Advantage Oil & Gas Ltd.
Annual Report 2011

Plain-text annual report

2011 Annual Report Non-Consolidated Financial and Operating Highlights (1) Financial ($000, except as otherwise indicated) Petroleum and natural gas sales Royalties Realized gain on derivatives Operating expense Operating General and administrative (2) Finance expense (3) Miscellaneous income Funds from operations Dividends from Longview Total per share (4) Three months ended December 31, 2011 Three months ended December 31, 2010 Year ended December 31, 2011 Year ended December 31, 2010 $000 per boe $000 per boe $000 per boe $000 per boe $ $ $ $ $ $ $ 23.24 (2.16) 3.49 (4.90) 19.67 (2.12) (1.44) 0.04 16.15 48,293 (4,481) 7,262 (10,191) 40,883 (4,400) (2,984) 88 33,587 4,417 38,004 34.08 (4.32) 4.38 (10.65) 23.49 (2.77) (2.54) (0.02) 18.16 $ 76,221 (9,661) 9,791 (23,811) 52,540 (6,197) (5,679) (36) 40,628 - 40,628 $ $ 241,420 (29,661) 26,916 (59,473) 179,202 (19,497) (17,044) 634 143,295 11,780 155,075 28.26 (3.47) 3.15 (6.96) 20.98 (2.28) (2.00) 0.07 16.77 $ $ $ 0.23 $ 0.25 $ 0.94 $ $ 36.26 (5.22) 5.12 (10.86) 25.30 (2.87) (2.82) 0.06 19.67 $ 319,368 (45,954) 45,133 (95,609) 222,938 (25,316) (24,832) 511 173,301 - $ 173,301 $ 1.06 $ 221,683 $ $ 64,452 290,657 $ 68,029 $ $ 64,452 290,657 $ 199,217 $ $ 70,564 142,548 $ 148,544 $ 86,250 $ 148,544 Expenditures on property, plant and equipment Working capital deficit (5) Bank indebtedness Convertible debentures (face value) Shares outstanding at end of period (000) Basic weighted average shares (000) $ 75,572 $ $ 70,564 142,548 $ 86,250 166,304 166,249 164,092 164,035 127,265 1,378 22,589 Operating Daily Production Natural gas (mcf/d) Crude oil and NGLs (bbls/d) Total boe/d @ 6:1 Average prices (including hedging) Natural gas ($/mcf) Crude oil and NGLs ($/bbl) (1) Non-consolidated financial and operating highlights for Advantage excluding Longview. (2) General and administrative expense excludes non-cash G&A and non-cash share-based compensation. (3) Finance expense excludes non-cash accretion expense. (4) Based on basic weighted average shares outstanding. (5) Working capital deficit includes trade and other receivables, prepaid expenses and deposits, and trade and other accrued liabilities, and the current portion of other liability 106,125 6,620 24,308 $ $ $ $ 3.78 89.14 4.81 64.14 166,304 165,371 123,246 2,864 23,405 164,092 163,467 101,562 7,202 24,129 $ $ 4.19 76.45 $ $ 5.45 61.85 CONTENTS Message to Shareholders ........................................................................................................................................................................................... 3 Reserves ....................................................................................................................................................................................................................... 6 Consolidated Management’s Discussion & Analysis ........................................................................................................................................... 11 Consolidated Financial Statements ........................................................................................................................................................................ 40 Consolidated Statement of Financial Position ............................................................................................................................................. 45 Consolidated Statement of Comprehensive Income (Loss)....................................................................................................................... 46 Consolidated Statement of Changes in Shareholders’ Equity .................................................................................................................... 47 Consolidated Statement of Cash Flows ........................................................................................................................................................ 48 Notes To The Consolidated Financial Statements ...................................................................................................................................... 