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“World Class Montney Resource, Industry Leading Low Cost Structure & Cash Margin and Operational Excellence Reinforces the Strength of our Three Year Growth Plan”
TSX / NYSE: AAVInvestor Presentation November 2014
ADVANTAGE: AT A GLANCE
2
Intermediate Canadian Montney Producer Listed on TSX and NYSE AAV
TSX 52‐week trading range ($Cdn) $3.84 ‐ $7.85
Shares Outstanding (basic) 169.8 million
Glacier Q3 2014 production 132.5 mmcfe/d(22,087 boe/d)
Market Capitalization (November 10, 2014) $0.9 billion
Bank Debt @ September 30, 2014 (18% drawn on $400 million credit facility) $71.0 million
Total Debt including working capital deficit (September 30, 2014) $205.6 million
Q3 2014 Total Debt / Annualized Cash Flow 1.4x
View of Glacier Plant Process Train – approximately 650 feet long
3
FOCUSED ON MONTNEY GROWTH & VALUE CREATION
(1) Cash Flow Per Share (CFPS) and Production Per Share (PPS) based on Advantage’s 3 Year Development Plan at an average natural gas price of Aeco Cdn $3.75/GJ over the period
245 mmcfe/d in 2017 190% CFPS growth (1)
100% PPS growth (1)
Free Cash Flow 2017Pure Montney
Producer27 employees
World Class Montney Asset
Operational Excellence
Growth Plan & Financial Strength
0
50
100
150
200
250
300
350
Million $
Stay Flat Capex Growth Capex Cash Flow
GROWTH LEADS TO SIGNIFICANT FREE CASH FLOW IN 2017
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Free cash flow is achieved in early 2017 based on Plan $160 million of free annual cash flow is generated at 245 mmcfe/d @ Cdn $3.65/GJ
Capital required to stay flat at 135
mmcfe/d
Capital required to grow to 183
mmcfe/d
Capital required to grow to 205
mmcfe/d
Capital required to grow to 245
mmcfe/d
Capital required to stay flat at 183
mmcfe/d
Capital required to stay flat at 205
mmcfe/d
Capital required to stay flat at 245
mmcfe/d
Phase VIIIQ2 2015 ‐ Q1 2016
Phase IXQ2 2016 ‐ Q1 2017 Q2 2017 ‐ Q2 2018
Phase VIIQ2 2014 ‐ Q1 2015
THREE YEAR FULLY FUNDED GLACIER GROWTH PLAN
5
Three Year Plan Summary:245 mmcfe/d (40,830 boe/d) in 2017
$735 million Capital Expenditures
33 New Montney wells per year
$3.75/GJ Aeco Cdn average price
1.5x Average Total Debt to Forward Cash Flow
190% CFPS growth
100% PPS growth
FINANCIAL STRENGTH SUPPORTS DEVELOPMENT PLAN
Credit Facility:$329 million currently available (18% drawn on our $400 million credit facility)
Balance Sheet: 1.4x Total debt to annualized Q3 2014 Cash Flow
Hedging Program:
6
% ForecastProduction Year Aeco Cdn $/mcf
56% 2014 Q4 $3.90
51% 2015 $3.90
31% 2016 $3.93
25% 2017 Q1 $3.95
GAS PRICE SENSITIVITY REDUCED BY HEDGING ANDLOW COST STRUCTURE
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Downside gas price mitigation while retaining
torque to upside
Glacier Operating Netback (1): ($/mcfe)
Revenue (2) $4.39
Royalties ($0.22)
Operating Costs ($0.31)
Operating Netback $3.86
(Recycle Ratio at 2013 2P F&D $1.33/mcfe (3)) 2.9x
G&A ($0.17)
Interest Expense & other ($0.19)
Cash Flow Netback $3.50 or ($21.00/boe)
(1) YTD 2014 Netback based on actual results. (2) Revenue is net of transportation costs & hedging loss of $0.33/mcfe YTD.(3) F&D includes Future Development Capital
Operating netback is 88% of revenue
YTD 2014 STRONG NETBACKS UNDERPIN GROWTH PLAN
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Cash flow netback is 80% of revenue
INDUSTRY COST STRUCTURE & MARGIN COMPARISON
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Advantage’s full cycle margin is among the top Montneyproducers today.
