Investor Presentation TSX, NYSE: AAV July, Page 1

Transcription

1 Pure Play Montney Producer with a proven operating team, industry leading cost structure & clear visibility to a significant drilling inventory creates a solid foundation for multi-year growth Investor Presentation TSX, NYSE: AAV July, 2014 Page 1

2 Advantage At a Glance Intermediate Canadian Montney Producer Listed on TSX and NYSE AAV TSX 52-week trading range ($Cdn) $ $7.85 Shares Outstanding (basic) Current Production Market Capitalization (June 30, 2014) Bank March 31, 2014 (21% drawn on $400 million credit facility) Total Debt (March 31, 2014) million 135 mmcfe/d (22,500 boe/d) $1.2 billion $85 million $188 million Q Total Debt / Annualized Cash Flow 1.0 Page 2

3 Industry Leading Pure Play Montney Producer Focused on Glacier Area Advantage s Pure Play Montney holdings are concentrated in the Glacier, Alberta area. We are a highly focused Montney only producer with 25 current employees, operatorship of our lands and ownership of our facilities. Glacier 77 net sections 100% owned Glacier Gas Plant Valhalla Recently acquired net sections of Montney Acreage Focused development of 16 TCF (1) TPIIP at Glacier including liquids extraction Glacier future drilling inventory ~1,400 locations New Montney lands at Vahalla and Wembley are yet to be delineated Industry leading cost structure Wembley (1) Based on Sproule s March 31, 2013 Glacier Resource Assessment. Page 3

4 Glacier Montney Development Then and Now EnCana EnCana Murphy Murphy Swan & Tupper at 4 to 7 wells/section density today. Potential for 20 wells/section at Glacier Very few horizontal wells drilled however, numerous vertical wells had penetrated the Montney providing geological information Advantage has drilled over 117 Montney wells at Glacier since Delineation drilling was designed to evaluate the Montney across our land block and in each of the multiple layers contained in ~300 meters of formation thickness Page 4

5 Glacier Delineation Drilling Resulted in Pentastack Development Plan Five Development Intervals Containing > 1,400 Future Locations Development based on four wells per section per layer Proven commercial well rates across Glacier in the Upper, Middle and Lower Montney Three of the five intervals are located in the liquids rich Middle Montney formation Wells are vertically and laterally offset in each layer for optimal recovery Remaining Inventory of Locations(1) # Wells Required in 3 Year Development Plan (2) Remaining Undrilled Locations post 2017 # of Undeveloped Locations Booked in Sproule Dec 31, 2013 Report Upper Montney Middle Montney Lower Montney Total (1) (2) Excludes 117 Developed wells booked in the Sproule Dec. 31, 2013 Reserve Report Includes 12 Phase VI wells drilled in Q Page 5

6 Middle Montney Liquids Led to Acquisition of New Montney Lands in 2013 Phase VI drilling results confirm increasing liquids in east Glacier and extends liquids potential to new lands Technical work to date indicates thick Montney formation and multiple layer potential in the new lands These new Montney lands are not included in our current drilling inventory or resource estimates at this time Glacier 77 net Montney sections High Liquid Yield Glacier Middle Montney Wells Additional net sections of Montney Acreage New 12-2 well restricted to ~6.5 mmcf/d to manage handling of high liquid volumes Page 6

7 Going Forward Financial Strength to Support Montney Growth Plan Strengthened Balance Sheet $94 million gross proceeds from Longview share sale $17.5 million from sale of Questfire investments $85 million March 31, 2014 bank debt Total Debt/Cash flow 1.5x (1) over 3 year Dev Plan Low cost structure 3 Year Development Plan Downside Natural Gas Protection 50% future production hedged at Aeco Cdn $3.84/mcf, 2014 and % future production hedged at Aeco Cdn $4.07/mcf 2016 to Q Credit Facility Capacity 79% undrawn ($315 million available) (1) Based on peak total debt at end of each development phase to forward cash flow Page 7

8 Industry Leading Cost Structure Contributes to Robust Economics Advantage s full cycle margin between realized price and cash costs is among the top Montney producers liquids production will further increase the realized price and margin. Page 8