49 ANNUAL GENERAL AND SPECIAL MEETING Advantage Oil & Gas Ltd. is pleased to invite its shareholders and other interested parties to its Annual General and Special Meeting to be held in the Strand/Tivoli Room at the Metropolitan Centre, 333 – 4th Avenue SW, Calgary, Alberta on Wednesday, May 23, 2012 commencing at 1:30 p.m. We ask those shareholders unable to attend the meeting to please complete and return your Form of Proxy. Advantage Oil & Gas Ltd. - 2 MESSAGE TO SHAREHOLDERS The following Message to Shareholders discusses the non-consolidated financial and operating results for Advantage, excluding Longview. Production Growth, Reduced Costs & Hedging Deliver Solid Financial & Operating Results  Production for the fourth quarter of 2011 averaged 22,589 boe/d (94% natural gas), comparable to the immediate prior quarter. Production in Q4 2011 at Glacier was partially impacted due to facility downtime associated with equipment modifications related to our Phase IV development program. During 2011, production growth at Glacier to 100 mmcf/d substantially offset the sale of approximately 6,000 boe/d of oil assets to Longview Oil Corp. as of April 14, 2011.  Operating costs for the current quarter were $4.90/boe compared to $5.89/boe during the third quarter of 2011. The significant reduction this quarter was primarily the result of a one-time $1.7 million equalization credit related to a gas processing facility. Excluding this equalization, Advantage operating costs are $5.72/boe for Q4 2011 with Glacier operating costs at $1.80/boe.  Advantage’s royalty rate during the fourth quarter of 2011 was 9.3% as compared to 11.4% in the prior quarter. The reduced royalty rate is due to a higher percentage of production from Glacier and lower natural gas pricing.  Funds from operations for Q4 2011 were $33.6 million or $0.20 per share, slightly higher than the third quarter of 2011 despite a 12% reduction in AECO Canadian natural gas prices. Funds from operations for 2011 were $143.3 million or $0.87 per share. Realized hedging gains for Q4 2011 and full year 2011 were $7.3 million and $26.9 million, respectively.  In addition to the funds from operations, Advantage also received tax-free dividend income of $4.4 million this quarter and $11.8 million for 2011 as a result of its 63% ownership in the shares of Longview Oil Corp. (“Longview”).  Capital expenditures for the three months and year ended December 31, 2011 were $77.2 million and $202.1 million, respectively, primarily related to completing Glacier’s Phase III expansion in March 2011 and commencing our Glacier Phase IV expansion program in July 2011. Capital expenditures at Glacier were $178.6 million in 2011.  Bank indebtedness at December 31, 2011 was $142.5 million a decrease of 51% since December 31, 2010 primarily due to proceeds received from the sale of certain oil-weighted assets to Longview and cash flow from operating activities. Bank indebtedness increased during Q4 2011 predominantly due to two convertible debentures that matured in December 2011 for the sum of $62.3 million. We have one remaining convertible debenture outstanding for $86.2 million that will mature in January 2015.  Bank debt to annualized cash flow at the end of the fourth quarter is 1.1x and 1.7x including convertible debentures. Bank indebtedness is expected to increase during the remainder of our budget cycle as we continue with capital activity during H1 2012.  Advantage retains balance sheet flexibility at December 31, 2011 with an undrawn credit facility of $132.5 million and a 63% ownership in the shares of Longview which had an asset value of $298 million at December 31, 2011. Glacier – Montney Potential Enhanced with Discovery of Natural Gas Liquids & Significant Increase in Reserves & Resource Potential (refer to Advantage press release dated March 15, 2012 and the Sproule Resource Assessment)  Our Phase IV drilling program began in late July 2011 and included drilling 22 gross (21.5 net) Upper Montney wells and 7 gross (7 net) “evaluation wells” to investigate additional layers of Montney potential specifically in the Middle Montney and to test new completion techniques in the Lower Montney. Advantage Oil & Gas Ltd. - 3  To date, evaluation in the Middle Montney has revealed natural gas liquids (“NGL’s”) potential in 3 separate layers. Four horizontal wells have been tested and demonstrated well production test rates between 1.1 to 4.4 mmcf/d at an average flowing pressure of 350 psi (calculated at the end of each 90 hour flow test). Significant natural gas liquids content was observed in the gas analyses and free condensate was noted on flow back from 3 of the 4 wells. Liquid yields are internally estimated to range from 25 bbls/mmcf to 50 bbls/mmcf assuming a shallow cut refrigeration process. Liquid yields can be increased through construction of a higher cost facility which involves a deep cut liquids extraction process. We estimate liquid yields would increase to the range of 57 bbls/mmcf to 90 bbls/mmcf assuming a deep cut liquids extraction process. The propane, butane and condensate components are estimated to comprise 46% to 60% of the liquid yield in a deep cut liquids extraction process.  