Glacier Montney Outperformance Improves Capital Efficiencies, Enables Lower Capital and Maintains Future Production Growth. Highly Efficient 2014

Transcription

1 Glacier Montney Outperformance Improves Capital Efficiencies, Enables Lower Capital and Maintains Future Production Growth. Highly Efficient 2014 Reserve Additions Reaffirms High Quality Glacier Asset. Investor Presentation TSX / NYSE: AAV March 2015

2 ADVANTAGE: AT A GLANCE Canadian Pure Play Montney Producer Listed on TSX and NYSE AAV TSX 52-week trading range $ $7.85 Shares Outstanding (basic) Glacier Q production (1) Market March 3, 2015 Bank December 31, 2014 (1) (28% drawn on $400 million Credit Facility) Total December 31, 2014 (1) (including working capital deficit) million 134 mmcfe/d (22,352 boe/d) $1.1 billion $110 million $253 million View of Glacier Plant Process Train approximately 650 feet long (1) Year end 2014 financial & operating data are estimates and unaudited. Final audited results are targeted for release March 25,

3 FOCUSED ON MONTNEY GROWTH & VALUE CREATION Growth Plan & Financial Strength World Class Montney Asset Operational Excellence Development Plan 22% Average Annual Production Growth 245 mmcfe/d in 2017 (40,830 boe/d) 27 Employees 3

4 GLACIER OUTPERFORMANCE IMPROVES CAPITAL EFFICIENCIES 100% Owned Facilities & Infrastructure Industry Leading Low Cost Structure Improved Well Performance Growth Maintained with Lower Capital $110 Million (1) Reduction in 2015 Capital Expenditures 18% (1) 2015 Annual Production Growth UNCHANGED 2.1 (2) 2015 Total Debt / Cash Flow at Aeco Cdn $2.50/GJ $150 Million (1) Reduction in 2015 to 2017 Capital Expenditures 22% (1) 2015 through 2017 Annual Average Production Growth - UNCHANGED 1.6 (2) 2015 through 2017 Average Total Debt/Cash Flow at Average Aeco Cdn $2.95/GJ (1) As compared to Advantage s initial development plan estimates (2) Estimated Total Debt including working capital at year end divided by trailing annual cash flow 4

5 2015 CAPITAL PROGRAM HIGHLIGHTS Production Growth Unchanged 36% Increase from 135 mmcfe/d to 183 mmcfe/d in July % Annual production growth (2015/2014) Standing Initial Well Productivity available now to support 2015 production target 160 mmcf/d excess first month well productivity from 16 completed wells of 33 well drilling program and a number of older wells 16 wells will be utilized to increase production to 183 mmcfe/d in July 2015 and maintain until early additional wells already drilled and will be completed and brought on production as required in 2016 Reduced 2015 Capital Requirements due to Improved well performance $110 million reduction from earlier Advantage estimates ($270 million to $160 million) Less wells required in 2015 due to production performance exceeding initial assumptions Glacier Plant Expansion & Flexibility 250 mmcf/d processing capacity in July 2015 (includes 70 mmcf/d spare capacity for future growth) Capable of processing varying amounts of liquids rich gas or dry gas after expansion Hedging 54% hedged (1) at average Aeco Cdn $3.90/mcf for 2015 Total Debt/Cashflow 2.1x Total Debt/Cash flow at average $2.50/GJ gas price assumption for 2015 (1) Percentage of forecast production net of royalties. 5

6 Calendar Production Growth Average Daily Production (mmcfe/d) PLAN GROWTH MAINTAINED AT $150 MILLION LOWER CAPITAL Plan Summary 2015 to 2017 (1) 245 mmcfe/d (40,830 boe/d) in Production Profile 205 mmcfe/d 183 mmcfe/d 245 mmcfe/d $545 million Capital Expenditures mmcfe/d 70 New Montney wells $2.95/GJ AECO Cdn average Plan price 1.6x Average Total Debt to Cash Flow % Calendar Years Production Growth (2) 2015 Hedging % 25% 20% 26% 18% 29% 18% Q % 10% (1) See Plan details in Appendix page 26 (2) 2014 growth calculation based on Glacier production (excludes production from asset dispositions completed in 2013.) 5% 0% (2) Calendar Years 6

7 2015 THROUGH 2017 GROWTH PLAN PRICE SENSITIVITY Downside gas price mitigation while retaining torque to upside 7