9 Three Year Fully Funded Glacier Growth Plan Details: 100% Production per Share and 190% Cash Flow per Share Growth Development Plan (3) Phase VI Phase VII Phase VIII Phase IX Q2 13 to Q1 14 Q2 14 to Q1 15 Q2 15 to Q1 16 Q2 16 to Q1 17 Current Approved Estimates Estimates Production (mmcfe/d) 12 month average End of Phase Target Production includes NGL s increasing from 900 bbls/d to 1,500 bbls/d in Phases VIII and IX Wells Dry Liquids Rich Total Capital ($ millions) $165 $265 $255 $215 Commodity Prices (4) NYMEX ($US/mmbtu) $4.00 $4.40 $4.10 $4.10 AECO ($/GJ) $3.30 $4.10 $3.65 $3.55 WTI ($US/bbl) $98.00 $92.50 $85.00 $80.50 Financial ($ millions) Funds from operations $103 $165 $205 $240 Bank debt peak (5) $105 $265 $325 $290 Total debt peak (5) $225 $325 $375 $333 Bank debt/cash flow (5) Total debt /cash flow (5) (1) Based on input assumptions illustrated in above table. Growth % represents average production change and CFPS change in each 12 month consecutive Phase. (2) Based on million shares outstanding. (3) All capital and operating input parameters are based on mid-point estimates. (4) Based on strip prices as of January 28, (5) Estimated peak bank debt and total debt at end of development Phase pro forma Longview share sale. Total debt includes bank debt, debentures and working capital. Page 9 Cash flow based on forward period.

10 Three Year Development Plan Strong Growth Leads to Free Cash Flow Total debt/ forward cash flow decreases as cash flow grows significantly based on an average natural gas price of Cdn $3.75/GJ ( ) Pea The 12 month period post Q generates $160 million of free cash flow at a natural gas price of Cdn $3.65/GJ assuming flat production of 245 mmcfe/d Capital required to grow to 183 mmcfe/d Capital required to grow to 205 mmcfe/d Capital required to grow to 245 mmcfe/d Capital required to stay flat at 135 mmcfe/d Capital required to stay flat at 183 mmcfe/d Capital required to stay flat at 205 mmcfe/d Capital required to stay flat at 245 mmcfe/d Page 10

11 Track Record of Improving Operating Performance Production Growth to 135 mmcfe/d & Operating Cost Reduction to ~$0.30/mcfe $475,000/frac stage 73% Reduction in cost per frac despite increasing average number of frac stages from 6 to 16 $130,000/frac stage 580% Increase in 2P Reserves to 1.7 Tcfe 43% Reduction in 3 Year 2P F&D cost to $1.06/mcfe Page 11

12 Improving Upper & Lower Montney Well Performance with Slickwater (data updated to May 31, 2014) High rate wells are typically rate restricted to avoid sand erosion issues Recent Upper and Lower Montney wells completed with slickwater fracs are outperforming Phase VII Budget type curve which is based on an IP mmcf/d. Graph illustrates production from 13 recent Montney wells (5 Upper and 8 Lower) Page 12

13 Exceptional Upper Montney Results Across Glacier Production from slickwater fracs exhibiting clean-up after test and shallower declines 21 mmcf/d initial production restricted to 10 mmcf/d 21 mmcf/d record well 11 mmcf/d 10 mmcf/d 11 mmcf/d 15 mmcf/d 11 mmcf/d 10 mmcf/d 13 mmcf/d 14 mmcf/d 11 mmcf/d 11 mmcf/d 17 mmcf/d 13 mmcf/d 10 mmcf/d No Wells Drilled 11 mmcf/d 12 mmcf/d 12 mmcf/d 19 mmcf/d 15 mmcf/d 12 mmcf/d 11 mmcf/d 9 & 5 mmcf/d Denotes previous wells >10 mmcf/d test rates (1) 18 mmcf/d 10 mmcf/d 12 mmcf/d Current Phase VI well test rates (1)(2) Drilled and completed Waiting on completion Drilling or to be drilled Phase VI wells are proving up reserves in east Glacier at above well type curve expectations Upper Montney results from west to east Glacier demonstrated exceptional results and robust economic returns A total of 86 Upper Montney Hz wells have been drilled to date across Glacier 24 of these wells tested at > 10 mmcf/d 44 wells tested at >7 mmcf/d (1) Based on well final test rate normalized to average gas gathering system pressure of 3,000 kpa (2) See Appendix for well test information. Page 13