We caution that we are very early in this evaluation and more delineation and analysis will have to be undertaken in order to ascertain the drilling economics of the three Middle Montney layers. However, our low operating cost and royalty structure at Glacier could provide significant benefits to reduce threshold economics in support of a potential liquids rich Middle Montney program. Several options are available for liquids processing including undertaking modifications at our existing Glacier gas plant, accessing the nearby Alliance pipeline which accommodates NGL’s or use of current pipeline interconnections to a third party deep cut facility which has spare processing capacity.  The discovery of NGL’s in the Middle Montney along with the recognition of additional contingent & prospective resources in the Upper, Middle and Lower Montney have significantly enhanced the resource potential as recognized in Sproule’s updated Glacier Montney Resource Assessment as of February 29, 2012.  Sproule’s updated Glacier Montney resource assessment resulted in a 320% increase in the Total Petroleum Initially in Place (“TPIIP”) to 10 Tcf gross raw (9.33 Tcf raw AAV working interest) and identified substantial contingent and prospective resources in six layers within our Montney formation. The 2P reserves plus contingent resource best estimate increased by 90% to 2.49 TCF which represents only 27% of the TPIIP as compared to our year end 2011 2P Montney reserves of 1.096 Tcf which represents only 12% of the TPIIP.  In the Middle Montney, Sproule assigned a contingent resource 0.61 Tcf (best estimate) which previously had no assignment. In addition, Sproule also identified NGL’s Initially In Place (“NGLIIP”) of 156.34 million bbls and an ultimate recoverable resource best estimate of 50.8 million bbls based on an estimated liquid yield of 32 to 40 bbls/mmcf for the Middle Montney formation.  Our high quality asset at Glacier contains significant scope and scale as validated by Sproule’s resource assessment and is underpinned with one of the lowest cost structures in Western Canada which provides Advantage with a significant drilling inventory. Our recent drilling which involved lateral and vertical delineation through the very thick Montney formation across our contiguous land block has added another dimension to Glacier, specifically with the Middle Montney. We estimate that the current drilling inventory at Glacier to be in excess of 900 wells which only includes development of 3 layers in the Montney formation. Looking Forward – Glacier Phase IV Production Ramp-up Deferred Due to Low Natural Gas Prices  Our capital budget for the twelve month period ending June 30, 2012 was set at $216 million of which $200 million is focused on a Phase IV development program at Glacier with two key objectives: i) increase throughput capacity at our Glacier gas plant from 100 mmcf/d to 140 mmcf/d by the second quarter of 2012 and ii) further evaluate the Middle and Lower Montney formations.  To date, we have drilled 29 gross (28.5 net) Montney horizontal wells at Glacier as part of our Phase IV capital program and have recently began delineation in the Middle Montney which has revealed the potential for natural gas liquids. Current behind pipe volumes are estimated to be 37 mmcf/d including wells that have been tested and existing wells that are currently restricted as a result of our 100 mmcf/d Glacier gas plant capacity. An additional 14 Montney wells have been drilled and are awaiting completion. Advantage Oil & Gas Ltd. - 4  As a result of the prevailing low natural gas pricing environment, production at Glacier will be maintained between 90 mmcf/d to 100 mmcf/d until we see a sustained increase in natural gas pricing. We will utilize our inventory of 29 gross (28.5 net) Montney wells that have been drilled to maintain targeted production rates at Glacier by producing and/or completing these wells as required. Additionally, we believe that the high industry activity levels that have increased service and supply costs could subside during the latter part of 2012 which would benefit natural gas development economics.  We believe that it is prudent to maintain capital spending discipline and financial flexibility in this current natural gas price environment. We also believe that the current price of natural gas is unsustainable for generating sufficient full cycle economic returns in the vast majority of North American natural gas plays and anticipate an improvement in the natural gas price environment. As a result, we are positioning our Glacier gas plant with the capability to ramp up production capacity to 140 mmcf/d by completing modifications as planned in our Phase IV capital program.  