $3.50/gj generates $130 million free annual cash flow

(1) Assumed natural gas prices at Aeco Cdn $/GJ in Growth Plan. 2015 Estimate updated on August 6, 2015. (2) Assumes 7 mmcf/d /7 Bcf for Upper & Lower Montney wells and 4 mmcf/d /4 Bcf for Middle Montney wells

Illustrative

SLIDE 19

2015 THROUGH 2017 – GROWTH PLAN PRICE SENSITIVITY

Downside gas price mitigation while retaining torque to upside

2015 Estimate updated on August 6, 2015

SLIDE 20

Clear Vision for Growth Financial Strength Proven Expertise

SLIDE 21

APPENDIX

SLIDE 22

FULLY FUNDED GLACIER GROWTH PLAN DETAILS:

22% ANNUAL AVERAGE PRODUCTION GROWTH FOR 2015 TO 2017

(2)

(CAGR) (2) CAGR – compound annual growth rate over period

SLIDE 23

EXCEPTIONAL UPPER MONTNEY WELL ECONOMICS – NO COST REDUCTIONS ASSUMED

(1)

(1) Management estimates. NPV 10% pre-tax (2) Based on $5.5 million per well with 18 frac stages (no service cost reduction estimate included) (3) Natural gas prices and costs escalated at 2%. Average C3+ NGL price of $52.39/bbl escalated at 2%

Upper Montney Dry Gas (2)

Recent average Upper Montney well performance exceeding 7 mmcf/d IP30

(3)

SLIDE 24

EXCEPTIONAL LOWER MONTNEY WELL ECONOMICS – NO COST REDUCTIONS ASSUMED

(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 (no service cost reduction estimate included) (3) Natural gas prices and costs escalated at 2%. Average C3+ Avg NGL price of $52.39/bbl escalated at 2%

AECO Gas Price $/mcf (3)

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

Recent Lower Montney wells are at or above 7 mmcf/d IP 30

SLIDE 25

STRONG EAST GLACIER MIDDLE MONTNEY WELL ECONOMICS – NO COST REDUCTIONS ASSUMED

(1)

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

Recent wells are exceeding Budget Type Curve of 4 mmcf/d IP 30

(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 (no service cost reduction estimate included) (3) Natural gas prices and costs escalated at 2%. Average C3+ Avg NGL price of $52.39/bbl escalated at 2%

(3)

SLIDE 26

HIGHLY EFFICIENT GLACIER RESERVE ADDITIONS & RECYCLE RATIO

0.00 0.50 1.00 1.50 2.00 2.50 2008YE 2009YE 2010YE 2011YE 2012YE 2013YE 2014YE

2P F&D Cost ($/Mcfe)

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

$1.03 3yr Avg F&D (1) 2.9x 3yr Avg Recycle Ratio (2)

(1) Based on 2P Reserves including changes in Future Development Capital (2) Based on glacier operating netbacks. Recycle Ratio = Operating Netbacks

(2P) 2P F&D Cost

Mcfe ($1.03) 2P F&D Cost ($0.89) Total Cash Cost 2014 ($1.92) $4.23

Realized Sales Price 2014

+$2.31

per Mcfe

Full Cycle Return

SLIDE 27

GLACIER DRILLING ECONOMICS AND 2P RECOVERIES PER INTERVAL – NO COST REDUCTIONS ASSUMED

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 $3.5 $5.6 $7.3 5 mmcf/d & 5 Bcf $1.5 $4.5 $7.5 $2.0 $4.8 $7.6 $6.0 $8.6 $10.1 6 mmcf/d & 6 Bcf $3.0 $6.5 $10.0 $3.5 $6.9 $9.9 $8.5 $11.4 $12.5 7 mmcf/d & 7 Bcf $4.4 $8.6 $11.9 $5.2 $9.1 $11.8 $10.9 $13.9 $15.0 8 mmcf/d & 8 Bcf $5.9 $10.4 $13.8 $6.8 $10.8 $13.8 $13.0 $16.2 $17.3 9 mmcf/d & 9 Bcf $7.3 $11.9 $15.7 $8.4 $12.5 $15.7 N/A N/A N/A