14 Solid Lower Montney Results Across Glacier 7 mmcf/d 12 mmcf/d initial production 5mmcf/d 10 mmcf/d production for 3 months Production from slickwater fracs exhibiting clean-up after test and shallower declines 4mmcf/d 3.7 7mmcf/d 6.8 Previous LM well 16 mmcf/d Previous LM well 14 mmcf/d mmcf/d 9.4 mmcf/d 3mmcf/d 3.6 4mmcf/d Current Phase VI well test rates (1)(2) Drilled and and completed Waiting on on completion Drilling or or to to be be drilled Phase VI wells proving up reserves and productivity in east and northwest Glacier Lower Montney average type curve yields strong economics Future completion design changes could further improve results more stages and high frac rates LM wells will yield C3+ of 11 bbls/mmcf under shallow cut liquids extraction process A total of 21 Lower Montney Hz wells have been drilled to date at Glacier (1) Based on well final test rate normalized to average gas gathering system pressure of 3,000 kpa (2) See Appendix for well test information. Page 14

15 Improving Liquids Rich Middle Montney Well Performance at Glacier (data updated to May 31, 2014) Production Rate vs Time New Phase VI 12-2 well started production at restricted rate of 9.5 mmcf/d. Restricted to ~6.5 mmcf/d to manage handling of high liquid volumes Middle Montney wells have sequentially demonstrated improved productivity as we optimize frac design. Recent wells exceeding Budget type curve Page 15

16 Middle Montney: Results Confirm Liquid Trend and Improved Well Rates Liquid yields are higher in east Glacier and pervasive through entire land block 8 mmcf/d 26 bbl/mmcf 8 bbl/mmcf 31 bbl/mmcf 8 bbl/mmcf vertical well 30 bbl/mmcf 10 bbl/mmcf vertical well 1 mmcf/d 18 bbl/mmcf 5 bbl/mmcf 4 mmcf/d 27 bbl/mmcf 8 bbl/mmcf 40 bbl/mmcf 10 bbl/mmcf vertical well 8 mmcf/d 57 bbl/mmcf 32 bbl/mmcf 4 mmcf/d 63 bbl/mmcf 26 bbl/mmcf 2 mmcf/d 42 bbl/mmcf 20 bbl/mmcf 4 mmcf/d 76 bbl/mmcf 45 bbls/mmcf 2 mmcf/d 76 bbl/mmcf 45 bbl/mmcf 9.5 mmcf/d initial production restricted to 6 mmcf/d due to high liquid volumes Record Well 100/ w6 13 mmcf/d 42 bbl/mmcf 20 bbl/mmcf Phase VI wells confirm AAV geological model with increasing liquids up-dip across Glacier lands Results to date will add reserves and confirms commerciality based on average type curve Future completion design changes expected to improve well performance more frac stages and high frac rates Local variations in Middle Montney highlighting sweet spots A total of nine Middle Montney Hz wells have been drilled to date at Glacier mmcf/d bbl/mmcf bbl/mmcf Test Gas rate (1) C3+ liquids yield (2) Condensate yield Current Phase VI well test rates (1) (3) Drilled and completed (1) Based on well final test rate normalized to average gas gathering system pressure of 3,000 kpa (2) Based on shallow cut liquids extraction process (3) See Appendix for well test information. Page 16

17 Proven Commerciality - Glacier Montney Well Economics (1) Dry Gas Upper and Lower Montney (2) Liquids Rich Gas Middle Montney Intervals (3) Rate of Return (%) $10.9 million $8.8 million $6.7 million $10.5 million $7.9 million $4.9 million Frac optimization of 108 Upper and Lower Montney wells since 2008 at Glacier has increased the average Budget type curve to an IP of 6.9 mmcf/d. Production from 9 MM wells to date confirm the average 4 mmcf/d IP 30 Budget type curve. Continued frac design changes have shown improving rates in each subsequent MM program. AECO Gas Price $/mcf (4) (1) Management estimates. NPV 10% pre-tax (2) Based on $5.8 million per well with 17 frac stages (3) Based on $6.6 million per well with 17 frac stages and NGL yields of 39 bbls/mmcf raw gas (4) Natural gas prices and costs escalated at 2%. Average C3+ NGL price of $60.29/bbl escalated at 2% Page 17

