Record Q Production & Three Year Plan to Accelerate Pipestone Condensate Development

Record Q3 2018 Production & Three Year Plan to Accelerate Pipestone Condensate Development Investor Presentation TSX: AAV December 2018

ADVANTAGE AT A GLANCE TSX 52 week trading range $1.82 $5.73 Shares Outstanding (basic) 186 million Market Capitalization $0.4 billion Enterprise Value $0.6 billion Estimated Dec. 31, 2018 (1) Bank Debt (68% drawn on credit facility) $245 million Total Debt (includes working capital) (2) $250 million (@ AECO $1.57/GJ, WTI $67 U.S./bbl) 2019 Guidance (1) Total Production 43,500 to 46,500 boe/d Liquids Production (100% Increase) 3,100 bbls/d Exit Liquids Production 4,500 bbls/d Glacier Advantage Montney Assets Progress Valhalla Pipestone/ Wembley Notes: (1) Forward looking information. Refer to three year development plan (page 5) and Advisory for material assumptions and risk factors. (2) Non GAAP measure which may not be comparable to similar non GAAP measures used by other entities. Refer to Advisory. Advantage holds 128,000 net acres (200 net sections) in the condensate rich Montney Glacier/Pipestone fairway 2

2019 2021 DEVELOPMENT PLAN FURTHER STRENGTHENS BUSINESS MODEL Solid Today Solid Tomorrow Free Cash Generating Asset Ultra low Costs Financial Strength & Discipline World Class Montney Resource Reinvest to Diversify & Enhance Free Cash Generation Maintain & Strengthen Netbacks Preserve & Enhance Investment Returns Condensate/Light Oil & Natural Gas Capital Allocation Flexibility 3

2019 2021 DEVELOPMENT PLAN INTERNALLY FUNDED GROWTH (1) Progress 6 miles Condensate & Light Oil Focused Fully funded from cash provided by operating activities & credit facilities $690 million capital investment Glacier The Foundation Valhalla Drill 96 Montney wells: o 42 Pipestone/Wembley o 14 Valhalla o 36 Glacier o 4 Progress Glacier/Pipestone Liquids Development The Next Phase Pipestone/ Wembley Utilize 3 rd party gas processing for initial Pipestone/Wembley development Utilize spare processing capacity at Glacier gas plant for growth at Valhalla, Glacier, Progress & 3 rd party processing income Notes: (1) Forward looking information. Refer to three year development plan (page 5) and Advisory for material assumptions and risk factors. Build liquids handling hub at Pipestone/Wembley 4

2019 2021 DEVELOPMENT PLAN (1) Guidance and Estimates (2)(3) 2019 Guidance 2020 Estimate 2021 Estimate Average production (boe/day) 43,500 46,500 47,850 52,300 Gas production (mmcf/d) 244 to 260 245 246 Liquids production (bbls/d) 2,900 to 3,200 7,000 11,370 % Liquids / % Condensate/light oil 7% / 75% 15% / 80% 22% / 82% Royalties ($/boe) and Royalty Rate (%) $0.65 (4%) $0.90 (4%) $1.15 (4.5%) Operating Cost ($/boe) $2.00 $2.45 $2.65 Transportation Cost ($/boe) $3.35 $3.45 $3.40 G&A/Finance Cost ($/boe) $1.35 $1.35 $1.25 Cash Used in Investing Activities (millions) $210 to $240 $225 $240 Net Capital Expenditures (4)(5) (millions) $210 to $240 $225 $240 Capital Efficiency (4) ($/boe/d) $14,400 $13,700 $12,700 Cash Provided by Operating Activities (millions) $185 $235 $315 Adjusted Funds Flow (4)(5) (millions) $185 $235 $315 per boe $11.28 $13.38 $16.56 per share $0.99 $1.25 $1.67 Total debt to adjusted funds flow (4) 1.6 1.2 0.6 WTI (US$/bbl) (2) $66.79 $66.37 $63.29 Advantage C5+/Light oil differential to WTI (CAD$/bbl) (2) $(7.00) $(6.00) $(6.00) CAD/USD exchange rate (2) $0.77 $0.77 $0.77 AECO (C$/GJ) (2) $1.68 $1.61 $1.78 Notes: 1) Forward looking information. Refer to Advisory for cautionary statements regarding Advantage s budget and three year development plan including material assumptions and risk factors. 2) Based on assumptions and strip pricing effective as at October 23, 2018 as set forth above. 3) Management estimates representing mid point of range. 4) Non GAAP Measure which may not be comparable to similar non GAAP measures used by other entities. Refer to Advisory. 5) Net Capital Expenditures is the same as Cash Used in Investing Activities and Adjusted Funds Flow is the same as Cash Provided by Operating Activities as no change in non cash working capital is assumed between years and other differences are immaterial. 5

