Record Low Reserve Addition Costs of PDP $0.84/Mcfe in 2016 Tops Off A Stellar Year of Operating & Financial Results. Development Plan Growth to 316

Transcription

1 Record Low Reserve Addition Costs of PDP $0.84/Mcfe in 2016 Tops Off A Stellar Year of Operating & Financial Results. Development Plan Growth to 316 mmcfe/d (52,670 boe/d) Underway" Investor Presentation TSX / NYSE: AAV March 2017

2 ADVANTAGE AT A GLANCE TSX, NYSE: AAV TSX 52-week trading range $ $10.33 Shares Outstanding (basic) Annual Production Budget 16% Production Growth million 236 mmcfe/d (39,330 boe/d) Market March 2, 2017 $1.5 billion As of December 31, 2016: Bank Debt (38% drawn on $400 million Credit Facility) $153 million Total Debt (including working capital deficit) $159 million Year-end 2016 Total Debt /Trailing Cash Flow 1.0x View of Glacier Plant Process Train approximately 1,250 feet long 2

3 OUR STRATEGY LONG TERM PROFITABLE & SUSTAINABLE GROWTH 2016 PDP F+D $0.84/mcfe (2) 1P F+D $0.25/mcfe (2) 3 Year 2P F+D $0.46/mcfe (2) 2016 Q4 Total corporate cash costs $0.83/mcfe (3) World Class Montney Asset Industry Leading N.A. Low Cost Gas Supply Own & Operate 100% Plant & Infrastructure Hedged to Protect Future Cash Flow (1) Strong Balance Sheet 1.0x D/CF 2016 Operating & Financial Flexibility 1) % of estimated annual future production net of royalties, $3.19 Cdn/mcf 2017, $3.02 Cdn/mcf 2018 & $3.00 Cdn/mcf Q ) Finding & Development Cost ( F+D ) including change in Future Development Capital for proved development producing ( PDP ), Proved ( 1P ) and Proved Plus Probable ( 2P ) reserves based on Sproule 2016 year-end reserves report 3) Total corporate cash cost includes royalties, operating costs, gas and liquids transportation, G&A and financing costs 3

4 LAST 3 ARS - A SOLID TRACK RECORD OF VALUE GENERATION 98% THREE-AR TOTAL SHAREHOLDER RETURN (Dec. 31/13 to Dec. 31/16) 2016 RETURN ON CAPITAL Natural gas and liquids sales price including realized hedging gains $/mcfe $2.89 Total Corporate Cash Costs $(0.66) Total Capital Costs, PDP F&D $(0.84) (1) (2) 23% 2016 Full Cycle Netback $ Annual Return on Capital 48% -11% -18% 3 Year Average Annual Return on Capital 29% Advantage Oil & Oil Gas & Gas Ltd. Ltd. S&P/TSX Composite Index (Total Return) S&P/TSX Capped Energy Index (Total Return) S&P/TSX Oil & Gas Exploration & Production GICS Sub Industry (Total Return) 1) Corporate cash costs include natural gas transportation fees as of Nov. 1, Prior to, fees deducted off revenue as per contractual terms. 2) PDP F&D cost based on Sproule year-end 2016 Reserve Report 4

5 2017 BUDGET FUNDED THROUGH CASH FLOW INCLUDING UPSIZED GLACIER GAS PLANT EXPANSION TO 400 MMCF/D ($ million) $205 Drill 21 wells $37 Complete 24 wells $71 Plant Expansion $71 $ Highlights (1) 16% Annual Production Growth 23% Cash Flow Per Share Growth (2) 236 MMcfe/d (39,330 Boe/d) Annual Average Production $0.91/mcf Total Cash Costs including natural gas transportation of $0.28/mcf Upsized Glacier Gas Plant Expansion to 400 mmcf/d Other Facilities $12 Well Tie-in $9 Land & Other $ Capital Estimate 2017 Cash Flow (2) AECO $2.95/Mcf 100% Firm Gas Transportation Service Year-end 2017 Total Debt/Cash Flow 0.7x (1) Midpoint of 2017 Guidance Range. (2) Based on an average AECO Cdn $2.95/mcf ($2.80/GJ) natural gas price for 2017 and Advantage s current hedge positions 5