8 Millions $ GROWTH PLAN LEADS TO SIGNIFICANT FREE CASH FLOW IN EARLY 2017 $300 Cash flow significantly exceeds maintenance capital each year 245 $3.50/gj generates $130 million free annual cash flow $250 $200 $150 $100 Capital required to grow to 183 mmcfe/d Capital required to grow to 205 mmcfe/d Final Capital required to grow to 245 mmcfe/d $50 $- 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 $2.53/GJ $3.00/GJ $3.30/GJ $3.50/GJ (1) Maintenance Capital Growth Capital Cash Flow (1) Assumed natural gas prices at Aeco Cdn $/GJ in Growth Plan 8

9 Montney Only Focus Industry Leading Low Cost Structure Operational Outperformance Well Performance 100% Owned Facilities 9

10 FOCUSED ON MONTNEY DEVELOPMENT AT GLACIER Current development at Glacier including dry and liquids rich gas drilling Glacier future drilling inventory >1,000 locations New Montney lands at Vahalla, Wembley & Progress contain multiple layers but require evaluation Total 129 net Montney sections (82,560 net acres) Glacier 77 net sections 100% owned Glacier Gas Plant Valhalla Progress 9 net Montney sections acquired net Montney sections acquired 2013 Wembley 10

11 INDUSTRY LEADING COST STRUCTURE & MARGIN Junior E&P 2015e Cost Structure Intermediate/Mid Cap Natural Gas Producers Ranked by Margin (including distributions) Advantage s full cycle margin is among the top Montney producers today. 11

12 STRONG NETBACKS PROVIDE SUSTAINABILITY Glacier Operating Netback Estimated Q (1) ($/mcfe) Illustrative $2.50/mcfe Revenue $3.82 (2) $2.50 Royalties ($0.18) ($0.13) Operating Costs ($0.34) ($0.31) Operating Netback Netback is 86% of $3.30 $2.06 Recycle Ratio at P F&D $1.03/mcfe (3) 3.2x 2.0x G&A ($0.11) ($0.17) Finance Expense ($0.20) ($0.19) Cash Flow Netback Q Operating revenue Q Cash Flow Netback is 78% of revenue $2.99 or $17.94/boe $1.70 or $10.20/boe (1) All references to year end 2014 financial and operating data in this presentation are estimates and are unaudited. Advantage is targeting to report on its audited 2014 financial and operating results after markets on March 25, (2) Revenue includes adjustments for transportation costs and heat value. (3) F&D includes Future Development Capital 12

13 HIGHLY EFFICIENT 2014 MONTNEY RESERVES ADDITIONS 803% Growth 2P Reserves 321% Reserves Replacement (1) 33% Increase in PDP (2) reserves to 279 Bcfe 11% Increase in Proven reserves to 1.2 Tcfe 6% Increase in Proven plus Probable ( 2P ) reserves to 1.8 Tcfe 53% Reduction in 3 year average 2P F&D to $1.03/mcfe 3.2x 2P Recycle Ratio (3) $1.03/mcfe ($6.17/boe) 2P F&D cost (4) $1.03/mcfe ($6.21/boe) Three year average 2P F&D cost (4) (1) Total P reserve additions divided by 2014 annual corporate production (2) Proven developed producing reserves (3) 2014 Q4 operating netback divided by P F&D cost (4) Finding and Development cost including the change in future development capital 13

14 UPPER AND LOWER MONTNEY WELL PERFORMANCE Recent wells completed with slick water and more frac stages are outperforming expectations. No 2014/2015 wells have been brought on-production to date Budget Type Curve (IP mmcf/d & 6.9 Bcf) Data: updated to February

15 2013 SLICKWATER WELLS OUTPERFORM LONG TERM PRODUCTION EXPECTATIONS Recent Upper and Lower Montney wells completed with slickwater fracs are outperforming longer term production expectations. Graph illustrates production from 21 recent Upper & Lower Montney wells Budget Type Curve (IP mmcf/d) mmcf/d & 6.9 Bcf) Data: updated to February

16 EXCEPTIONAL UPPER MONTNEY WELL ECONOMICS (1) Upper Montney Dry Gas (2) Recent average Upper Montney well performance exceeding 7 mmcf/d IP30 (3) (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+ NGL price of $52.39/bbl escalated at 2% 16

17 EXCEPTIONAL LOWER MONTNEY WELL ECONOMICS (1) Lower Montney at 11 bbls/mmcf C3+ (2) Recent Lower Montney wells are at or above 7 mmcf/d IP 30 AECO Gas Price $/mcf (3) (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 $52.39/bbl escalated at 2% 17

18 EAST GLACIER CONTAINS HIGHER MIDDLE MONTNEY LIQUID CONTENT Middle Montney wells to date illustrate higher liquid content from west to east across Glacier Glacier C5+ 57 deg API No Wells Drilled 30 bbl/mmcf 10 bbl/mmcf vertical well C3+ Liquids Yield bbl/mmcf Record Well 100/ w6 13 mmcf/d 42 bbl/mmcf Follow-up Well 100/ w mmcf/d 47 bbl/mmcf 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. 18