STRENGTHENING FOUNDATION 2021 HIGHLIGHTS (1) 700% Increase in Liquids Production (3) 14,000 Bbls/d 2021 Exit Liquids Rate 25% Increase in Total Annual Production to 52,330 boe/d (3) 82% Premium C5+/Light Oil content of liquids stream 22% Liquids % of Total Production 94% Increase in Adjusted Funds Flow (2) per share to $1.67 (3) 58% Increase in Adjusted Funds Flow (2) per boe to $16.56 maintaining low costs (3) 0.6x Total Debt to Adjusted Funds Flow (2) ratio 15% AECO revenueexposure Notes: (1) Forward looking information. Refer to three year development plan (page 5) and Advisory for material assumptions and risk factors. (2) Non GAAP measure which may not be comparable to similar non GAAP measures used by other entities. Refer to Advisory. (3) Comparisons are relative to 2018 annual average estimates. 6

THREE AR DEVELOPMENT PLAN STRENGTHENING FOUNDATION (1) G&A and Finance Transport Operating Royalties 45,000 7% 15% $1.35 $3.35 $2.00 Total Production (boe/d) 6% 47,850 Costs ($/boe) 9% $1.35 $1.25 $3.45 $3.00 $2.45 $0.65 $0.90 52,300 22% 2019E 2020E 2021E Gas Liquids % of Total $2.65 $1.15 2019E 2020E 2021E 3,100 75% Liquids Production and Composition (bbls/d) 11,370 125% 7,000 80% 62% Glacier Provides $175 million Cash for Reinvestment Overall Plan adjusted funds flow exceeds capital Average capital efficiency ~$13,600/boe/d (2) 81% 2019E 2020E 2021E Three Year Development Plan Notes: (1) Forward looking information. Refer to three year development plan (page 5)and Advisory for material assumptions and risk factors. (2) Non GAAP measure which may not be comparable to similar non GAAP measures used by other entities. Refer to Advisory. 14,000 bbls/d Exit C5+ 7

THREE AR DEVELOPMENT PLAN ADJUSTED FUNDS FLOW (1) $185 Adjusted Funds Flow (2) and Net Capital Expenditures (2) ($ millions) $315 $225 $235 $225 $240 Adjusted Funds Flow (2) per share 34% $1.67 26% $1.25 $0.99 2019E 2020E 2021E Adjusted Funds Flow Net Capital Expenditures Adjusted Funds Flow (2) per boe 24% $16.56 19% $13.38 $11.28 2019E 2020E 2021E 1.6 Total Debt to Adjusted Funds Flow (2) 1.2 0.6 2019E 2020E 2021E 2019E 2020E 2021E Notes: (1) Forward looking information. Refer to three year development plan (page 5)and Advisory for material assumptions and risk factors. (2) Non GAAP measure which may not be comparable to similar non GAAP measures used by other entities. Refer to Advisory. 8