At this time, we are providing interim guidance for the six months ending June 30, 2012: Production average 22,800 boe/d to 23,400 boe/d Royalty rate 8% to 10% Operating expense $5.70/boe to $6.00/boe Capital expenditures $65 million to $75 million  Additional capital budget and guidance details will be provided pending our evaluation of future delineation plans for our liquids rich Middle Montney formation in order to determine the natural gas and NGL production and reserves potential. This evaluation will include detailed analysis and interpretation of recent geological, engineering and completions data which we obtained from our Middle Montney Phase IV wells. In addition, we have 1 remaining Middle Montney well and 2 Lower Montney wells that are drilled and are awaiting completion which we anticipate undertaking after spring break-up. We expect the results of this information and our evaluation to provide more information in regard to determining a systematic delineation plan for the balance of 2012 and beyond.  We will continue with a technically focused and financially disciplined approach to create value from our Glacier property and will revisit our 2012 capital spending plans as required taking into account commodity price and market dynamics. Advantage Oil & Gas Ltd. - 5 Reserves Advantage engaged our independent qualified reserves evaluator Sproule Associates Ltd. (“Sproule”) to update the reserves analysis for the Company (the “Sproule Report”) in accordance with National Instrument 51-101 (“NI 51-101”) and the COGE Handbook. The Sproule Report includes only Advantage’s “stand-alone” reserves and excludes the assets in Longview Oil Corp. Reserves and production information included herein is stated on a Company Interest basis (before royalty burdens and including royalty interests receivable) unless noted otherwise. This summary contains several cautionary statements that are specifically required by NI 51-101. In addition to the detailed information disclosed in this annual report more detailed information on a net interest basis (after royalty burdens and including royalty interests) and on a gross interest basis (before royalty burdens and excluding royalty interests) is included in Advantage's Annual Information Form ("AIF") and is available at www.advantageog.com and www.sedar.com. Note that the December 31, 2010 figures below include the assets sold to Longview Oil Corp. on April 14, 2011. Highlights - Company Interest Reserves (Working Interests plus Royalty Interests Receivable) December 31, 2011 December 31, 2010 Proved plus probable reserves (mboe) 218,386 Present Value of 2P reserves discounted at 10%, before tax ($000)(1) $1,483,679 $9.35 Net Asset Value per Share discounted at 10%, before tax (2) 26.4 Reserve Life Index (proved plus probable - years) (3) 1.31 Reserves per Share (proved plus probable) (2) $0.66 Bank debt per boe of reserves (4) $0.40 Convertible debentures per boe of reserves (4) 244,291 $2,515,972 $13.63 27.5 1.48 $1.18 $0.61 (1) Assumes that development of each property will occur, without regard to the likely availability to the Company of funding required for that development. (2) Based on 166.304 million Shares outstanding at December 31, 2011, and 164.092 million Shares outstanding as December 31, 2010. (3) Based on Q4 average production and company interest reserves. (4) Using boe's may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion ratio for natural gas of 6 mcf: 1 bbl has been used which 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. Company Interest Reserves (Working Interests plus Royalty Interests Receivable) Summary as at December 31, 2011 Light & Medium Oil (mbbl) Heavy Oil (mbbl) Natural Gas Liquids (mbbl) Oil Natural Gas Equivalent (mboe) (mmcf) Proved Developed Producing Developed Non-producing Undeveloped Total Proved Probable Total Proved + Probable 1,458 38 48 1,544 898 2,442 19 - - 19 10 29 2,407 7 297 2,711 1,177 3,888 245,879 17,371 556,097 819,347 452,822 1,272,169 44,863 2,941 93,028 140,832 77,554 218,386 Advantage Oil & Gas Ltd. - 6 Gross Working Interest Reserves (Working Interest only) Summary as at December 31, 2011 Light & Medium Oil (mbbl) Heavy Oil (mbbl) Natural Gas Liquids (mbbl) Oil Natural Gas Equivalent (mboe) (mmcf) Proved Developed Producing Developed Non-producing Undeveloped Total Proved Probable Total Proved + Probable 1,375 38 48 1,461 870 2,331 6 - - 6 5 11 2,374 7 297 2,678 1,165 3,843 244,430 17,259 556,092 817,781 452,262 1,270,043 44,493 2,922 93,027 140,442 77,416 217,858 Present Value of Future Net Revenue using Sproule price and cost forecasts (1)(2) ($000) Proved Developed Producing Developed Non-producing Undeveloped Total