6 PRODUCTIVITY & INFRASTRUCTURE SUPPORTING 2017 THROUGH 2019 GROWTH >70 mmcf/d Surplus Well Productivity IP30 Average (1) 5 wells Completed Waiting on Testing 15 wells Uncompleted Standing Wells (2) 150 mmcf/d Plant Expansion to 400 mmcf/d in progress >180 mmcf/d Additional Sales Gas Pipeline Capacity, Total 400 mmcf/d capacity 308 mmcf/d Total Firm Natural Gas Transportation Service by 2019 Well Pads Planned to 2019 Glacier Gas Plant 100% working interest Current Capacity 250 mmcf/d (1) As of March 1, Management estimated initial 30 day average well production rate (IP30). (2) As of March 1,

7 ADVANTAGE S 2017 THROUGH 2019 GROWTH 2017 thru 2019 Highlights 56% Production Growth (2017 thru 2019) $625 Million Capital Investment $735 Million Cash Average AECO Cdn $2.95/mcf ($2.80/GJ) 0.2x 2019 Total Debt/Trailing Cash Flow Post mmcfe/d (66,670 boe/d) 2008 to mmcfe/d 2017 thru 2019 Q4 221 to 325 mmcfe/d 7

8 ADVANTAGE GROWTH PLAN 2017 THROUGH 2019 (1) 203 Annual Average Production (mmcfe/d) 16% 15% % % CAGR (2) 316 $128 Capital Spending ($ millions) Cumulative $625 million $205 $210 $ Budget 2018E 2019E Budget 2018E 2019E $0.92 Cash Flow per Share 12% 23% $1.27 $1.13 Cumulative Cash Flow $735 million % $1.55 $7,330 ALL-IN Capital Efficiency (3) ($/boe/d) $13,000 $11,800 $11,600/boe/d Average $10, Budget 2018E 2019E Budget 2018E 2019E Notes: (1) See Appendix pg. 26 for Plan details (2) Compound annual growth rate. (3) Capital Efficiency calculated using 30% per annum decline and includes total annual capital expenditures 8

9 CASH SURPLUS REDUCES TOTAL DEBT TO CASH FLOW Cumulative Cash Surplus ($2.80/GJ) $80 Year-end Total Debt to Cash Flow (1) Ratio $110 million surplus $ $ $ Budget 2018E 2019E Budget 2018E 2019E Note: (1) Based on Advantage 2017 Budget and 2018 & 2019 Development Plan estimates assuming an AECO natural gas price of Cdn $2.95/mcf ($2.80/GJ) & the corporation s hedging positions 9

10 HEDGING, TRANSPORTATION AND MARKETS Current Hedges TCPL Transportation Service Period Production (1) Hedged (net) Average AECO Fixed Price 100% firm service secured thru Advantage s surplus plant & well capacity provides flexibility to capture high pipeline flow periods % $3.19/mcf % $3.02/mcf 2019 Q1 18% $3.00/mcf Fixed price removes commodity price and basis volatility Guarantees cash flow for hedged volumes Market Diversification Sales Gas Target Firm Contracted Service Pending Request IT Service Estimate Alliance Connection Option TCPL Henry Hub 25,000 mcf/d at U.S. $0.85/mcf basis 2018 to 2019 Henry Hub - 50,000 mcf/d at U.S. $0.88/mcf basis 2019 Evaluating N.A. market options Glacier gas plant Alliance Assessing Alliance meter station connection (1) % of estimated annual future production, net of royalties 10