FINANCIALLY ROBUST AT LOW PRICES (1) GAS PRICE SENSITIVITY (3) OIL PRICE SENSITIVITY (3) AECO $1.50/mcf AECO $1.75/mcf AECO $2.00/mcf $1.70 Adjusted Funds Flow (2) per share $1.64 $1.56 $1.32 $1.25 $1.18 $1.01 $0.97 $0.93 2019 2020 2021 WTI US$55.00/bbl WTI US$65.00/bbl WTI US$75.00/bbl $1.96 Adjusted Funds Flow (2) per share $1.71 $1.38 $1.46 $1.04 $1.23 $0.98 $1.08 $0.92 2019 2020 2021 1.7 1.6 1.5 1.4 1.2 Total Debt to Adjusted Funds Flow (2) 1.8 1.6 1.4 1.6 1.2 Total Debt to Adjusted Funds Flow (2) 1.0 0.8 0.7 0.5 0.9 1.0 0.6 0.3 2019 2020 2021 2019 2020 2021 Notes: (1) Forward looking information. Refer to three year development plan (page 5)and Advisory for material assumptions and risk factors. (2) Non GAAP measure which may not be comparable to similar non GAAP measures used by other entities. Refer to Advisory. (3) Flat pricing assuming an estimated C 5 +/Light Oil differential to WTI of $7.00/bbl Cdn 2019, $6.00/bbl Cdn 2020 & 2021 and Fx $0.77 Cdn/US. 9

NET CAPITAL EXPENDITURES FOCUSED ON DRILLING (1)(2) Progress 7% 2019 Capital By Area Other 6% $225 million 2019 2021 Total Capital By Area Progress 4% Other 6% $690 million Wembley 24% Glacier 49% Wembley 47% Glacier 32% Valhalla 14% 2019 Capital Breakdown Other $13 Facility & Tie in $58 Drill & Complete $154 68% Allocated to Drilling & Completions (26 wells) 2019 2021 Total Capital Breakdown Other $43 Facility & Tie in $171 Drill & Complete $476 Valhalla 11% 69% Allocated to Drilling & Completions (96 wells) Notes: (1) Forward looking information. Refer to three year development plan (page 5) and Advisory for material assumptions and risk factors. (2) Non GAAP measure which may not be comparable to similar non GAAP measures used by other entities. Refer to Advisory. 10

REVENUE & MARKET DIVERSIFICATION, HEDGING AND TRANSPORTATION (1) 25% 8% 13% 30% Revenue Diversification 48% 15% 17% 23% 21% 58% 14% 13% 15% Dec 19 Dec 20 Dec 21 Liquids Midwest US Dawn Fixed price AECO Market Diversification Benefits Diversifies Advantage s sales portfolio Enhances commercial terms to optimize netbacks & increases commercial flexibility 140 120 100 80 60 40 20 $3.45 Current Hedging Transactions (MMcf/d) $2.75 $2.75 $2.93 $3.01 $3.09 $2.34 $1.72 $2.84 $2.83 $2.00 $2.00 $2.21 Q1 18 Q2 18 Q3 18 Q4 18 Q1 19 Q2 19 Q3 19 Q4 19 AECO ($Cdn/Mcf) Dawn ($US/Mmbtu) % of Production Hedged Hedging Strategy Actively hedge future commodity prices to ensure cash expectations and preserve development project economics Transportation Sufficient current and future transportation capacity available to meet requirements of 2019 2021 development plan Actively manage contracted transportation capacity to minimize unutilized demand charges 11 Notes: (1) Forward looking information. Refer to three year development plan (page 5)and Advisory for material assumptions and risk factors. $2.87 $2.87 $2.87 60% 50% 40% 30% 20% 10% 0%