18 Glacier Gas Plant (100% Owned) - Significant Expansion Potential mmcf/d pipeline capacity to TCPL meter station in place Glacier Gas Plant Site & Proximity to Major Natural Gas & Liquids Pipelines & Rail Access Provides Significant Expansion Potential Page 18

19 Advantage Summary Growing Our Montney at Glacier Focused on our world class 16 Tcf TPIIP Glacier Montney property and development of its 4.2Tcfe contingent resources and 1.7 Tcfe 2P reserves (1) Additional net sections of new undeveloped Montney lands provides further upside Three Year Glacier Development Plan Underway Grow production per share by ~100% in 2017 Increase cash flow per share ~ 190% (2) at an average Total Debt/Cash Flow of 1.5x (2)(3) Solid financial strategy and operational expertise underpins execution capability Initial Delineation Drilling on our new undeveloped Montney lands is planned within the next 14 months Well productivity in the Upper, Middle and Lower Montney across Glacier have improved and result in robust well economics. New frac technology may further improve well results in future Phase VII Budget (2014/15) approved by Board Grows Glacier production in 2014/15 by 36% to 183 mmcfe/d (1) Based on Sproule s March 31, 2013 Resource Assessment and Glacier 2P Reserve report as of December 31, See Appendix A. (2) Assumes an average price of AECO Cdn $3.75/GJ (strip price as of January 28, 2014 for 2014 to 2017). (3) Based on end of development phase peak total debt to forward cash flow. Page 19

20 Appendix Page 20

21 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 Page 21

22 Glacier Major Pipeline Access Page 22

23 2012 Core and Completion Studies Increased Resource and Improved Well Results 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 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 Page 23

24 Upper and Lower Montney Average Well Type Curve Improvement (data updated to May 31, 2014) Advantage has significantly improved well performance since Utilization of more frac stages and slickwater fracs have recently created another step-rate change. We anticipate new technology could further improve results. Page 24

25 Summary of Well Tests Referenced in Presentation Slides Well Formation Final Gas Test Rate (mmcf/d) Test Period (hrs) Final Flow Pressure (kpa) Normalized Final Gas Test Rate (1) (mmcf/d) Estimated C3+ liquid yield (bbls/mmcf) (2) 00/ W6-Horizontal Upper Montney , / W6-Horizontal Upper Montney , / W6-Horizontal Upper Montney , / W6-Horizontal Upper Montney , / W6-Horizontal Upper Montney , / W6-Horizontal Upper Montney , / W6-Horizontal Lower Montney , / W6-Horizontal Lower Montney , / W6-Horizontal Lower Montney , / W6-Horizontal Lower Montney , / W6-Horizontal Lower Montney , / W6-Horizontal Lower Montney , / W6-Horizontal Lower Montney , / W6-Vertical Middle Montney / W6-Vertical Middle Montney / W6-Vertical Middle Montney / W6-Horizontal Middle Montney / W6-Horizontal Middle Montney , / W6-Horizontal Middle Montney , / W6-Horizontal Middle Montney , / W6-Horizontal Middle Montney , / W6-Horizontal Middle Montney , / W6-Horizontal Middle Montney , / W6-Horizontal Middle Montney , / W6-Horizontal Middle Montney , / w6- Horizontal Lower Montney , / w6- Horizontal Lower Montney , (1) Based on well test final rate normalized to average gas gathering system pressure of 3000 kpa. (2) Estimated recovery from shallow cut extraction process. Page 25