11 DEVELOPMENT PLAN NATURAL GAS PRICE SENSITIVITY CFPS & D/CF Cash Flow per Share Sensitivity (1) $1.49 $1.32 $1.20 $1.12 $1.03 $1.12 $0.94 $0.92 $1.86 $1.58 $1.30 $ AECO $2.00/mcf AECO $2.50/mcf AECO $3.00/mcf AECO $3.50/mcf Total Debt to Trailing Cash Flow Sensitivity (1) (1) As of November 28, 2016 and includes Advantage s current hedge positions 11

12 MAINTENANCE CAPITAL AND SURPLUS CASH FLOW SENSITIVITY ILLUSTRATIVE AT 325 MMCFE/D (NO HEDGING INCLUDED) 3 Year Cumulative Surplus $525 million 3 Year Cumulative Surplus $690 million $360 Million Based on average well type curve (1) Surplus Cash Flow Above $1.45/mcf $130 million $130 Million $305 Million Cash Surplus $175 million per Year Cash Surplus $230 million per Year Based on top quartile type well (2) $110 million Mantenance Capital at 325 mmcfe/d Q Cash Flow at AECO $1.45/Mcf Cash Flow at AECO $3.00/Mcf Notes (1) Assumes 7.5 mmcf/d /7.5 Bcf for Upper/Lower Montney wells and 5.0 mmcf/d /5.0 Bcf for Middle Montney wells (2) Assumes 9 mmcf/d /9 Bcf for Upper/Lower Montney wells and 6 mmcf/d /6 Bcf for Middle Montney wells Cash Flow at AECO $3.50/Mcf 12

13 ATTRACTIVE NETBACKS & RECYCLE RATIOS ARE ACHIEVABLE WITHOUT HEDGING $/Mcfe $5.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $- Montney Natural Gas Producers Total Cost Structure Q AAV - $0.85/mcfe Lowest Total Corporate Cash Cost Montney Producer (includes gas transportation) $2.41/mcfe AAV TOU PPY BIR CR VII ARX KEL NVA POU Interest & other ($/mcfe) Royalties incl. GCA adjustments ($/mcfe) G&A ($/mcfe) Average of Peers Operating costs & transportation ($/mcfe) Glacier Netbacks NO HEDGING INCLUDED Illustrative Illustrative AECO Cdn AECO Cdn $2.00/mcf $3.00/mcf Revenue (Realized Price) $2.15 $3.17 Royalties ($0.09) ($0.15) Operating Costs Transportation Costs ($0.25) ($0.31)(2) ($0.25) ($0.31) Operating Netback $1.50 $2.46 G&A ($0.10) ($0.10) Finance Expense & other ($0.10) ($0.10) Cash Flow Netback Recycle Ratio based on 3 Year Average 2P $0.46/mcfe (3) $1.30/mcfe or $7.80/boe (1) (1) $2.26/mcfe or $13.56/boe 2.8x 4.9x (2) (1) Advantage's transportation includes liquids transportation costs of $0.05/mcfe and gas transportation costs of $0.27/mcfe for Q Source: RBC Capital Markets, Public Disclosures and Advantage Q reported actual results (1) Natural Gas & Liquids revenue includes adjustments for heat value. (2) Includes liquids transportation costs of $0.04/mcfe and gas transportation costs of $0.27/mcfe. (3) 2P F&D includes Future Development Capital and is based on Sproule s 2014, 2015 and 2016 year-end 2P reserves reports. 13

14 HIGH QUALITY MONTNEY ASSETS, OPERATIONAL EXCELLENCE 14

15 GLACIER DRIVES GROWTH THROUGH NEXT DECADE, ADDITIONAL MONTNEY LANDS PROVIDES FUTURE UPSIDE Current development at Glacier including dry and liquids rich gas drilling with a future drilling inventory >1,100 locations Total 157 net Montney sections (100,480 acres) New Montney lands at Valhalla, Wembley & Progress contain multiple layers and requires additional delineation Glacier 91 net sections 100% owned Glacier Gas Plant Valhalla (Evaluating) Progress (Future) 9 net Montney sections Valhalla Initial 3 delineation wells confirm liquids in 2 layers drilled to date. Total of 4 possible development Montney layers are present. Additional 4 delineation wells to be drilled in net Montney sections Wembley (Future) Industry Activity Encroaching Wembley & Progress 15