OPERATIONS OVERVIEW SHIFTING TO MIDDLE MONTNEY LIQUIDS Glacier Progress Deep Liquids Rich Inventory (1)(2)(3) Booked Unbooked Upside Undeveloped TOTAL future location inventory ~1,200 to 1,400 Valhalla 62 613 Liquids rich Middle Montney Pipestone/ Wembley 214 123 Total of ~200 net sections (128,000 net acres) Middle Montney is liquids rich throughout (25 to 280 bbls/mmcf) Only 50 liquids rich wells drilled to date 5% of inventory 100% Ownership of Glacier gas plant 400 mmcf/d capacity, 6,800 bbls/d liquids handling 200 <25 bbls/mmcf 25 100 bbls/mmcf >100 bbls/mmcf (1) Management Estimates. Refer to Advisory. (2) Based on Sproule December 31, 2017 Reserves Report. (3) C 3 + shallow cut recoveries. 12

PIPESTONE/WEMBLEY LIQUIDS RICH DEVELOPMENT Pipestone BBI CNQ ECA Kelt The premium condensate play in Canada 31 net sections Recent M&A land values exceeding $4.5 million per section 42 wells planned from 2019 to 2021 (4) Inventory of >200 wells in primary development zones (4) AAV 1,312 boe/d 62% liquids Half cycle Economics (1)(2) (AECO Cdn $2.00/mcf & $US 60/bbl WTI) Rate of Return % Payout Years Breakeven (3) 160% 200% 0.8 1.0 <$1.00/mcf Pipestone Oil Corp Blackbird Energy Area Well Performance Average Initial Production (boe/d) Average over 1 Year Production (boe/d) TOTAL EUR (boe) Oil 581 303 361,000 Gas 409 260 384,000 NGL 160 101 150,000 Total 1,150 664 895,000 Liquid Yield Bbls/mmcf 300 260 225 (1) Management estimates. (2) Rate of Return is the percentage return earned on the capital invested in a well during the well s producing life assuming initial capital of $5.3 million per well DCE+T (drilling, completion, equipping and tie in) with natural gas and NGL prices and costs escalated at 1.5% annually. (3) Breakeven based on NPV10 pre tax equal to zero and calculated AECO Cdn price. (4) There are no proved or additional probable undeveloped locations booked by our independent reserve evaluator in this area. All locations are unbooked estimates by Management. Refer to Appendix and Advisory. 13

VALHALLA LIQUIDS DEVELOPMENT ADVANCING Upper Montney Middle Montney 2 Middle Montney 3 Middle Montney 4 Lower Montney AAV Liquids Handling Hub Competitor well IP30 1,400 boe/d 68% liquids (1) Management estimates. (2) Rate of Return is the percentage return earned on the capital invested in a well during the well s producing life assuming initial capital of $4.8 million per well DCE+T (drilling, completion, equipping and tie in) with natural gas and NGL prices and costs escalated at 1.5% annually. (3) Breakeven based on NPV10 pre tax equal to zero and calculated AECO Cdn price. (4) There are 12 proved and 1 additional probable undeveloped locations booked by our independent reserve evaluator in this area. All remaining locations are unbooked estimates by Management. Refer to Appendix and Advisory. Industry results in Middle Montney have proven ultra rich condensate on offsetting lands Advantage to target same interval Q1 2019 Extension of Wembley reservoir 42 net sections 200 well inventory and growing (4) Pipeline connected to Advantage Glacier gas plant through new AAV liquids hub Half cycle Economics (1)(2) (AECO Cdn $2.00/mcf & $US 60/bbl WTI) Rate of Return % PayoutYears Breakeven (3) (AECO Cdn $) 40% 90% 1.4 2.2 <$1.00/mcf 14

LIQUIDS RICH MIDDLE MONTNEY AT GLACIER STEPPING UP Only 41 Middle Montney drills to date Early development focussed on upper and lower Montney Liquids range from 25 80 bbls/mmcf in Middle Montney 90 net sections 750 well inventory (4), including 480 liquids rich Low costs = high netbacks IP30 well liquids rates up to 400 bbls/d Half cycle Economics (1)(2) (AECO Cdn $2.00/mcf & $US 60/bbl WTI) Rate of Return % PayoutYears Breakeven (3) (AECO Cdn $) Upper Montney Middle Montney 2 Middle Montney 3 Middle Montney 4 Lower Montney 40% 90% 1.4 2.2 <$1.00/mcf (1) Management estimates. (2) Rate of Return is the percentage return earned on the capital invested in a well during the well s producing life assuming initial capital of $4.8 million per well DCE+T (drilling, completion, equipping and tie in) with natural gas and NGL prices and costs escalated at 1.5% annually. (3) Breakeven based on NPV10 pre tax equal to zero and calculated AECO Cdn price. (4) There are 291 proved and 33 additional probable undeveloped locations booked by our independent reserve evaluator in this area. All remaining locations are unbooked estimates by Management. Refer to Appendix and Advisory. 15