26 Glacier Drilling Economics and 2P Recoveries per Interval ($ millions unless otherwise indicated) Glacier Drilling Economics PV 10% Discount (1) AECO C natural gas price ($/mcf) (2) Dry Gas(3) Liquids Rich Gas(4) $3.00 $4.00 $5.00 $3.00 $4.00 $5.00 IP30 s and 2P Reserves: 4 mmcf/d & 4 Bcf N/A N/A N/A $2.8 $4.9 $7.1 5 mmcf/d & 5 Bcf $1.8 $4.6 $7.4 $5.2 $7.9 $ mmcf/d & 6 Bcf $3.4 $6.7 $10.0 $7.7 $10.5 $ mmcf/d & 7 Bcf $5.0 $8.8 $12.4 $9.6 $12.7 $ mmcf/d & 8 Bcf $6.5 $10.9 $14.3 N/A N/A N/A Glacier 2P Recoveries per Interval (5) 2P Recovery # of Gross Hz Wells (bcf/well) Developed Undeveloped Total Developed Undeveloped Interval YE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE Total (1) Management estimates (2) Natural gas prices and costs escalated at 2%. Average C3+ NGL price of $60.29/bbl escalated at 2% (3) Based on $5.8 million per well with 17 frac stages (4) Based on $6.6 million per well with 17 frac stages and NGL yields of 39 bbls/mmcf raw gas (5) Based on Sproule December 31, 2013 reserves report Page 26

27 Glacier March 31, 2013 Contingent and Prospective Resource Assessment Advantage engaged our independent qualified reserves evaluator Sproule Associates Ltd. ( Sproule ) to update the resource analysis and provide a 2C evaluation ( Sproule 2C Contingent Resource Evaluation ) at Glacier as of March 31, 2013 in accordance to the Canadian Oil and Gas Evaluation Handbook (COGEH) resource definitions that are consistent with the standards of National Instrument The estimates of reserves and resources for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The following three tables summarize the results of Sproule s resource assessment of Advantage s Glacier Montney resources as at March 31, 2013: Resource Categories (AAV Working Interest, Best Estimate, Raw) (1) Tcf Total Petroleum Initially In Place (TPIIP) Discovered Petroleum Initially in Place (DPIIP) (2) Undiscovered Petroleum Initially in Place (UPIIP) (3) 2.05 Low Estimate Best Estimate High Estimate DPIIP (AAV Working Interest, Sales) (2) Natural Gas Cumulative Production (Tcf) (4) Reserves (Tcf) (5) Contingent Resources (Tcf) Unrecoverable DPIIP (Tcf) Natural Gas Liquids Cumulative Production (mbbls) (4) Reserves (mbbls) (5) 5,949 11,071 12,732 Contingent Resources (mbbls) 72, , ,013 Unrecoverable DPIIP (mbbls) 225, , ,330 Page 27

28 Glacier Contingent and Prospective Resource Assessment Low Estimate Best Estimate High Estimate UPIIP (AAV Working Interest, Sales) (3) Natural Gas Prospective Resources (Tcf) Unrecoverable UPIIP (Tcf) Natural Gas Liquids Prospective Resources (mbbls) 7,381 11,691 16,274 Unrecoverable UPIIP (mbbls) 25,558 21,248 16,665 (1) See Appendix C for the definitions from the COGE Handbook of the various resource categories used herein. (2) There is no certainty that it will be commercially viable to produce any portion of the DPIIP. (3) There is no certainty that any portion of the UPIIP will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the UPIIP. (4) The cumulative production represents the actual total historic production from Advantage's Glacier Montney resources and as such is not a Low, Best or High Estimate. (5) For reserves, the Low Estimate is proved reserves, the Best Estimate is proved plus probable reserves and the High Estimate is proved plus probable plus possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. Page 28