10
WORLD CLASS MONTNEY ASSET
300 meters
Natural gas and liquids resource
16 Tcf TPIIP
Glacier
GLACIER – LOCATED IN THE HEART OF THE MONTNEYRESOURCE PLAY
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Montney Siltstone Comparison:
• 700 times more permeability• 4x more formation thickness• Very low clay content• Liquids & Improved well efficiencies strong economics
FOCUSED ON MONTNEY SURROUNDING GLACIER GAS PLANT
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Glacier77 net
sections
Wembley
Valhalla
9 net Montneysections acquired
2014
100% owned Glacier Gas Plant
(1) Based on Sproule’s March 31, 2013 Glacier Resource Assessment.
Current development of 16 TCF (1) TPIIP at Glacier including liquids drilling
Glacier future drilling inventory ~1,400 locations
New Montney lands at Vahalla, Wembley & Progress are yet to be delineated
Total 129 net Montney sections (82,560 net acres)
Progress
43.25 net Montney sections acquired Sept
2013
13
Glacier Gas Plant – Positioned for Production Ramp‐up
Glacier Gas Plant Site & Proximity to Major Natural Gas & Liquids Pipelines & Rail Access Provides Significant Expansion Potential
400 mmcf/d pipeline capacity to TCPL meter
station in place
GLACIER 100% OWNED GAS PLANT & PIPELINE ACCESS
400 mmcf/d pipeline capacity to TCPL meter
station in place
GLACIER DELINEATION DRILLING HAS CONFIRMEDMULTI‐LAYER DEVELOPMENT
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EnCana began horizontal drilling in 2005; however, numerous vertical wells had penetrated the Montney
providing geological information
Advantage has drilled over 140 Montney wells at Glacier since 2008. Delineation drilling was designed to evaluate the Montney across our land block and in each of the multiple layers contained in ~300 meters of formation thickness
Swan & Tupper at 4 to 7 wells/section density today. Potential for 20
wells/section at Glacier
Remaining Inventory of Locations(1)
# Wells Required in 3 Year Development Plan (2)
Remaining Undrilled Locations post 2017
# of Undeveloped Locations Booked in Sproule Dec 31, 2013 Report
Upper Montney 230 39 191 169
Middle Montney 882 39 843 57
Lower Montney 304 33 271 72
Total 1416 111 1305 298
“PENTASTACK” DEVELOPMENT WITH DECADES OF DRILL INVENTORY
15
Development based on four wells per section per layer
Proven commercial well rates across Glacier in the Upper, Middle and Lower Montney
Three of the five intervals are located in the liquids rich Middle Montney formation
Wells are vertically and laterally offset in each layer for optimal recovery
(1) Excludes 117 Developed wells booked in the Sproule Dec. 31, 2013 Reserve Report(2) Includes 12 Phase VI wells drilled in Q1 2014
Five Development Intervals Containing > 1,400 Future Locations
16
OPERATIONAL EXCELLENCE
17
Production Growth to 135 mmcfe/d & Operating Cost Reduction to ~$0.30/mcfe 73% Reduction in cost per frac despite increasing
average number of frac stages from 7 to 16
580% Increase in 2P Reserves to 1.7 Tcfe 43% Reduction in 3 Year 2P F&D cost to $1.06/mcfe
$475,000/frac stage
$130,000/frac stage
No wells drilled
TRACK RECORD OF OPERATING PERFORMANCE
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Advantage has significantly improved well performance since 2008. Utilization of more frac stages and slickwater fracs have recently created another step‐rate change. We anticipate new technology could further improve results.