16 INDUSTRY ACTIVITY ENCROACHING PROGRESS, WEMBLEY AND VALHALLA LAND BLOCKS Pipestone/Wembley New Locations Multi-Layer Development Upper Montney Middle Montney Lower Montney Progress Recent Wells Pipestone Development Valhalla New Wells On-Production Drill Months (28 Net Sections) Drill Months (9 Net Sections) Multi-Layer Natural Gas & Liquids Potential Future Processing at Glacier Gas Plant Drill 4 Wells 2017 (30 Net Sections) 16

17 ONLY 7% OF GLACIER S FUTURE WELL INVENTORY REQUIRED FOR 2017 THRU 2019 DEVELOPMENT Only 83 of our 1,100 Future Drill Locations at Glacier is required to achieve growth to 316 mmcfe/d average 2019 Only 307 undeveloped locations booked in 2P reserves Year End 2016 Drilled (3) Wells by Layer >1,100 Future Drilling Locations (Management (1) Estimate) Upper 108 Liquids Rich intervals Average 50 bbls/mmcf, >45% C5+ East Glacier *Interval 6 not assigned reserves or resource 2P Reserves Undeveloped (2) Wells 307 Middle 26 Lower 47 (1) Management Estimates (2) Based on Sproule December 31, 2016 Glacier Reserves Report (3) As of December 31, 2016, gross Hz wells 17

18 (1) LM WELLS FROM RECENT 120 MMCF/D EIGHT WELL PAD OUTPERFORMING PRODUCTION TYPE CURVE 3 longer lateral LM wells (still production restricted) are significantly outperforming average well type curve LM Well #1 LM Well #2 LM Well #3 LM Well #4 Budget Type Curve (IP mmcf/d & 7.5 Bcf) Longer Laterals, More Frac Stages 3 LM wells average 2,583 meters (longest 2,880 meters) 28 frac stages, 60 tonnes/stage Avg cost DCE&T $4.3 million/well 1 MM well 2,502 meters, 26 frac stages 11.3 mmcf/d, 30 bbls/mmcf C 3 +, $5.1 million DCE+T Upper Montney Middle Montney Lower Montney Well Pad Shorter Laterals Evaluating Spacing & Recovery 3 LM wells average 1,656 meters Avg cost $3.7 million/well DCE&T Notes: (1) Each well produced in-line for average of 48 hours to Glacier gas plant, at an average flow pressure of 11.8 mpa (1,623 psi) 18

19 UPPER & LOWER MONTNEY WELL PRODUCTION CONTINUES TO IMPROVE >16mmcf/d New wells are normally restricted to ~ 10 mmcf/d for frac sand flowback control during initial 6 months Wells tested, not on-production. Production Average (24 wells) Budget Type Curve (IP mmcf/d & 7.5 Bcf) IP mmcf/d & 9.0 Bcf Type Curve 24 Upper & Lower Montney Wells, average 20 frac stages, started production July Lower Montney Well results beginning to surpass Upper Montney Production updated to January,

20 MOST RECENT LOWER MONTNEY WELLS WITH UP TO 30 FRAC STAGES (OPEN-HOLE PACKERS AND CEMENTED PORTS) Additional Lower Montney wells with longer laterals, reduced frac spacing and cemented ports are continuing to be brought on production. Wells restricted to ~ 10mmcf/d for frac sand flowback control during initial 6 months Production Average (13 wells) Budget Type Curve (IP mmcf/d & 7.5 Bcf) IP mmcf/d & 9.0 Bcf Type Curve Production updated to January,