STRATEGIC INFRASTRUCTURE CONTROL, FLEXIBLE PIPELINE ACCESS 100% Owned Glacier Gas Plant 400 mmcf/d Raw Gas + 6,800 bbls/d C3+ Liquids Extraction Advantage Gas Plant Alliance Sales Gas Line Liquids Handling Hub Pembina NGL Line NGTL Sales Gas Mainline Company Land Company Gas Plant TransCanada Pipeline Pembina Pipeline Advantage Pipeline Alliance Pipeline Keyera Pipestone Plant (2021) Tidewater Pipestone Plant (2019) Growth beyond 400 mmcf/d can be accommodated on existing plant site NGTL Natural Gas Firm Transportation Service in place Several new gas plants proposed in Pipestone/Wembley area competitive options available 3 rd Party processing capacity in H2 2019 to match Pipestone/Wembley growth profile Advantage s Wembley to Glacier planned pipeline routing work continuing. 16

Financial Discipline Operational Excellence Returns Focus

APPENDIX 18

GLACIER LOCATED IN THE HEART OF THE MONTNEY RESOURCE PLAY Montney Siltstone Comparison: 700 times more permeability 4x more formation thickness Very low clay content Liquids & Improved well efficiencies strong economics Up to 83 bbls/mmcf 19

CONTINUOUS IMPROVEMENT HAS LED TO EXCEPTIONAL EFFICIENCIES Production restrictions 20

MIDDLE MONTNEY PRODUCTION CONTINUES TO INCREASE 2018 6 wells Gen 6: Slickwater, OH Packers, Stage completions Avg 34 frac stages 2016 17 6 Wells Gen 5: Slickwater, OH Packers, Cased hole & Stage completions Avg 27 frac stages 2015+ Middle Montney wells with frac design changes including >20 frac stages & numerous mechanical systems to be evaluated 34 total Middle Montney wells on production across Glacier land block. 2015 13 wells Gen 4: Slickwater, OH Packers Avg 19 frac stages 2014 3 wells Gen 3: Slickwater, OH Packers Avg 15 frac stages 2013 4 wells Gen 2: Poly CO2, & Slickwater Plug and Perf Avg 13 frac stages 2012 2 wells Gen 1: Poly CO2, Sand Plugs, Avg 15 frac stages Note: Production plot affected by low number of producing wells >350 days and wells being choked. Middle Montney Budget Type Curve (IP30 5.0 mmcf/d & 5.0 Bcf) 21