UPPER AND LOWER MONTNEY AVERAGE WELL TYPE CURVE IMPROVEMENT
Data: updated to November 2014
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
0.0 0.5 1.0 1.5 2.0 2.5
Raw
Gas
Pro
duct
ion
Rat
e (m
cf/d
)
Cumulative Raw Gas Production (Bcf)
Current Budget Type Curve(IP30 6.9 mmcf/d)
14
24
28
31
10
Well Count
Phase VI2013
Phase IV & V2011/12
1
Phase III2010
Phase II2009
Phase I2008
IMPROVING UPPER & LOWER MONTNEY WELL PERFORMANCE WITH SLICKWATER
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Recent Upper and Lower Montney wells completed with slickwaterfracs are outperforming Phase VII Budget type curve which is based on an IP30 6.9 mmcf/d.
Graph illustrates production from 14 recent Montney wells (5 Upper and 9 Lower)
Phase VII Upper & Lower (IP30 6.9 mmcf/d) Budget Type Curve
Data: updated to November2014
20(1) Based on Advantage Operating Netback of $3.86/mcfe for the first nine months of 2014
• Upper and Lower Montney well performance has improved through frac design & increased reservoir knowledge.
• Some recent wells were initially restricted as noted by the slope change in their cumulative production trend.
Top Tier Wells Trending toward Payout of <10 months(1)
Cumulative production of >2 Bcf in first year
IMPROVING UPPER & LOWER MONTNEY WELL PAYOUT
Data: updated to November2014
EXCEPTIONAL UPPER MONTNEY WELL ECONOMICS(1)
21(1) Management estimates. NPV 10% pre‐tax(2) Based on $5.5 million per well with 18 frac stages(3) Natural gas prices and costs escalated at 2%. Average C3+ Avg NGL price of $63.44/bbl escalated at 2%
Upper Montney Dry Gas (2)
Frac optimization of 108 Upper and Lower Montney wells since 2008 at Glacier has increased the average Budget type curve to an IP of 6.9 mmcf/d.
mmcf/d IP30 / Bcf
(3)
EXCEPTIONAL LOWER MONTNEY WELL ECONOMICS(1)
22(1) Management estimates. NPV 10% pre‐tax(2) Based on $5.8 million per well with 18 frac stages and C3+ NGL yields of 11 bbls/mmcf raw gas(3) Natural gas prices and costs escalated at 2%. Average C3+ Avg NGL price of $63.44/bbl escalated at 2%
AECO Gas Price $/mcf (3)
Lower Montney at 11 bbls/mmcf C3+(2)
Budget type curve 6.9 mmcf/d. Lower Montneywells have improved with frac design changes and are similar to Upper Montney wells
mmcf/d IP30 / Bcf
EAST GLACIER CONTAINS HIGHER MIDDLE MONTNEY LIQUID CONTENT
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30 bbl/mmcf10 bbl/mmcfvertical well
Results have commercialized Middle Montney play
Future completion design changes expected to further improve well performance
Local variations in Middle Montney highlighting “sweet spots”
(1) Based on shallow cut liquids extraction process yields from well test data.
Middle Montney wells to date illustrate higher liquid content from
west to east across Glacier
63
27
18
40
4230
76
5731
26
76Record Well 100/12‐2‐76‐
12w613 mmcf/d 42 bbl/mmcf
C3+ Liquids
Yield bbl/mmcf
Glacier C5+ 57 deg API
Follow‐up Well 100/8‐35‐76‐12w6
11.4 mmcf/d 47 bbl/mmcf
42
47
IMPROVING LIQUIDS RICH MIDDLE MONTNEY WELL PERFORMANCE AT GLACIER
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New Phase VI 12‐2 well started production at restricted rate of 9.5 mmcf/d. Currently restricted at 5 mmcf/d after 250 days @ 1,100psi
Budget Type Curve 4mmcf/dMiddle Montney wells have sequentially demonstrated improved productivity as we optimize frac design. Recent wells
exceeding Budget type curve
Data: updated to November, 2014
4.0 mmcf/d Budget Type Curve
STRONG EAST GLACIER MIDDLE MONTNEY WELL ECONOMICS(1)
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Middle Montney at 50 bbls/mmcf C3+ (2)
Current Budget Type Curve 4 mmcf/d IP 30 Continued frac design changes have shown improving rates in each subsequent MM program.