19 IMPROVING LIQUIDS RICH MIDDLE MONTNEY WELL PERFORMANCE AT GLACIER New well started production at restricted rate of 9.5 mmcf/d. Currently restricted at 5 mmcf/d after 300 1,075psi Middle Montney wells have sequentially demonstrated improved productivity as we optimize frac design. Recent wells exceeding Budget type curve Middle Montney Budget Type Curve (IP mmcf/d & 4.0 Bcf) Data: updated to Februrary,

20 STRONG EAST GLACIER MIDDLE MONTNEY WELL ECONOMICS (1) Middle Montney at 50 bbls/mmcf C3+ (2) Recent wells are exceeding Budget Type Curve of 4 mmcf/d IP 30 (3) (1) Management estimates. NPV 10% pre-tax (2) Based on $6.4 million per well with 18 frac stages and C3+ NGL yields of 50 bbls/mmcf raw gas (3) Natural gas prices and costs escalated at 2%. Average C3+ Avg NGL price of $52.39/bbl escalated at 2% 20

21 PENTASTACK DEVELOPMENT WITH DECADES OF DRILLING INVENTORY AT GLACIER Five Development Intervals Containing >1,000 Future Locations after undeveloped locations booked in Dec 31, 2014 Reserve Report 65% of unbooked future locations are in the liquids rich Middle Montney intervals 2, 3 and 4 Development based on four wells per section per layer Wells are vertically and laterally offset in each layer for optimal recovery 21

22 GLACIER 100% OWNED GAS PLANT & PIPELINE ACCESS Glacier Gas Plant Positioned for Production Ramp-up Expansion to 250 MMcf/d Dry and Liquid Gas Processing Capability 400 mmcf/d pipeline capacity to TCPL meter station in place 400 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 Advantage s Layered Transportation Contract Strategy since 2008 has created minimal financial exposure 22

23 2015 GUIDANCE 2015 Guidance (1) Average Production (mmcfe/d) % Annual Production growth 18% Exit Production (mmcfe/d) Royalty Rate (%) 4.5% to 5.5% Operating costs ($/mcfe) $0.32 to $0.37 Capital Expenditures ($ Million) $145 to $175 # Wells Drilled 15 (1) Based on an average Aeco Cdn $2.53/GJ natural gas price for

24 ADVANTAGE SUMMARY: GROWING OUR MONTNEY AT GLACIER Focused on World Class Glacier Montney development Improved capital efficiencies lowers capital with unchanged production growth 2015 through 2017 Plan Grows Production to 245 mmcfe/d (40,830 boe/d) 22% Average Annual Production growth (1), 1.6x Average Total Debt to Cash Flow (2) Industry Leading Low Cost Producer with 2014 total cash costs of $0.89/mcfe ($5.34/boe) and P F&D cost of $1.03/mcfe ($6.17/boe) Improved production performance results in Glacier well economics with rates of return exceeding 30% at $2.50/GJ Aeco Cdn natural gas price Financial strength to support capital program Multi-year hedging program & low cost structure strengthens growth plan (1) Assumes an average price of AECO Cdn $2.95/GJ for 2015 through (2) Total debt is estimated at year-end and includes working capital. Cash flow is based on trailing annual estimates. 24

25 APPENDIX 25

26 Calendar Production Growth Average Daily Production (mmcfe/d) FULLY FUNDED GLACIER GROWTH PLAN DETAILS: 22% ANNUAL AVERAGE PRODUCTION GROWTH FOR 2015 TO % 30% 25% 20% 15% 10% 5% 0% Production Profile 245 mmcfe/d 205 mmcfe/d 183 mmcfe/d 135 mmcfe/d Calendar Years (6) Production Growth 29% 26% 18% 18% Calendar Years Development Plan (1) Completed Current Estimate Estimate Production Calendar average (mmcfe/d) growth (2) 26% 18% 29% 18% Exit rate (mmcfe/d) growth 24% 37% 12% 20% Production includes NGLs of 900 bbls/d beginning Q3 15 and increasing to 1,500 bbls/d in Q2 17 Total Wells Commodity Prices (3) NYMEX ($US/mmbtu) $4.41 $2.80 $3.20 $3.50 AECO ($/GJ) $4.26 $2.53 $3.00 $3.30 WTI ($US/bbl) $93.26 $55.00 $62.00 $65.00 Financial Capital ($ millions) $237 $160 $240 $145 Funds from operations ($ millions) $164 $135 $185 $240 per share (4) $0.97 $0.79 $1.10 $1.40 Bank debt ($ millions) (5) $110 $265 $305 $225 multiple of cash flow - trailing 0.7x 2.0x 1.6x 0.9x - forward 0.8x 1.4x 1.3x 0.8x Total debt ($ millions) (5) $253 $278 $333 $238 multiple of cash flow - trailing 1.5x 2.1x 1.8x 1.0x - forward 1.9x 1.5x 1.4x 0.9x Notes (1) All capital and operating input parameters are based on mid-point of estimates. (2) Grow th calculation based on Glacier production (excludes production from asset dispositions completed in 2013). (3) Based on forw ard prices as of Feb.6, (4) Based on million basic common shares outstanding. (5) Estimated bank debt and total debt at the end of each calendar year. Total debt includes bank debt, debentures, and w orking capital. (6) 2014 growth calculation based on Glacier production (excludes production from asset dispositions completed in 2013.) 26