GLACIER MONTNEY ASSIGNED 2P EUR PER WELL & INTERVAL Glacier 2P Recoveries per Interval (1) # of Gross HZ Wells 2P Recovery [bcf/well] Interval 2015 Developed Undeveloped Total Developed Undeveloped Total 2016 2017 2015 2016 2017 2015 2016 2017 2015 2016 2017 2015 2016 2017 2015 2016 2017 1 UM 100 103 111 148 141 133 248 244 244 4.7 4.9 5.1 5.5 5.9 5.8 5.2 5.4 5.5 2 MM 10 12 15 43 52 65 53 64 80 4.7 5.8 5.6 4.8 5.2 5.6 4.8 5.3 5.6 3 MM 7 8 10 23 25 35 30 33 45 4.6 4.5 4.4 4.2 4.1 4.4 4.3 4.2 4.4 4 MM 2 2 3 0 5 11 2 7 14 3.7 6.1 7.4 0.0 5.9 6.6 3.7 6.0 6.7 5 LM 34 43 51 83 84 81 117 127 132 5.6 7.1 7.7 5.9 6.4 6.5 5.8 6.6 6.9 Total 153 168 190 297 307 325 450 475 515 Interval 2015 # of Gross HZ Wells 2P Recovery [bcf/well] Developed Undeveloped Total Developed Undeveloped Total 2016 2017 2015 2016 Valhalla 2P Recoveries per Interval (1) 2017 2015 2016 2017 2015 2016 2017 2015 2016 2017 2015 2016 2017 1 UM 2 4 5 0 2 9 2.9 6.6 7.9 2.9 7.3 2 MM 1 2 5 0 1 7 4.4 4.3 4.1 4.4 4.2 3 MM 1 2 0 0 3 2.1 2.1 2.1 Total 0 3 7 0 0 12 0 3 19 (1) Based on Sproule 2017 year end reserve reports. Indicated raw gas volumes per well. Refer to Statement of Reserves Data and Other Oil and Gas Information in the Corporation s Annual Information Form dated March 5, 2018 which is available at www.sedar.com and www.advantageog.com. 22

ADVISORY Forward Looking Information and Statements The information in this presentation contains certain forward looking information and forward looking statements (collectively, "forward looking statements") within the meaning of applicable securities laws relating to the Corporation's plans and other aspects of its anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. These statements relate to future events or ourfuture intentions or performance. All statements other than statements of historical fact may be forward looking statements. The statements have been prepared by management to provide an outlook of the Corporation's activities and results and may not be appropriate for other purposes. Forward looking statements are often, but not always, identified by the use of words such as seek, anticipate, plan, continue, estimate, guidance, demonstrate, expect, may, can, will, project, predict, potential, target, intend, could, might, should, believe, would and similar expressions and include statements relating to, among other things, the Corporation's 2019 to 2021 Development Plan (the "Plan"), the Plan's development focus and the timing thereof, the expected sources of funding for the Plan; expected results and benefits to be derived from the Plan include, but are not limited to, increasing the anticipated amount of annual average liquids production, increasing C5+/light oil production mix and the expected amount of C5+/light oil production mix, diversifying the Corporation's revenue sources including the composition of natural gas and liquids, developing additional operational and infrastructure optionality and how this will be achieved; annual production average and the expected amount by which total annual average production will be increased by in 2019 to 2021; expected net capital expenditures for 2019 to 2021, including the expected focus and allocation of such expenditures; the expected adjusted funds flow per share and per boe in each of 2019 to 2021; expected year end total debt to adjusted funds flow ratios in each of 2019 to 2021; the expected cumulative adjusted funds flow and capital investment over the Plan's three years; resource development potential beyond the Plan and the Corporation's future drilling inventory; the benefits derived from third party processing arrangements the Corporation entered into with two midstream firms; whether the Corporation will extend its gathering pipelines from Glacier to Wembley; and other matters. 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. With respect to the forward looking statements contained in this presentation, Advantage has made a number of material assumptions regarding, but not limited to: current and future commodity prices; the Corporation's current and future hedging program; future exchange rates; future production and composition including natural gas and liquids; royalty regimes and future royalty rates; future operating costs; future transportation costs and availability of product transportation capacity; future general and administrative costs; the estimated well costs including frac stages and lateral lengths per well; the number of new wells required to achieve the objectives of the Plan; that the Corporation will be able to complete its infrastructure projects on a timely basis; the timing for the construction to be completed on the Corporation's new liquids handling facility in Valhalla and the benefits derived from such new facility; the timing for the construction to be completed on third party mid stream facilities; timing and amount of net capital expenditures; and that the Corporation will have sufficient financial resources required to fund its capital and operating expenditures and requirements as needed. 23