mmcf/d IP30 / Bcf
(1) Management estimates. NPV 10% pre‐tax(2) Based on $6.4 million per well with 18 frac stages and C3+ NGL yields of 50bbls/mmcf raw gas(3) Natural gas prices and costs escalated at 2%. Average C3+ Avg NGL price of $63.44/bbl escalated at 2%
(3)
ADVANTAGE SUMMARY: GROWING OUR MONTNEY AT GLACIER
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Focused on our world class 16 Tcf TPIIP Glacier Montney property and development of its 4.2 Tcfe contingent resources and 1.7 Tcfe 2P reserves(1)
Additional 52.25 net sections of new undeveloped Montney lands provides further upside
Three Year Development Plan Grows Production to 245 mmcfe/d (40,830 boe/d) 190% CFPS, 100% PPS(2), 1.5x Total Debt to Forward Cash Flow(3)
Multi‐year Hedging program & low cost structure strengthens growth plan
Industry Leading Low Cost Producer with top decile cash margin
Improving well performance further enhances economics in Upper, Middle & Lower Montney
Financial strength to support capital program
(1) Based on Sproule’s March 31, 2013 Resource Assessment and Glacier 2P Reserve report as of December 31, 2013. See Appendix. (2) Assumes an average price of AECO Cdn $3.75/GJ (strip price as of January 28, 2014 for 2014 to 2017).(3) Based on end of development phase peak total debt to forward cash flow.
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APPENDIX
THREE YEAR FULLY FUNDED GLACIER GROWTH PLAN DETAILS: 100% PRODUCTION PER SHARE AND 190% CASH FLOW PER SHARE GROWTH
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Development Plan (3)
Phase VII Phase VIII Phase IXQ2’14 to Q1’15
Q2‘15 to Q1’16
Q2’16 to Q1’17
Current Estimates Estimates Production (mmcfe/d)12 month average 135 174 209 End of Phase Target 183 205 245
WellsUpper & Lower 20 22 24 Liquids Rich, Middle Montney 13 9 11 Total 33 31 35
Capital ($ millions) $265 $255 $215 Commodity Prices (4)
NYMEX ($US/mmbtu) $4.40 $4.10 $4.10 AECO ($/GJ) $4.10 $3.65 $3.55 WTI ($US/bbl) $92.50 $85.00 $80.50
Financial ($ millions)Funds from operations $165 $205 $240Bank debt – peak (5) $265 $325 $290 Total debt – peak (5) $325 $375 $333 Bank debt/cash flow (5) 1.3 1.4 1.0 Total debt /cash flow (5) 1.6 1.6 1.1
(1) Based on input assumptions illustrated in above table. Growth % represents average production change and CFPS change in each 12 month consecutive Phase.
(2) Based on 168.4 million shares outstanding.(3) All capital and operating input parameters are based on mid‐point estimates.(4) Based on strip prices as of January 28, 2014.(5) Estimated peak bank debt and total debt at end of development Phase pro forma Longview share sale.
Total debt includes bank debt, debentures and working capital.Cash flow based on forward period.
Production includes NGL’s increasing from 900 bbls/d to 1,500 bbls/d in Phases VIII and IX
SOLID UPPER & LOWER MONTNEY WELL RESULTS ACROSS GLACIER
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(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.