29 Glacier Contingent and Prospective Resource Assessment 2C (Best Estimate) Contingent Resources Interval Gross Number of Hz Well Locations Net Present Values Before Income Taxes Gross 2C Recoverable ($ millions) Resources per Location (Raw Bcf per Well) 0% 10% 15% ,031 1,791 1, , , , Facility Costs N/A N/A (758) (368) (296) Total 1,120 4,619 $19,652 $3,215 $1,642 Sproule evaluated the economics of Advantage's Best Estimate contingent resources based on a development scenario that was provided by Advantage. The development plan included the drilling of 1,120 future contingent locations with a total undiscounted capital expenditure of $8.3 billion which includes the necessary facilities and infrastructure costs. For the evaluation of proved plus probable reserves, the development plan assumed a maximum production rate of 200 mmcf/d is reached in 2015 and maintained until The proved plus probable reserves evaluation included the drilling of 313 future undeveloped locations with a total undiscounted capital expenditure of $1.9 billion. In estimating the Glacier contingent resources, Sproule assumed based on Advantage's development plan that gas plant capacity would increase over and above the proved plus probable reserves forecast by 100 mmcf/d per year of raw gas starting in 2015 to a total throughput of 600 mmcf/d raw gas by The 600 mmcf/d raw facility throughput capacity was then maintained to the year 2032 by drilling wells as required. The 2C contingent resources at Glacier are all considered to be Economic Contingent Resources based on the forecast commodity prices, capital costs and operating costs as at March 31, The crude oil and natural gas pricing assumptions used for the estimate were prepared by Sproule effective March 31, Page 29

30 Glacier Contingent and Prospective Resource Assessment Other Notes about Resource Estimates: TPIIP, DPIIP and UPIIP have been estimated using a zero percent porosity cut-off (sandstone log scale). The Montney formation is approximately 300 meters thick. Sproule s analysis utilized 6 potential layers consisting of 1 layer in the Upper Montney, 3 layers in the Middle Montney and 2 layers in the Lower Montney. With the exception of the lowest layer in the Lower Montney, all other layers exist across the entire Glacier land block. Recoverable gas volumes were estimated using a 4 well per section development in each of the layers within the Montney formation at Glacier. Recovery factors were assigned to each layer based on the performance of existing wells in the layer or in similar layers. Reserves have only been assigned to Layer 1 (Upper Montney), Layers 2 and 3 (Middle Montney) and Layer 5 (Lower Montney). Contingent Resources are assigned to all five layers except the sixth layer of the Lower Montney (all of Layer 6 is prospective). Contingent Resources for each section and layer were assigned if there was a sustained gas test within 3 miles of the section, otherwise, the resource was classified as prospective undiscovered resources. Liquid yields are unique to each layer and were estimated based on the gas composition of gas samples combined with any free liquids obtained from well production tests in each layer. The contingencies Sproule identified to convert Contingent Resource into reserves are specific to each layer and generally include the following: Development maturity including the number of sustained well tests and the amount of production information. Sproule indicates that very few sections in Layers 2 and 3 (Middle Montney) have reserves assigned; however, there are sufficient tests spread geographically across the lands to classify the bulk of the sections as Contingent Resources. No reserves have been assigned to Layer 4 (Middle Montney); however, there have been sufficient testing of a few wells located very low in Layer 3 and spread geographically across the lands to classify many sections as contingent in Layer 4. The lack of infrastructure to facilitate full development in the short term including the required processing facilities to extract NGLs in certain Montney layers. Economic contingencies dictating a slower pace of development with current low gas prices in sections that are farther from existing gas gathering infrastructure and farther from existing tests. Prospective resources account for only 9.6% of the estimated ultimate recoverable resources in the 2C best estimate case and demonstrates that the vast majority of the Montney formation at Glacier has been shown to be productive. Page 30

31 Appendix Reserve and Resource Definitions Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows: Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total resources" is equivalent to "Total Petroleum Initially-In-Place". Resources are classified in the following categories: Total Petroleum Initially-In-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. Discovered Petroleum Initially-In-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and Contingent Resources; the remainder is unrecoverable. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies. Economic Contingent Resources are those contingent resources that are currently economically recoverable. Undiscovered Petroleum Initially-In-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as "prospective resources" and the remainder as "unrecoverable." Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and resources as follows: Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. Page 31