21 GLACIER MIDDLE MONTNEY WELLS EXCEEDING AVERAGE BUDGET TYPE CURVE Wells are exceeding current type curves Ongoing delineation identifies sweet spots within different Middle Montney layers. Frac designs are tailored to further optimize results well (2013) cumulative production > 3.8 Bcfe Middle Montney Budget Type Curve (IP mmcf/d & 5.0 Bcf) Production updated to January,

22 ROBUST GLACIER MONTNEY WELL ECONOMICS Upper & Lower Montney (Dry Gas) Advantage achieved >20% DC & E well cost reduction with >35% increase in frac count ROR = 76% ROR = 108% Middle Montney (50 bbls/mmcf (1) C3+, 45% C5+) ROR = 75% ROR = 106% Type Curve & Cost Higher IP & EUR Case Type Curve & Cost Higher IP & EUR Case $4.8MM $4.8MM $4.8MM $4.8MM IP30 Bcf Well Cost (DC&E) mmcf/d Assumptions: Management Estimates of IP30, 2P EUR & Capital Costs and includes a 4 month drill to on-production timeframe. Cdn Aeco $3.00/mcf, flat Cdn $37/bbl blended C3+ price based on $50 U.S./bbl WTI (1) East Glacier average 22

23 GROWTH BEYOND 400 MMCF/D CAN BE ACCOMMODATED ON EXISTING PLANT SITE 100% Owned Glacier Gas Plant Positioned for Production Ramp-up Advantage Gas Plant Room for Additional Expansion Beyond 400 mmcf/d To be expanded from 250 mmcf/d to 400 mmcf/d Dry & Liquids gas processing capacity TCPL Sales Meter Stations Alliance Sales Gas Line TCPL NW ALBERTA Main Sales Gas Line 400 mmcf/d take away capacity to TCPL NW main sales gas pipeline Pembina NGL Line Company Land Company Gas Plant TransCanada Pipeline Pembina Pipeline Advantage Pipeline Alliance Pipeline Glacier Gas Plant Site near Major Natural Gas & Liquids Pipelines & Rail Access Sales Pipeline Loop capacity of 400 mmcf/d (Glacier plant to NW TCPL Mainline) Total TCPL Natural Gas Firm Transportation Service of 308 mmcf/d by 2019 Secured 23

24 Clear Vision for Growth Financial Strength Proven Expertise

25 APPENDIX 25

26 GLACIER GROWTH PLAN DETAILS 16% ANNUAL AVERAGE PRODUCTION GROWTH 2017 THRU Annual Average Production (mmcfe/d) Budget 2018E 2019E Annual Average Production Growth 16% 16% average growth per year ( CAGR ) 15% 16% 2017 Budget 2018E 2019E 26

27 IMPROVING WELL PERFORMANCE AND LOWER WELL COSTS THROUGH DRILLING & COMPLETION TECHNOLOGY Recent TOP Quartile Wells (1) Increasing frac count has improved long term production performance in all layers Well Costs Reduced ($ millions) NOTE: 2017 cost estimate includes an allowance for inflation UPPER MONTNEY $5.5 $4.8 9 mmcf/d 21 mmcf/d 18 mmcf/d 10 mmcf/d 6 mmcf/d (18 fracs) (>25 fracs) 18 mmcf/d 13 mmcf/d MIDDLE MONTNEY LOWER MONTNEY 16 mmcf/d 13 mmcf/d 13 mmcf/d 12 mmcf/d 18 mmcf/d $6.6 $4.8 $5.8 $4.8 Upper Montney Middle Montney Lower Montney 11 mmcf/d (18 fracs) (>25 fracs) (18 fracs) (>25 fracs) (1) Initial on production rate based on approximately first ten days of in line test at gas gathering system pressure. Wells are then choked to 10 mmcf/d to manage frac sand flow back per AAV operating practices (2) As of August 4,