Upper Montney - Strong well results throughout block show tremendous upside potential in future development locations.
record well 21 mmcf/d record well
10 mmcf/d
15 mmcf/d
14 mmcf/d
19 mmcf/d
17 mmcf/d
15 mmcf/d
13 mmcf/d
12 mmcf/d
13 mmcf/d
12 mmcf/d
12 mmcf/d
11 mmcf/d
11 mmcf/d
11 mmcf/d
11 mmcf/d
10 mmcf/d
10 mmcf/d
13 mmcf/d
Recent 4 well pad39 mmcf/d
18 mmcf/d
Lower Montney – Recent wells with revised completions have markedly improved wells in West area. Advancing delineation to Northwest and East areas.
3 mmcf/d
11 mmcf/d
9 mmcf/d
7 mmcf/d4 mmcf/d
Recent Completions
12 mmcf/d
10 mmcf/d
4 mmcf/d
14 mmcf/d
record well 16 mmcf/d record well
Denotes test rates (1)(2)
Recent 4 well pad55 mmcf/d
Recent 4 well pad57 mmcf/d
2012 CORE AND COMPLETION STUDIES: INCREASED RESOURCE AND IMPROVED WELL RESULTS
30(1) Composite log and core from several wells located across the Glacier land block
Completion Study included 135 wells and over 1,400 fracs in the immediate Glacier area covering the EnCana Swan and Murphy Tupper properties
Findings revealed that high frac pump rates and open hole packer system resulted in optimal performance
IP30’s on open hole wells improved by
1.6xFirst year cumulative
production improved by 1.7x from 0.7 bcf to 1.2 bcf
First year cumulative production improved by 2.4x from 0.7 bcf to 1.7 bcf
IP30’s with pump rates > 4m3/minute improved by 1.7x
Core study determined original density porosity logs have to be re‐calibrated
Re‐calibration aligned log to actual core porosities evident through entire 290 meters of Montney formation at Glacier
Well tests in all the Montney layers proved gas saturation and productivity
Completion Study Area
GLACIER DRILLING ECONOMICS AND 2P RECOVERIES PER INTERVAL
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Glacier Drilling Economics – PV’s @ 10% Discount(1)
AECO C natural gas price($/mcf)(2)
Layer 1(6) Layer 5(3) Liquids Rich Gas (East Glacier)(4)
$3.00 $4.00 $5.00 $3.00 $4.00 $5.00 $3.00 $4.00 $5.00IP30’s and 2P Reserves:
4 mmcf/d & 4 Bcf N/A N/A N/A N/A N/A N/A $5.8 $7.9 $9.85 mmcf/d & 5 Bcf $1.4 $4.5 $7.6 $2.6 $5.5 $8.4 $8.5 $10.8 $12.96 mmcf/d & 6 Bcf $2.9 $6.5 $10.0 $4.3 $7.8 $10.6 $10.9 $13.5 $15.97 mmcf/d & 7 Bcf $4.3 $8.6 $11.9 $6.1 $9.7 $12.7 $13.2 $16.2 $18.88 mmcf/d & 8 Bcf $5.8 $10.3 $13.8 $7.8 $11.5 $14.8 N/A N/A N/A
(1) Management estimates(2) Natural gas prices and costs escalated at 2%. Average C3+ NGL price of $63.44/bbl escalated at 2%(3) Based on $5.8 million per well with 18 frac stages and NGL yields of 11 bbls/mmcf raw gas(4) Based on $6.4 million per well with 18 frac stages and NGL yields of 50 bbls/mmcf raw gas(5) Based on Sproule December 31, 2013 reserves report(6) Based on $5.5 million per well with 18 frac stages and NGL yields of 0 bbls/mmcf raw gas
($ millions unless otherwise indicated)
Glacier – 2P Recoveries per Interval(5)
# of Gross Hz Wells
2P Recovery(bcf/well)
Interval Developed Undeveloped Total Developed UndevelopedYE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE 2013 YE 2012 YE 2013
1 73 83 174 169 247 252 4.3 4.4 4.7 5.42 5 8 16 38 21 46 2.7 3.9 4.0 4.23 1 4 0 19 1 23 2.5 2.7 0.0 3.14 0 0 0 0 0 0 0.0 0.0 0.0 0.05 15 22 76 72 91 94 2.9 3.8 5.0 5.1
Total 94 117 266 298 360 415
GLACIER MARCH 31, 2013 CONTINGENT AND PROSPECTIVE RESOURCE ASSESSMENT