Proved 0% $737,412 64,615 1,545,887 2,347,914 Probable Total Proved + Probable 2,227,996 $4,575,910 Before Income Taxes Discounted at 10% 15% $476,330 35,282 399,105 910,718 572,961 $1,483,679 $404,290 28,459 198,522 631,272 367,629 $998,900 (1) Advantage’s crude oil, natural gas and natural gas liquid reserves were evaluated using Sproule’s product price forecast effective December 31, 2011 prior to the provision for income taxes, interests, debt services charges and general and administrative expenses. It should not be assumed that the discounted future revenue estimated by Sproule represents the fair market value of the reserves. (2) Assumes that development of each property will occur, without regard to the likely availability to the Company of funding required for that development. Sproule Price Forecasts The present value of future net revenue at December 31, 2011 was based upon crude oil and natural gas pricing assumptions prepared by Sproule effective December 31, 2011. These forecasts are adjusted for reserve quality, transportation charges and the provision of any applicable sales contracts. The price assumptions used over the next seven years are summarized in the table below: Year 2012 2013 2014 2015 2016 2017 2018 WTI Edmonton Light Alberta AECO-C Natural Gas ($Cdn/mmbtu) 3.16 3.78 4.13 5.53 5.65 5.77 5.89 Crude Oil ($Cdn/bbl) 96.87 93.75 90.89 96.23 98.16 100.12 102.12 Crude Oil ($US/bbl) 98.07 94.90 92.00 97.42 99.37 101.35 103.38 Henry Hub Exchange Rate Natural Gas ($US/mmbtu)($US/$Cdn) 1.012 3.55 1.012 4.18 1.012 4.54 1.012 5.95 1.012 6.07 1.012 6.19 1.012 6.32 Advantage Oil & Gas Ltd. - 7 Net Asset Value using Sproule price and cost forecasts (Before Income Taxes) The following net asset value ("NAV") table shows what is normally referred to as a "produce-out" NAV calculation under which the current value of the Company’s reserves would be produced at forecast future prices and costs. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. Before Income Taxes Discounted at ($000, except per Share amounts) Net asset value per Share (1) - December 31, 2010 Present value proved and probable reserves Undeveloped acreage and seismic (2) Working capital (deficit) and other Convertible debentures Bank debt Longview shares at market value Net asset value - December 31, 2011 Net asset value per Share (1) - December 31, 2011 0% $38.70 $4,575,910 71,630 (70,564) (86,250) (141,705) 298,034 $4,647,055 $27.94 10% $13.63 $1,483,679 71,630 (70,564) (86,250) (141,705) 298,034 15% $9.33 $998,900 71,630 (70,564) (86,250) (141,705) 298,034 $1,554,824 $1,070,045 $9.35 $6.43 (1) Based on 166.304 million Shares outstanding at December 31, 2011, and 164.092 million Shares outstanding at December 31, 2010. (2) Internal estimate Gross Working Interest Reserves Reconciliation Proved Opening balance Dec. 31, 2010 Extensions Improved recovery Infill Drilling Discoveries Economic factors Technical revisions Acquisitions Dispositions Production Light & Medium Oil (mbbl) 13,862 28 - 1 - 8 63 - (12,277) (224) Heavy Oil (mbbl) 1,654 - - - - (2) (26) - (1,619) (1) Natural Gas Liquids (mbbl) 5,181 1 - 8 - (129) (575) 1 (1,463) (346) Natural Oil Gas Equivalent (mboe) 143,371 2,067 - 2,645 - (3,445) 23,681 4 (19,985) (7,896) (mmcf) 736,040 12,227 - 15,819 - (19,932) 145,316 19 (27,756) (43,952) Closing balance at Dec. 31, 2011 1,461 6 2,678 817,781 140,442 Advantage Oil & Gas Ltd. - 8 Gross Working Interest Reserves Reconciliation (continued) Proved + Probable Opening balance Dec. 31, 2010 Extensions Improved recovery Infill Drilling Discoveries Economic factors Technical revisions Acquisitions Dispositions Production Light & Medium Oil (mbbl) 24,044 38 - 2 - 24 (438) - (21,115) (224) Heavy Oil (mbbl) 4,487 - - - - 8 (61) - (4,422) (1) Natural Gas Liquids (mbbl) 7,796 2 - 11 - (151) (1,007) 1 (2,463) (346) Natural Oil Gas Equivalent (mboe) 243,656 4,931 - 3,470 - (3,603) 13,766 5 (36,471) (7,896) (mmcf) 1,243,969 29,346 - 20,747 - (20,900) 91,631 27 (50,825) (43,952) Closing balance at Dec. 31, 2011 2,331 11 3,843 1,270,043 217,858 Finding, Development & Acquisitions Costs (“FD&A”) (1)(2)(3) 2011 FD&A Costs – Gross Working Interest Reserves excluding Future Development Capital Capital expenditures ($000) Acquisitions net of dispositions ($000) Total capital ($000) Total mboe, end of year Total mboe, beginning of year Production, mboe Reserve additions, mboe 2011 FD&A costs ($/boe) 2010 FD&A costs ($/boe) Three year average FD&A costs ($/boe) 2011 F&D costs ($/boe) 2010 F&D costs ($/boe) Three year average F&D costs ($/boe) Proved $202,148 (547,007) $(344,859) 140,442 143,371 7,896 4,967 $(69.42) $3.47 $(4.05) $8.10 $4.60 $5.51 Proved + Probable $202,148 (547,007) $(344,859) 217,858 243,656 7,896 (17,902) $19.27 $7.61 $(3.74) $10.89 $8.46 $4.23 Advantage Oil & Gas Ltd. - 9 NI 51-101 2011 FD&A Costs – Gross Working Interest Reserves including Future Development Capital Capital expenditures ($000) Acquisitions net of dispositions ($000) Net change in Future Development Capital ($000) Total capital ($000) Reserve additions, mboe 2011 FD&A costs ($/boe) 2010 FD&A costs ($/boe) Three year average FD&A costs ($/boe) 2011 F&D costs ($/boe) 2010 F&D costs ($/boe) Three year average F&D costs ($/boe) Proved $202,148 (547,007) 42,053 $(302,806) 4,967 $(60.95) $11.06 $8.46 $9.79 $11.55 $13.10 Proved + Probable $202,148 (547,007) (37,932) $(382,791) (17,902) $21.38 $10.89 $7.51 $8.85 $10.97 $9.90 (1) Under NI 51-101, the methodology to be used to calculate FD&A costs includes incorporating changes in future development capital ("FDC") required to bring the proved undeveloped and probable reserves to production. For continuity, Advantage has presented herein FD&A costs calculated both excluding and including FDC. (2) 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 reserves additions for that year. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect Sproule’s best estimate of what it will cost to bring the proved undeveloped and probable reserves on production. (3) In all cases, the FD&A number is calculated by dividing the identified capital expenditures by the applicable reserve additions. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 MCF:1 BBL is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Advantage Oil & Gas Ltd. - 10 Consolidated Management’s Discussion & Analysis The following Management’s Discussion and Analysis (“MD&A”), dated as of March 23, 2012, provides a detailed explanation of the consolidated financial and operating results of Advantage Oil & Gas Ltd. (“Advantage”, the “Corporation”, “us”, “we” or “our”) for the three months and year ended December 31, 2011 and should be read in conjunction with the December 31, 2011 audited consolidated financial statements. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) and all references are to Canadian dollars unless otherwise indicated. The term "boe" or barrels of oil equivalent may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil 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. Non-GAAP Measures The Corporation discloses several financial measures in the MD&A that do not have any standardized meaning prescribed under GAAP. These financial measures include funds from operations and cash 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 prior to the consideration of how these activities are financed or how the results are taxed. Investors should be cautioned that these measures should not be construed as an alternative to net income, comprehensive income, cash provided by operating activities or other measures of financial performance as determined in accordance with GAAP. 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 before expenditures on decommissioning liability and changes in non-cash working capital reduced for finance expense excluding accretion. Cash netbacks are dependent on the determination of funds from operations and include the primary cash sales and expenses on a per boe basis that comprise funds from operations. Funds from operations reconciled to cash provided by operating activities is as follows: Three months ended December 31 Year ended December 31 ($000) Cash provided by operating activities Expenditures on decommissioning liability Changes in non-cash working capital Finance expense (1) Funds from operations (1) Finance expense excludes non-cash accretion expense. Creation of Longview Oil Corp. $ $ $ $ 2011 79,932 761 (21,922) (4,137) 54,634 2010 60,964 1,811 (16,468) (5,679) 40,628 % change 31 % (58) % 33 % (27) % 34 % 2011 218,181 3,335 (4,131) (20,354) 197,031 2010 222,866 6,275 (31,008) (24,832) 173,301 % change (2) % (47) % (87) % (18) % 14 % $ $ $ $ On April 14, 2011, Advantage’s wholly-owned subsidiary, Longview Oil Corp. (“Longview”), completed its initial public offering (the “Offering”) at a price of $10 per common share issuing 17,250,000 common shares and raising gross proceeds of $172.5 million (including full exercise of the over-allotment option on April 28, 2011). Concurrent with the closing of the Offering, Longview purchased certain oil-weighted assets (the “Acquired Assets”) from Advantage for total consideration of $546.9 million, comprised of 29,450,000 common shares of Longview representing a 63% equity ownership and $252.4 million in cash (the “Acquisition”). The Acquired Assets were purchased with an effective date of January 1, 2011 and a closing date of April 