ADVISORY Management has included the summary of assumptions and risks related to forward looking information in order to provide shareholders with a more complete perspective on Advantage's future operations and such information may not be appropriate for other purposes. Advantage s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward looking statements will transpire or occur, or if any of them do so, what benefits that Advantage will derive there from. Management does not have firm commitments for all the costs, expenditures, prices or other financial assumptions used to prepare the forward looking information or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. Readers are cautioned that the foregoing lists of factors are not exhaustive. The Corporation and management believe that the statements have been prepared on a reasonable basis, reflecting management's best estimates and judgments. However, because this information is highly subjective and subject to numerous risks including the risks discussed above, it should not be relied on as necessarily indicative of future results. These forward looking statements are made as of the date of this presentation and Advantage disclaims any intent or obligation to update publicly any forward looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. 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; impact of significant declines in market prices for oil and natural gas; actions by governmental or regulatory authorities including increasing taxes and changes in investment or other regulations; changes in tax laws, royalty regimes and incentive programs relating to the oil and gas industry; the effect of acquisitions; Advantage's success at acquisition, exploitation and development of reserves; failure to achieve production targets on timelines anticipated or at all; unexpected drilling results; changes in commodity prices, currency exchange rates, net 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, including 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; individual well productivity; lack of available capacity on pipelines; delays in anticipated timingof drilling and completion of wells; delays in completion of infrastructure; lack of available capacity on pipelines; individual well productivity; competition from other producers; the lack of availability of qualified personnel or management; credit risk; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; our ability to comply with current and future environmental or other laws; stock market volatility and market valuations; 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; and 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 dated March 5, 2018 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. 24

ADVISORY Oil and Gas Information Barrels of oil equivalent ("boe") and thousand cubic feet of natural gas equivalent ("mcfe") may be misleading, particularly if used in isolation. Boe and mcfe conversion ratios have been calculated using a conversion rate of six thousand cubic feet of natural gas equivalent to one barrel of oil. A boe and mcfe conversion ratio of 6 mcf: 1 bbl 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. This presentation discloses drilling inventory in the Glacier, Valhalla, Progress and Pipestone/Wembley areas in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from Sproule Associates Limited reserves evaluation effective December 31, 2017 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the 1,200 to 1,400 total drilling locations identified herein, 303 are proved locations, 34 are additional probable locations and 863 to 1,063 are unbooked locations. Unbooked 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 Corporation will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics 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. Any references in this presentation to initial production rates or IP30 rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Advantage. Advantage has presented certain type curves and well economics for its Montney areas. The type curves presented are based on Advantage's historical production. Such type curves and well economics are useful in understanding management's assumptions of well performance in making investment decisions in relation to development drilling in the Montney area and for determining the success of the performance of development wells; however, such type curves and well economics are not necessarily determinative of the production rates and performance of existing and future wells and such type curves do not reflect the type curves used by our independent qualified reserves evaluator in estimating our reserves volumes. The type curves differ as a result of varying horizontal well length, stage count and stage spacing. The type curves represent the average type curves expected. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented; however, there is no certainty that Advantage will ultimately recover such volumes from the wells it drills. 25

ADVISORY In presenting such type curves, inputs and economics information and in this presentation generally, Advantage has used a number of oil and gas metrics which do not have standardized meanings and therefore may be calculated differently from the metrics presented by other oil and gas companies. Such metrics include DCE+T, "EUR", "NPV10", "payout", "rate of return" (or "ROR"), "half cycle ROR", operating netback", and "capital efficiency". EUR represents the estimated ultimate recovery of resources associated with the type curves presented. NPV 10 represents the anticipated net present value of the future net revenue discounted at a rate of 10% associated with the type curves presented. Payout means the anticipated years of production from a well required to fully pay for the DCE+T of such well. ROR means the rate of return of a well or the discount rate required to arrive at a NPV equal to zero. Half cycle ROR means the rate of return of a well or the discount rate required to arrive at a NPV equal to zero when taking into account "half cycle" costs, which include drilling, completion, equip and tie in capital expenditures. Production estimates contained herein are expressed as anticipated average production over the calendar year. In determining anticipated production for the years ended 2018 to 2021 Advantage considered historical drilling, completion and production results for prior years and took into account the estimated impact on production of the Corporation's 2018 to 2021 expected drilling and completion activities. 26