27 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 27

28 Completion Costs/Frac ($MM/frac) TRACK RECORD OF OPERATING PERFORMANCE Production Growth to 135 mmcfe/d & Operating Cost Reduction to ~$0.32/mcfe $472,400/frac stage 77% Reduction in cost per frac in Upper Montney Average number of frac stages from 7 to $107,300/frac stage No wells drilled Phase I Phase II Phase III Phase IV Phase V Phase VI Phase VII 803% Increase in 2P Reserves to 1.8 Tcfe 53% Reduction in 3 Year average 2P F&D cost to $1.03/mcfe 28

29 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 29

30 GLACIER DRILLING ECONOMICS AND 2P RECOVERIES PER INTERVAL ($ millions unless otherwise indicated) Glacier Drilling Economics PV 10% Discount (1) Upper Montney Layer 1 (6) Lower Montney Layer 5 (3) Middle Montney AECO C natural gas price Liquids Rich Gas (East Glacier) (4) ($/mcf) (2) $3.00 $4.00 $5.00 $3.00 $4.00 $5.00 $3.00 $4.00 $5.00 IP30 s and 2P Reserves: 4 mmcf/d & 4 Bcf N/A N/A N/A N/A N/A N/A $3.5 $5.6 $7.3 5 mmcf/d & 5 Bcf $1.5 $4.5 $7.5 $2.0 $4.8 $7.6 $6.0 $8.6 $ mmcf/d & 6 Bcf $3.0 $6.5 $10.0 $3.5 $6.9 $9.9 $8.5 $11.4 $ mmcf/d & 7 Bcf $4.4 $8.6 $11.9 $5.2 $9.1 $11.8 $10.9 $13.9 $ mmcf/d & 8 Bcf $5.9 $10.4 $13.8 $6.8 $10.8 $13.8 $13.0 $16.2 $ mmcf/d & 9 Bcf $7.3 $11.9 $15.7 $8.4 $12.5 $15.7 N/A N/A N/A Glacier - 2P Recoveries per Interval (5) # of Gross HZ Wells 2P Recovery [bcf/well] Interval Developed Undeveloped TOTAL Developed Undeveloped TOTAL YE 2012 YE 2013 YE 2014 YE 2012 YE 2013 YE 2014 YE 2012 YE 2013 YE 2014 YE 2012 YE 2013 YE 2014 YE 2012 YE 2013 YE 2014 YE 2012 YE 2013 YE UM MM MM MM LM Total (1) Management estimates (2) Natural gas prices and costs escalated at 2%. Average C3+ NGL price of $52.39/bbl escalated at 2% (3) Based on $5.8 million per well with 18 frac stages and NGL yields of 11 bbls/mmcf raw gas (4) Based on $6.4 million per well with 18 frac stages and NGL yields of 50 bbls/mmcf raw gas (5) Based on Sproule December 31, 2014 reserves report (6) Based on $5.5 million per well with 18 frac stages and NGL yields of 0 bbls/mmcf raw gas 30

31 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; 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 the development plan and available wells after 2017; effect of refinement of drilling and completion techniques; 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), exit 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; 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, exit production rates, royalty rates, operating costs, capital expenditures and number and types of wells drilled for the development plan; 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. 31

32 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 27, 2014 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, 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 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. Total debt to cash flow ratio is calculated as indebtedness under Advantage's credit facilities plus working capital deficit divided by funds from operations. Operating netbacks are calculated by deducting royalties and operating costs from revenue on a unit (boe or mcfe) basis. Please see the Corporation s most recent Management s Discussion and Analysis, which is available atwww.sedar.com andwww.advantageog.com for additional information about certain of these financial measures, including a reconciliation of funds from operations to cash provided by operating activities. 32

33 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 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. 33

34 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 Advantage 100% W.I. Glacier Gas Plant Main: Facsimile: 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