28 CONTINUOUS IMPROVEMENT HAS CREATED INDUSTRY LEADING EFFICIENCIES 28

29 UPPER AND LOWER MONTNEY WELLS - IMPROVING PERFORMANCE SINCE 2008 Newer wells restricted for frac sand flow back Budget Type Curve (IP mmcf/d & 7.5 Bcf) Data: updated to February

30 LIQUIDS RICH MIDDLE MONTNEY WELL PERFORMANCE IMPROVEMENTS SINCE Well Slickwater, OH Packers 26 frac stages 2015/16 Middle Montney wells with frac design changes including >20 frac stages and cemented ports to be evaluated 20 total Middle Montney wells on-production across Glacier land block wells (1) Gen 4: Slickwater, OH Packers Avg 19 frac stages wells Gen 3: Slickwater, OH Packers Avg 15 frac stages wells Gen 2: Poly CO2, & Slickwater Plug and Perf Avg 13 frac stages wells Gen 1: Poly CO2, Sand Plugs, Avg 15 frac stages Note: (1) Production plot affected by low number of producing wells >350 days and wells being choked. Middle Montney Budget Type Curve (IP mmcf/d & 5.0 Bcf) Middle Montney IP mmcf/d & 6.0 Bcf Type Curve 30

31 EXCEPTIONAL UPPER & LOWER MONTNEY WELL ECONOMICS (1) Upper & Lower Montney Dry Gas (2) Budget Type Curve. Some recent Upper & Lower Montney wells are outperforming type curve (3) (1) Management estimates. NPV 10% pre-tax. (2) Capital of $4.8 million per well based on management s estimate of DCE+T capital cost (3) Natural gas and NGL prices and costs escalated at 1.5%. Average C3+ Cdn NGL price of $37/bbl based on $50 U.S./bbl WTI 31

32 EXCEPTIONAL EAST GLACIER MIDDLE MONTNEY WELL ECONOMICS (1) Middle Montney at 50 bbls/mmcf C3+ (2) Budget type curve. Some recent MM wells are exceeding type curve. (3) (1) Management estimates. NPV 10% pre-tax. (2) Capital of $4.8 million per well based on management s estimate of DCE+T capital cost (3) Natural gas and NGL prices and costs escalated at 1.5%. Average C3+ Cdn NGL price of $37/bbl based on U.S.$50/bbl WTI. C3+ NGL yields of 50 bbls/mmcf raw gas 32

33 GLACIER MONTNEY ASSIGNED 2P EUR PER WELL & INTERVAL Glacier - 2P Recoveries per Interval (1) Interval 2012 # of Gross HZ Wells 2P Recovery [bcf/well] Developed Undeveloped Total Developed Undeveloped Total UM MM MM MM LM Total (1) Based on Sproule year-end reserve reports. Indicated raw gas volumes per well. 33

34 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 34

35 2012 CORE AND COMPLETION STUDIES: INCREASED RESOURCE AND IMPROVED WELL RESULTS Core study determined original density porosity logs have to be recalibrated 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 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 Completion Study Area IP30 s with pump rates > 4m 3 /minute improved by 1.7x First year cumulative production improved by 2.4x from 0.7 bcf to 1.7 bcf 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 (1) Composite log and core from several wells located across the Glacier land block 35