14, 2011. As Advantage is the parent company and has a majority ownership interest of Longview, the financial and operating results of Longview are consolidated 100% within Advantage and non-controlling interest has been recognized which represents Longview’s independent shareholders 37% ownership interest in the net assets and income of Longview. Refer to the MD&A section “Supplementary Financial and Operating information for Advantage and Longview” which provides detailed financial and operational information with respect to the separate legal entities. As the Acquisition closed on April 14, 2011, financial and operating results from the Acquired Assets belong to Advantage for the period prior to April 14, 2011 and are solely attributed to Advantage’s shareholders. For the period from April 14 to December 31, 2011, the financial and operating results from the Acquired Assets belong to Longview and are attributed to Longview’s shareholders based on their ownership interests. Advantage Oil & Gas Ltd. - 11 Upon closing of the Acquisition, Advantage entered into a Technical Services Agreement (the “TSA”) with Longview. Under the TSA, Advantage will provide the necessary personnel and technical services to manage Longview's business and Longview will reimburse Advantage on a monthly basis for its share of administrative charges based on respective levels of production. Longview has an independent board of directors with three initial members. The officers of Longview provide services to Longview under the TSA but remain employees of Advantage. Supplementary Financial and Operating Information for Advantage and Longview The following information has been presented to provide additional information with respect to the legal entity financial and operating information for each of Advantage and Longview. As the Acquisition closed on April 14, 2011, financial and operating results from the Acquired Assets belong to Advantage for the period prior to April 14, 2011 and are solely attributed to Advantage’s shareholders. For the period from April 14 to December 31, 2011, the financial and operating results from the Acquired Assets belong to Longview and are attributed to Longview’s shareholders based on their ownership interests. Production Natural gas (mcf/d) Crude oil (bbls/d) NGLs (bbls/d) Total (boe/d) Natural gas (%) Crude oil (%) NGLs (%) Natural Gas Prices ($/mcf) Realized natural gas prices Excluding hedging Including hedging Crude Oil and NGLs Prices ($/bbl) Realized crude oil prices Excluding hedging Including hedging Realized NGLs prices Excluding hedging Realized crude oil and NGLs prices Excluding hedging Including hedging Cash netbacks ($/boe) Petroleum and natural gas sales Royalties Realized gain (loss) on derivatives Operating expense Operating General and administrative expense (2) Finance expense (3) Miscellaneous income Cash netbacks Three months ended December 31, 2011 Year ended December 31, 2011 Advantage Longview Consolidated Advantage Longview (1) Consolidated 127,265 630 748 22,589 94% 3% 3% 10,215 4,552 568 6,823 25% 67% 8% 137,480 5,182 1,316 29,411 78% 18% 4% 123,246 1,746 1,118 23,405 88% 7% 5% 9,514 4,131 559 6,276 25% 66% 9% 130,075 4,711 1,519 27,909 78% 17% 5% $ $ 3.16 3.78 $ $ 3.47 3.47 $ $ 3.18 3.76 $ $ 3.55 4.19 $ $ 3.81 3.81 $ $ 3.57 4.17 $ $ 91.40 91.40 $ $ 89.05 87.37 $ $ 89.34 87.86 $ $ 85.68 82.95 $ $ 87.81 86.81 $ $ 87.02 85.38 $ 87.23 $ 66.05 $ 78.09 $ 66.31 $ 63.77 $ 65.64 $ $ 89.14 89.14 $ $ 86.50 85.01 $ $ 87.06 85.88 $ $ 78.12 76.45 $ $ 84.95 84.06 $ $ 81.81 80.56 $ $ $ $ $ $ 23.24 (2.16) 3.49 (4.90) 19.67 (2.12) (1.44) 0.04 16.15 70.11 (14.11) (1.12) (18.36) 36.52 (1.15) (1.84) - 33.53 34.11 (4.93) 2.42 (8.03) 23.57 (1.89) (1.53) 0.03 20.18 28.26 (3.47) 3.15 (6.96) 20.98 (2.28) (2.00) 0.07 16.77 69.26 (14.18) (0.66) (18.06) 36.36 (1.67) (2.01) 0.01 32.69 34.88 (5.20) 2.54 (8.75) 23.47 (2.18) (2.00) 0.06 19.35 $ $ $ $ $ $ (1) The year ended December 31, 2011 represents Longview's financial and operating results for the period from April 14 to December 31, 2011. (2) General and administrative expense excludes non-cash G&A and non-cash share-based compensation expense. (3) Finance expense excludes non-cash accretion expense. Advantage Oil & Gas Ltd. - 12 ($000, except as otherwise indicated) Sales including realized hedging Natural gas sales Realized hedging gains Natural gas sales including hedging Crude oil and NGLs sales Realized hedging losses Crude oil and NGLs sales including hedging Total per boe Royalties per boe As a percentage of petroleum and natural gas sales Operating expense per boe General and administrative expense (2) per boe Three months ended December 31, 2011 Year ended December 31, 2011 