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Advantage engaged our independent qualified reserves evaluator Sproule Associates Ltd. (“Sproule”) to update the resource analysis and provide a 2C evaluation (“Sproule 2C Contingent Resource Evaluation”) at Glacier as of March 31, 2013 in accordance to the Canadian Oil and Gas Evaluation Handbook (COGEH) resource definitions that are consistent with the standards of National Instrument 51‐101. The estimates of reserves and resources for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
The following three tables summarize the results of Sproule’s resource assessment of Advantage’s Glacier Montney resources as atMarch 31, 2013:
Resource Categories (AAV Working Interest, Best Estimate, Raw) (1) TcfTotal Petroleum Initially In Place (TPIIP) 16.03Discovered Petroleum Initially in Place (DPIIP) (2) 13.98Undiscovered Petroleum Initially in Place (UPIIP) (3) 2.05
DPIIP (AAV Working Interest, Sales) (2) Low Estimate Best Estimate High EstimateNatural GasCumulative Production (Tcf) (4) 0.100 0.100 0.100Reserves (Tcf) (5) 0.927 1.526 1.770Contingent Resources (Tcf) 2.316 3.540 4.898Unrecoverable DPIIP (Tcf) 9.574 7.751 6.149
Natural Gas LiquidsCumulative Production (mbbls) (4) ‐ ‐ ‐Reserves (mbbls) (5) 5,949 11,071 12,732Contingent Resources (mbbls) 72,472 110,274 152,013Unrecoverable DPIIP (mbbls) 225,654 182,730 139,330
GLACIER CONTINGENT AND PROSPECTIVE RESOURCE ASSESSMENT
33
(1) See Appendix for the definitions from the COGE Handbook of the various resource categories used herein.
(2) There is no certainty that it will be commercially viable to produce any portion of the DPIIP.
(3) There is no certainty that any portion of the UPIIP will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the UPIIP.
(4) The cumulative production represents the actual total historic production from Advantage's Glacier Montney resources and as such is not a Low, Best or High Estimate.
(5) For reserves, the Low Estimate is proved reserves, the Best Estimate is proved plus probable reserves and the High Estimate is proved plus probable plus possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
UPIIP (AAV Working Interest, Sales) (3) Low Estimate Best Estimate High EstimateNatural Gas
Prospective Resources (Tcf) 0.342 0.556 0.776
Unrecoverable UPIIP (Tcf) 1.561 1.347 1.127
Natural Gas Liquids
Prospective Resources (mbbls) 7,381 11,691 16,274
Unrecoverable UPIIP (mbbls) 25,558 21,248 16,665
GLACIER CONTINGENT AND PROSPECTIVE RESOURCE ASSESSMENT
34
2C (Best Estimate) Contingent Resources
IntervalGross Number of Hz
Well Locations
Gross 2C Recoverable Resources per Location(Raw – Bcf per Well)
Net Present Values Before Income Taxes ($ millions)
0% 10% 15%
1 60 3.425 777 46 13
2 286 4.035 6,031 1,791 1,153
3 280 3.120 4,869 565 226
4 260 3.030 4,598 379 127
5 234 4.440 4,135 802 420
Facility Costs N/A N/A (758) (368) (296)
Total 1,120 4,619 $19,652 $3,215 $1,642
Sproule evaluated the economics of Advantage's Best Estimate contingent resources based on a development scenario that was provided by Advantage.
The development plan included the drilling of 1,120 future contingent locations with a total undiscounted capital expenditure of $8.3 billion which includes the necessary facilities and infrastructure costs.