32 Advisory Certain statements contained in this presentation constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. In particular, this presentation contains forward-looking statements pertaining to, but not limited to, the following: details of the Corporation s development plan to increase production at Glacier and the anticipated production levels and timing thereof; anticipated effect of three year development plan at Glacier on production per share growth and cash flow per share growth, including the Corporation's expectations as to the levels of such growth and the timing of achievement of such levels; estimated debt levels following the sale of the Longview common shares; number of expected future drilling locations; the Corporation's plans to evaluate additional sections of Montney acreage for prospective natural gas and liquids potential; anticipated effect of production history from recent wells and future well test results on reserve replacement efficiencies at Glacier; the Corporation s anticipated drilling and completion plans, including drilling inventory, future locations, additional wells required for three year development plan and available wells after 2017; effect of refinement of drilling and completion techniques; effect of termination of TSA on general and administrative expenses and financial and operational complexity; the Corporation's expectations regarding increase to borrowing base for it credit facilities; anticipated increases to production at Glacier, including Advantage's guidance in respect of anticipated production levels (including the commodities expected), end of phase production rates, capital expenditures, number and types of wells drilled, wellhead deliverability, commodity prices, funds from operations, bank debt, funds from operations, and debt to cash flow ratios for Phase VI, Phase VII, Phase VIII and Phase IX and Advantage's guidance in respect of capital expenditures and debt to cash flow ratios for the period from Q to Q2 2018; expected continued improvements in cost efficiencies and design changes on drilling and completion plans and well performance; Advantage's guidance in respect of anticipated production levels, end of phase production rates, royalty rates, operating costs, capital expenditures and number and types of wells drilled for the 12 months ended March 31, 2015; the Corporation's expectations as to the benefits from its natural gas hedges; expectations of facilities expenditures and details thereof; plans to proceed with the installation of a liquids extraction process; ability to enhance initial production rates, rates of return and reserves; estimated three year recycle ratios and netbacks; and projections of market prices and costs. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described can be profitably produced in the future. These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond Advantage's control, including, but not limited to: changes in general economic, market and business conditions; industry conditions; actions by governmental or regulatory authorities including increasing taxes and changes in investment or other regulations; the effect of acquisitions; Advantage's success at acquisition, exploitation and development of reserves; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; fluctuations in commodity prices and foreign exchange and interest rates; stock market volatility and market valuations; volatility in market prices for oil and natural gas; unexpected drilling results, changes in commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; changes or fluctuations in production levels; delays in anticipated timing of drilling and completion of wells; individual well productivity; competition from other producers; the lack of availability of qualified personnel or management; credit risk; our ability to comply with current and future environmental or other laws; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; ability to obtain required approvals of regulatory authorities; ability to access sufficient capital from internal and external sources. Many of these risks and uncertainties and additional risk factors are described in the Corporation s Annual Information Form which is available at 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 commodity prices and royalty regimes; future exchange rates; royalty rates; future operating costs; current commodity prices and royalty regimes; availability of skilled labor; availability of drilling and related equipment; timing and amount of capital expenditures; the impact of increasing competition; the price of crude oil and natural gas; that the Corporation will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Corporation s conduct and results of operations will be consistent with its expectations; that the Corporation will have the ability to develop the Corporation s properties in the manner currently contemplated; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated; and the estimates of the Corporation s production and reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects. 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33 Advisory Advantage's actual decisions, activities, results, performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that Advantage will derive from them. Except as required by law, Advantage undertakes no obligation to publicly update or revise any forward-looking statements. For additional risk factors in respect of Advantage and its business, please refer to it Annual Information Form dated March 26, 2013 which is available on SEDAR at and References in this presentation to initial test production rates, production type curves, initial "productivity", initial "flow" rates, final gas flow rates, average gas flow rates, average type curves, "flush" production rates and "behind pipe production 30 day IP rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Advantage. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the Corporation cautions that the test results should be considered to be preliminary. Throughout this presentation the terms boe (barrels of oil equivalent), mcfe (thousand of cubic feet of gas equivalent), mmcfe (millions of cubic feet of gas equivalent), bcfe (billions of cubic feet of gas equivalent) and Tcfe (trillion of cubic feet of gas equivalent) are used. Such terms may be misleading, particularly if used in isolation. The conversion ratio used herein of six thousand cubic feet per barrel (6 mcf: 1 bbl) of natural gas to barrels of oil equivalent and the conversion ratio used herein of 1 barrel per six thousand cubic feet (1 bbl: 6 mcf) of barrels of oil to natural gas equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. The Corporation discloses several financial measures that do not have any standardized meaning prescribed under International Financial Reporting Standards ("IFRS"). These financial measures include funds from operations, net debt to cash flow ratio, enterprise value and operating netbacks. Management believes that these financial measures are useful supplemental information to analyze operating performance and provide an indication of the results generated by the Corporation s principal business activities. Investors should be cautioned that these measures should not be construed as an alternative to net income, cash provided by operating activities or other measures of financial performance as determined in accordance with IFRS. Advantage s method of calculating these measures may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies. Funds from operations, as presented, is based on cash provided by operating activities, adjusted for expenditures on decommissioning liability, changes in non-cash working capital and interest on bank indebtedness. Net debt to cash flow ratio is calculated as indebtedness under Advantage's credit facilities plus working capital deficit divided by funds from operations. Enterprise value has been calculated by adding market capitalization as at March 10, 2014 (based on the number of issued and outstanding common shares as at March 10, 2014 multiplied by the market price of the common shares on the Toronto Stock Exchange on March 10, 2014) to the total pro forma debt as of December 31, 2013 after giving effect to the sale of shares of Longview Oil Corp. Operating netbacks are calculated by deducting royalties and operating costs from revenue on a unit (boe or mcfe) basis. Please see the Corporation s most recent Management s Discussion and Analysis, which is available at and for additional information about certain of these financial measures, including a reconciliation of funds from operations to cash provided by operating activities. Page 33