(1) Management estimates (2) Natural gas prices and costs escalated at 2%. Average C3+ NGL price of $52.39/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, 2014 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)

Interval # of Gross HZ Wells 2P Recovery [bcf/well] Developed Undeveloped TOTAL Developed Undeveloped TOTAL YE 2012 YE 2013 YE 2014 YE 2012 YE 2013 YE 2014 YE 2012 YE 2013 YE 2014 YE 2012 YE 2013 YE 2014 YE 2012 YE 2013 YE 2014 YE 2012 YE 2013 YE 2014 1 UM 73 83 99 174 169 157 247 252 256 4.3 4.4 4.5 4.7 5.4 5.3 4.6 5.1 5.0 2 MM 5 6 7 16 38 42 21 44 49 2.7 3.9 4.6 4.0 4.2 4.6 3.7 4.2 4.6 3 MM 1 4 6 19 20 1 23 26 2.5 2.7 3.3 0.0 3.1 3.2 2.5 3.0 3.2 4 MM 1 1 2 0.0 0.0 2.5 0.0 0.0 4.0 0.0 0.0 3.3 5 LM 15 22 27 76 72 72 91 94 99 2.9 3.8 5.4 5.0 5.1 5.9 4.7 4.8 5.8 Total 94 115 140 266 298 292 360 413 432

SLIDE 28

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 29

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 30

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 2015 to 2017 development plan including expected production growth, estimate debt to cash flow ratio, expected capital expenditures, expected wells to be drilled, expected operating costs, expected economics, expected resulting free cash flow and expected number of drilling locations and inventory; expected number of wells required to be drilled to achieve certain levels of production; expected details and timing of the Glacier gas plant expansion; expected well economics associated with certain type curves; expected future production levels; expected maintenance and outages on the TransCanada pipeline; expected effect of restrictions and outages on the TransCanada pipeline on future production levels; expected sensitivities in cash flow per share and debt to cash flow levels to changes in commodity prices; expected effect of refinement of drilling and completion technique; Advantage's guidance in respect of anticipated production levels, exit production rates, royalty rates, operating costs 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 or royalties; 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

ccurrence 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;

ur 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. 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 25, 2015 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

SLIDE 31

ADVISORY

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

ut in respect of all wells. Accordingly, the Corporation cautions that the test results should be considered to be preliminary.

Certain type curves presented herein represent estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. The 7 mmcf/d IP (which represents the average 30 day initial production rate) & 7 Bcf (which represents the ultimate volumes expected to be recovered from the wells over the life of the well based on the type curve) Upper and Lower Montney type curve and the 4 mmcf/d IP and 4 Bcf Middle Montney type curve are management generated type curves based on a combination of historical performance of

lder wells and management's expectation of what might be achieved from future wells. The type curves represent what management thinks an average well will achieve. Individual wells may

be higher or lower but over a larger number of wells management expects the average to come out to the type curve. Over time type curves can and will change based on achieving more production history on older wells or more recent completion information on newer wells. Other type curves presented herein, including the 9 mmcf/d IP & 9 Bcf Upper and Lower Montney type curve and the 6 mmcf/d IP & 6 Bcf Middle Montney type, curve have been provided to demonstrate the economics associated with wells that could potentially have that type of productivity and recovery but do not represent management estimates of how such wells will actually perform. This presentation discloses certain future drilling locations that have not been booked in Advantage's most recent independent reserves evaluation as prepared by Sproule as of December 31,

2014. Such drilling locations are internal estimates based on Advantage's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry

practice and internal review. Such locations do not have attributed reserves or resources. Such drilling locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Advantage will drill all drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other

factors. While certain of the drilling locations have been derisked by drilling existing wells in relative close proximity to such drilling locations, other drilling locations are farther away from

existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. 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 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

f 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

perating activities.

SLIDE 32

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 NGLs natural gas liquids 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 33

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

Neil Bokenfohr, P.Eng.

Senior Vice President