ADVISORY Non GAAP Measures The Corporation discloses several financial and performance measures that do not have any standardized meaning prescribed under International Financial Reporting Standards ("IFRS" or GAAP ). These financial and performance measures include net capital expenditures, adjusted funds flow, total debt, total debt to adjusted funds flow, and capital efficiency. Such financial and performance measures should not be considered as alternatives to, or more meaningful than measures determined in accordance with GAAP including net income, comprehensive income, cash provided by operating activities, or cash used in investing activities. Management believes that these measures provide an indication of the results generated by the Corporation s principal business activities and provide useful supplemental information for analysis of the Corporation s operating performance and liquidity. 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. Net capital expenditures include total capital expenditures related to property, plant and equipment and exploration and evaluation assets incurred during the period. Management considers this measure reflective of actual capital activity for the period as it excludes changes in working capital related to other periods. The Corporation considers adjusted funds flow to be a useful measure of Advantage s ability to generate cash from the production of natural gas and liquids, which may be used to settle outstanding debt and obligations, and to support future capital expenditures plans. Changes in non cash working capital are excluded from adjusted funds flow as they may vary significantly between periods and are not considered to be indicative of the Corporation s operating performance as they are a function of the timeliness of collecting receivables or paying payables. Expenditures on decommissioning liabilities are excluded from the calculation as the amount and timing of these expenditures are unrelated to current production, highly variable and discretionary. Total debt is the total of bank indebtedness and working capital deficit. Total debt to adjusted funds flow is a ratio calculated as total debt divided by adjusted funds flow for the previous four quarters. Total debt to adjusted funds flow is considered by management to be a useful measure as it is commonly used to evaluate the leverage of a company and the ability to settle outstanding debt and obligations with cash generated from operations. Capital efficiency is calculated by dividing total capital development costs for oil and gas activities including drilling, completion, facilities, infrastructure, office and capitalized general and administrative costs (excluding abandonment and reclamation costs, exploration and evaluation costs, and acquisition and disposition related costs and proceeds) by the average production additions of the applicable year to replace base production declines and deliver production growth targets, expressed in $/boe/d. Capital efficiency is considered by management to be a useful performance measure as a common metric used to evaluate the efficiency with which capital activity is allocated to achieve production additions. Refer to 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 financial measures, including reconciliations to the nearest GAAP measures, as applicable. 27

ADVISORY Abbreviations The following abbreviations used in this presentation have the meanings set forth below. bbl barrel bbl/d bbls/d bbls/mmcf boe boe/d GJ mcf Mcfe mmcf/d mmcfe/d NGL DCE+T barrel per day barrels per day Barrels per million cubic feet barrels of oil equivalent of natural gas, on the basis of one barrel of oil or natural gas liquids for six thousand cubic feet of natural gas barrels of oil equivalent per day Gigajoule thousand cubic feet thousand cubic feet equivalent on the basis of six thousand cubic feet of natural gas for one barrel of oil or natural gas liquids million cubic feet per day million cubic feet equivalent per day natural gas liquids C3+ propane plus C5+ pentanes plus drill, complete, equip and tie in 28

ADVANTAGE CONTACT INFORMATION Investor Relations 1.866.393.0393 ir@advantageog.com www.advantageog.com Listed on TSX: AAV Advantage Oil & Gas Ltd. Suite 300, 440 2nd Avenue SW Calgary, Alberta T2P 5E9 Advantage 100% W.I. Glacier Gas Plant Main: 403.718.8000 Facsimile: 403.718.8332 Andy Mah, P.Eng. Mike Belenkie, P.Eng. Craig Blackwood, C.A. Director, President & Chief Executive Officer Chief Operating Officer VP Finance & Chief Financial Officer