36 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 to 2019 development program; expected number of wells required to be drilled to achieve certain levels of production; expected well economics associated with certain type curves; expected sensitivities in cash flow per share and debt tocash flow levels tochanges in commodity prices; expected effect of refinement of drilling and completion techniques; projections of market prices and costs; anticipated number of future drilling locations and inventory and the Corporation's focus on developing such locations including the timing thereof; the proposed expansion of Advantage's Glacier gas plant processing capacity, including the amount of such expansion, the anticipated timing of completion of the proposed expansion and the expected benefits to Advantage from such expansion; Advantage's 2017 capital program, including the amount thereof, the amount to be allocated to increase annual production and the amount to be directed to facilities and infrastructure; the Corporation's drilling plans for 2017, 2018 and 2019, including the number of wells to be drilled and the timing of completion of certain wells; Advantage's anticipated annual production, total year-end debt to trailing cash flow, natural gas and liquids sales price (including realized hedging gains), total corporate cash costs, total capital costs, netbacks and annual return on capital for 2016; estimated three year annual return on capital; Advantage's anticipated capital expenditures, annual production, royalty rates, operating costs, liquids transportation costs, annual cash flow, cash flow per share, funds from operations, total debt to trailing cash flow ratio, cumulative cash surplus and total corporate cash costs for 2017; Advantage's anticipated capital expenditures, annual production, annual cash flow per share, funds from operations, all-in capital efficiency, cumulative cash surplus and total debt to trailing cash flow ratio for each of 2018 and 2019; expected increases in production in 2017, 2018 and 2019 resulting from Advantage s development plan; Advantage's future hedging positions; 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. 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 or royalties 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; 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, 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; delays in anticipated timing of drilling and completion of wells; delays in completion of the expansion of the Glacier gas plant; 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 which is available at and 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 and future commodity prices and royalty regimes; future exchange rates; royalty rates; future operating costs, cash costs and liquids transportation costs; frac stages per well; lateral lengths per well; estimated EURs; well costs; 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; available pipeline capacity; that the Corporation will be able to complete the expansion and increase capacity at the Glacier gas plant; that Advantage's production will increase; current or, where applicable, proposed assumed industry conditions, laws and regulations will 36

37 ADVISORY continue in effect or as anticipated; and that 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. Production estimates contained herein for the years ended December 31, 2017, 2018 and 2019 are expressed as anticipated average production over the calendar year. In determining anticipated production for the years ended December 31, 2017, 2018 and 2019 Advantage considered historical drilling, completion and production results for prior years and took into account the estimated impact on production of the Corporation's 2017, 2018 and 2019 expected drilling and completion activities. Management has included the above 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. Readers are cautioned that the foregoing lists of factors are not exhaustive. 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. 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 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. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. 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. 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 7.5 mmcf/d IP (which represents the average 30 day initial production rate) and 7.5 Bcfe (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 5 mmcf/d IP and 5 Bcfe Middle Montney type curve are management generated type curves based on a combination of historical performance of older 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 and 9 Bcf Upper and Lower Montney type curve and the 6 mmcf/d IP and 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 over 1,100 undeveloped future drilling locations in the following categories: (i) proved (247 locations); (ii) proved + probable (307 locations); and (iii) unbooked (over 793 additional locations). Proved locations and probable locations are derived from the Corporation s most recent independent reserves evaluation as prepared by Sproule Associates Limited as of December 31, 2016 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Corporation 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. Unbooked locations do not have attributed reserves or resources. 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 derisked 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. 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 37

38 ADVISORY 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 total debt to trailing cash flow ratio, total cash costs, funds from operations and operating netbacks. Total debt to trailing cash flow ratio is calculated as bank indebtedness under the Corporation's credit facilities plus working capital deficit divided by funds from operations for the prior twelve month period. Total cash costs includes royalties, operating costs, liquids transportation, cash G&A, interest & other cash expenses. Funds from operations is based on cash provided by operating activities, before expenditures on decommissioning liability and changes in non-cash working capital, reduced for finance expense excluding accretion. Operating netbacks are calculated by deducting royalties and operating costs from revenue on a unit (boe or mcfe) basis. 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. Please see the Corporation s most recent Management s Discussion and Analysis, which is available at and for additional information about these financial measures, including a reconciliation of funds from operations to cash provided by operating activities. This presentation and, in particular the information in respect of the Corporation's prospective cash flow debt to trailing cash flow ratio, total cash costs, operating costs, capital expenditures, annual cash flow and funds from operations may contain future oriented financial information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by management to provide an outlook of the Corporation's activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions, including the assumptions discussed above, and assumptions with respect to the costs and expenditures to be incurred by the Corporation, capital equipment and operating costs, foreign exchange rates, taxation rates for the Corporation, general and administrative expenses and the prices to be paid for the Corporation's production. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the FOFI 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. The actual results of operations of the Corporation and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The Corporation and management believe that the FOFI has 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. FOFI contained in this presentation was made as of the date of this presentation and the Corporation disclaims any intention or obligations to update or revise any FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.