34 Advisory The following abbreviations used in this press release, including in the appendices hereto, have the meanings set forth below: bbls barrels mcf thousand cubic feet bbls/d barrels per day mmcf million cubic feet mmcf/d million cubic feet per day mbbls thousand barrels bcf billion cubic feet boe barrels of oil equivalent of natural gas, on the basis of 1 barrel of oil or NGLs for 6 thousand cubic feet of natural gas bcfe billion cubic feet of natural gas equivalent on the basis of 1 barrel of oil or NGLs to 6 thousand cubic feet of natural gas mboe thousands of barrels of oil equivalent tcf trillion cubic feet boe/d barrels of oil equivalent per day tcfe trillion cubic feet of natural gas equivalent on the basis of 1 barrel of oil to 6 thousand cubic feet of natural gas 2P proved plus probable reserves 2C best estimate contingent resources NGLs natural gas liquids GGS gas gathering system Where any disclosure of reserves data and resources is made in this presentation that does not reflect all reserves of Advantage, the reader should note that the estimates of reserves, future net revenue and resources for individual properties or groups of properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. This presentation includes calculations of finding and development ("F&D") costs which have been calculated in accordance with Section 5.15 of NI by adding together exploration costs, development costs and the change in future development costs and dividing the sum by reserves additions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. In this presentation certain financial and operating metrics of other issuers are presented to compare such metrics to Advantage's results. Such other issuers were included to show how Advantage's performance compares to some of its peers. The financial and operating metrics of such issuers have been obtained from public sources and have not been independently verified by Advantage. Readers should not base an investment decision for the securities of such issuers based on the information available herein. Advantage disclaims any responsibility or liability for the accuracy of the information relating to such other issuers presented herein. This presentation contains projections of production growth based on drilling and recompletion opportunities identified by management of Advantage. Certain of the drilling opportunities identified have no associated reserves or resources which can presently be classified as recoverable. As such the initial rates of production and reserves per well identified herein do not represent estimates of future production or reserves associated with the drilling opportunities. The initial rates of production, reserves per well and the capital costs associated with drilling and recompletion identified below are based on Advantage's historical results and analogous public information received from other producers using similar technologies as Advantage intends to use in the same or similar areas and formations. The initial rates of production, reserves per well and capital costs associated with the wells have been provided herein to give an indication of management's assumptions used for budgeting, planning and forecasting purposes. The initial rates of production, reserves and capital costs will most likely be different than projected. Page 34

35 Advantage Contact Information Investor Relations Andy Mah, P.Eng. Director, President & Chief Executive Officer Craig Blackwood, C.A. VP Finance & Chief Financial Officer Advantage 100% W.I. Glacier Gas Plant Listed on NYSE and TSX: AAV Advantage Oil & Gas Ltd. Suite 300, nd Avenue SW Calgary, Alberta T2P 5E9 Main: Facsimile: Page 35