For the evaluation of proved plus probable reserves, the development plan assumed a maximum production rate of 200 mmcf/d is reached in 2015 and maintained until 2026. The proved plus probable reserves evaluation included the drilling of 313 future undeveloped locations with a total undiscounted capital expenditure of $1.9 billion.
In estimating the Glacier contingent resources, Sproule assumed based on Advantage's development plan that gas plant capacity would increase 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 2018. The 600 mmcf/d raw facility throughput capacity was then maintained to the year 2032 by drilling wells as required.
The 2C contingent resources at Glacier are all considered to be Economic Contingent Resources based on the forecast commodity prices, capital costs and operating costs as at March 31, 2013. The crude oil and natural gas pricing assumptions used for the estimate were prepared by Sproule effective March 31, 2013.
GLACIER CONTINGENT AND PROSPECTIVE RESOURCE ASSESSMENT
35
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 demonstratesthat the vast majority of the Montney formation at Glacier has been shown to be productive.
APPENDIX: RESERVE AND RESOURCE DEFINITIONS
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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 generallyaccepted 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 willexceed 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 recoveredwill 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 willexceed 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 andUndiscovered (recoverable and unrecoverable) plus quantities already produced. "Total resources" is equivalent to "Total Petroleum Initially‐In‐Place". Resources areclassified 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 ofpetroleum 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 bediscovered.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 toproduction. 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 technologyor 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 offuture 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 thesequantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovereddue 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 willexceed 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 exceedthe 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 willbe 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 willequal 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 willexceed 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 exceedthe high estimate.
ADVISORY
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Certain statements contained in this presentation constitute forward‐looking statements. These statements relate to future events or our future performance. All statements other thanstatements 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 Glacierand the anticipated production levels and timing thereof; anticipated effect of three year development plan at Glacier on production per share growth and cash flow per share growth,including the Corporation's expectations as to the levels of such growth and the timing of achievement of such levels; number of expected future drilling locations; the Corporation'splans to evaluate additional sections of Montney acreage for prospective natural gas and liquids potential; anticipated effect of production history from recent wells and future welltest results on reserve replacement efficiencies at Glacier; the Corporation’s anticipated drilling and completion plans, including drilling inventory, future locations, additional wellsrequired for three year development plan and available wells after 2017; effect of refinement of drilling and completion techniques; the Corporation's expectations regarding increaseto borrowing base for it credit facilities; anticipated increases to production at Glacier, including Advantage's guidance in respect of anticipated production levels (including thecommodities expected), end of phase production rates, capital expenditures, number and types of wells drilled, wellhead deliverability, commodity prices, funds from operations, bankdebt, funds from operations, and debt to cash flow ratios Phase VII, Phase VIII and Phase IX and Advantage's guidance in respect of capital expenditures and debt to cash flow ratios forthe period from Q2 2017 to Q2 2018; expected continued improvements in cost efficiencies and design changes on drilling and completion plans and well performance; Advantage'sguidance 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 12months 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 toproceed 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 impliedassessment, based on certain estimates and assumptions that the reserves and resources described can be profitably produced in the future. These statements involve substantialknown and unknown risks and uncertainties, certain of which are beyond Advantage's control, including, but not limited to: changes in general economic, market and businessconditions; 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 andchanges in how they are interpreted and enforced; fluctuations in commodity prices and foreign exchange and interest rates; stock market volatility and market valuations; volatility inmarket prices for oil and natural gas; unexpected drilling results, changes in commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debtservice 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 orfluctuations in production levels; delays in anticipated timing of drilling and completion of wells; individual well productivity; competition from other producers; the lack of availabilityof 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 obtainrequired approvals of regulatory authorities; ability to access sufficient capital from internal and external sources. Many of these risks and uncertainties and additional risk factors aredescribed in the Corporation’s Annual Information Form which is available at www.sedar.com and www.advantageog.com. Readers are also referred to risk factors described in otherdocuments Advantage files with Canadian securities authorities. With respect to forward‐looking statements contained in this presentation, Advantage has made assumptionsregarding, 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 orequity 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 operationswill 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, whereapplicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated; and the estimates of the Corporation’s production and reservesvolumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects.