39 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 mboe thousands of barrels of oil equivalent tcf trillion cubic feet 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 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 contains certain oil and gas metrics, including EUR, PDP F&D, 2P F&D, operating netbacks, cash flow netbacks, all-in netbacks, recycle ratio and CAGR which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Corporation's performance; however, such measures are not reliable indicators of the future performance of the Corporation and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. EUR represents the 2P estimated ultimate recoverable conventional natural gas volumes per well assigned by the Corporation's internal non-independent qualified reserves evaluator in accordance with the Canadian Oil & Gas Evaluation Handbook. PDP F&D is calculated by adding together all capital expenditures including exploration and development costs and dividing the sum by PDP reserves additions. 2P F&D is calculated by adding together all capital expenditures including exploration and development costs and the change in future development costs and dividing the sum by 2P additions. The aggregate of the exploration and development costs incurred in the most recent financial year generally will not reflect total finding and development costs related to reserve additions for that year. Operating netbacks are calculated by deducting royalties, operating costs and transportation costs from revenue on a unit (mcfe) basis. Cash flow netbacks are calculated by deducting royalties, operating costs, transportation costs, cash G&A and cash finance expenses from revenue on a unit (mcfe) basis. All-in netbacks are calculated by deducting royalties, operating costs, transportation costs, cash G&A, cash finance expenses and PDP F&D from revenue on a unit (mcfe) basis. Recycle ratio is calculated as Cash flow netbacks divided by 2P F&D. CAGR is the Compound Annual Growth Rate representing the measure of average annual growth over multiple time periods. In this presentation certain financial and operating metrics of other issuers are presented to compare such metrics to Advantage's results. Such other issuers were included to show how Advantage's performance compares to some of its peers. The financial and operating metrics of such issuers have been obtained from public sources and have not been independently verified by Advantage. Readers should not base an investment decision for the securities of such issuers based on the information available herein. Advantage disclaims any responsibility or liability for the accuracy of the information relating to such other issuers presented herein. This presentation contains projections of production growth based on drilling and recompletion opportunities identified by management of Advantage. Certain of the drilling opportunities identified have no associated reserves or resources which can presently be classified as recoverable. As such the initial rates of production and reserves per well identified herein do not represent estimates of future production or reserves associated with the drilling opportunities. The initial rates of production, reserves per well and the capital costs associated with drilling and recompletion identified below are based on Advantage's historical results and analogous public information received from other producers using similar technologies as Advantage intends to use in the same or similar areas and formations. The initial rates of production, reserves per well and capital costs associated with the wells have been provided herein to give an indication of management's assumptions used for budgeting, planning and forecasting purposes. The initial rates of production, reserves and capital costs will most likely be different than projected. 39

40 ADVANTAGE CONTACT INFORMATION Investor Relations Listed on NYSE and TSX: AAV Advantage Oil & Gas Ltd. Suite 300, 440 2nd Avenue SW Calgary, Alberta T2P 5E9 Main: Facsimile: Advantage 100% W.I. Glacier Gas Plant Andy Mah, P.Eng. Craig Blackwood, C.A. Neil Bokenfohr, P.Eng. Director, President & Chief Executive Officer VP Finance & Chief Financial Officer Senior Vice President