ADVISORY
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Advantage's actual decisions, activities, results, performance or achievement could differ materially from those expressed in, or implied by, such forward‐looking statementsand, 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 benefitsthat Advantage will derive from them. Except as required by law, Advantage undertakes no obligation to publicly update or revise any forward‐looking statements. Foradditional risk factors in respect of Advantage and its business, please refer to it Annual Information Form dated March 27, 2014 which is available on SEDAR atwww.sedar.com and www.advantageog.com.
References in this presentation to initial test production rates, production type curves, initial "productivity", initial "flow" rates, final gas flow rates, average gas flow rates,average type curves, "flush" production rates and "behind pipe production“ 30 day IP rates and other short‐term production rates are useful in confirming the presence ofhydrocarbons, 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 termperformance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Advantage. Apressure 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 beconsidered 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. Theconversion 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 persix 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 tipand 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 significantlydifferent from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
The Corporation discloses several financial measures that do not have any standardized meaning prescribed under International Financial Reporting Standards ("IFRS").These financial measures include funds from operations, total debt to cash flow ratio, and convertible debenture face value outstanding and operating netbacks.Management believes that these financial measures are useful supplemental information to analyze operating performance and provide an indication of the resultsgenerated by the Corporation’s principal business activities. Investors should be cautioned that these measures should not be construed as an alternative to net income, cashprovided by operating activities or other measures of financial performance as determined in accordance with IFRS. Advantage’s method of calculating these measures maydiffer from other companies, and accordingly, they may not be comparable to similar measures used by other companies. Funds from operations, as presented, is based oncash provided by operating activities, adjusted for expenditures on decommissioning liability, changes in non‐cash working capital and interest on bank indebtedness. Totaldebt to cash flow ratio is calculated as indebtedness under Advantage's credit facilities plus working capital deficit divided by funds from operations. Operating netbacks arecalculated 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 andAnalysis, which is available at www.sedar.com and www.advantageog.com for additional information about certain of these financial measures, including a reconciliation offunds from operations to cash provided by operating activities.
ADVISORY
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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 NGLsfor 6 thousand cubic feet of natural gas
bcfe billion cubic feet of natural gas equivalent on the basis of 1 barrel of oil orNGLs 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 6thousand 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 allproperties, due to the effects of aggregation.
This presentation includes calculations of finding and development ("F&D") costs which have been calculated in accordance with Section 5.15 of NI 51‐101 by adding togetherexploration costs, development costs and the change in future development costs and dividing the sum by reserves additions. The aggregate of the exploration and development costsincurred 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 relatedto 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 howAdvantage'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 independentlyverified by Advantage. Readers should not base an investment decision for the securities of such issuers based on the information available herein. Advantage disclaims anyresponsibility 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 drillingopportunities 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 identifiedherein 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 costsassociated with drilling and recompletion identified below are based on Advantage's historical results and analogous public information received from other producers using similartechnologies 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 havebeen provided herein to give an indication of management's assumptions used for budgeting, planning and forecasting purposes. The initial rates of production, reserves and capitalcosts will most likely be different than projected.
ADVANTAGE CONTACT INFORMATION
Investor [email protected]
Listed on NYSE and TSX: AAV
Advantage Oil & Gas Ltd.Suite 300, 440 – 2nd Avenue SWCalgary, Alberta T2P 5E9
Main: 403.718.8000Facsimile: 403.718.8332
Advantage 100% W.I. Glacier Gas Plant
Andy Mah, P.Eng. Director, President & Chief Executive Officer
Craig Blackwood, C.A. VP Finance & Chief Financial Officer