Advantage Longview Consolidated Advantage Longview (1) Consolidated $ 36,986 7,262 44,248 11,307 - $ 3,263 - 3,263 40,744 (704) $ 40,249 7,262 47,511 52,051 (704) $ 159,774 28,657 188,431 81,646 (1,741) $ 9,500 - 9,500 104,368 (1,090) $ 169,274 28,657 197,931 186,014 (2,831) 11,307 55,555 26.73 $ $ 40,040 43,303 68.99 $ $ 51,347 98,858 36.53 $ $ 79,905 268,336 31.41 $ $ 103,278 112,778 68.60 $ $ 183,183 381,114 37.42 $ $ $ $ 4,481 2.16 9.3% $ $ 8,858 14.11 20.1% $ $ 13,339 4.93 14.5% $ $ 29,661 3.47 12.3% $ $ 23,310 14.18 20.5% $ $ 52,971 5.20 14.9% $ $ 10,191 4.90 $ $ 11,526 18.36 $ $ 21,717 8.03 $ $ 59,473 6.96 $ $ 29,693 18.06 $ $ 89,166 8.75 $ $ 4,400 2.12 $ $ 719 1.15 $ $ 5,119 1.89 $ $ 19,497 2.28 $ $ 2,742 1.67 $ $ 22,239 2.18 Interest on bank indebtedness per boe $ $ 989 0.48 $ $ 1,153 1.84 $ $ 2,142 0.79 $ $ 8,173 0.96 $ $ 3,310 2.01 $ $ 11,483 1.13 Interest on convertible debentures per boe Miscellaneous income per boe Funds from operations per boe per share (3) (4) Dividends from Longview (declared by Longview) $ $ 1,995 0.96 $ - $ - $ $ 1,995 0.74 $ $ 8,871 1.04 $ - $ - $ $ 8,871 0.87 $ $ 88 0.04 $ - $ - $ $ 88 0.03 $ $ 634 0.07 $ $ 13 0.01 $ $ 647 0.06 $ $ $ 33,587 16.15 0.20 $ $ $ 21,047 33.53 0.45 $ $ $ 54,634 20.18 0.28 $ $ $ 143,295 16.77 0.87 $ $ $ 53,736 32.69 1.61 $ $ $ 197,031 19.35 1.07 $ 4,417 $ (7,012) $ (2,595) $ 11,780 $ (18,695) $ (6,915) Expenditures on property, plant and $ 75,572 $ 25,625 $ 101,197 $ 199,217 $ 54,957 $ 254,174 equipment Expenditures on exploration and 1,604 $ 20 1,624 2,930 76 3,006 evaluation assets Total capital spending Debt and working capital Bank indebtedness Convertible debentures Working capital deficit $ 77,176 $ 25,645 $ 102,821 $ 202,147 $ 55,033 $ 257,180 $ $ $ 142,548 86,250 70,564 91,355 $ $ - $ 20,074 $ $ $ 233,903 86,250 90,638 (1) The year ended December 31, 2011 represents Longview's financial and operating results for the period from April 14 to December 31, 2011. (2) General and administrative expense excludes non-cash G&A and non-cash share-based compensation expense. (3) Based on basic weighted average shares outstanding applicable to each legal entity. (4) Consolidated funds from operations per share excludes funds from operations attributable to the non-controlling interest of Longview. Advantage Oil & Gas Ltd. - 13 Transition to International Financial Reporting Standards The consolidated financial statements, MD&A and comparative information have been prepared in accordance with IFRS representing generally accepted accounting principles (“GAAP”) for publicly accountable enterprises in Canada. The transition date to IFRS was January 1, 2010 and comparative figures for 2010 and Advantage’s financial position as at January 1, 2010 have been restated to IFRS from the previous Canadian generally accepted accounting principles (“Previous GAAP”). Reconciliations to IFRS from Previous GAAP financial statements including the impact of the transition on the Corporation's reported financial position and financial performance, and the nature and effect of significant changes in accounting policies from those used in the Corporation’s Previous GAAP consolidated financial statements for the year ended December 31, 2010, are summarized in note 25 to the audited consolidated financial statements. Forward-Looking Information This MD&A contains certain forward-looking statements, which are based on our current internal expectations, estimates, projections, assumptions and beliefs. 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", "would" and similar or related expressions. These statements are not guarantees of future performance. In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to terms of the TSA with Longview; effect of commodity prices on the Corporation's Corporation’s financial condition and performance, including cash provided by operating activities, funds from operations, net income and comprehensive income; industry conditions; effect of commodity prices on sales, drilling activity and supply levels; effect of derivative contracts on sales and cash flows; the Corporation's hedging strategy; effect of the Corporation's risk management activities; expected effect on production from the completion of facilities and infrastructure expansion work in Glacier, Alberta; expected production from the Glacier development; projected royalty rates; average royalty rates; terms of the Plans and the grants of restricted shares; terms of the convertible debentures; the Corporation's estimated tax pools; timing of expiry of federal non-capital loss carry forward; future commitments and contractual obligations; effect of changes in reserves estimates or commodity prices on the borrowing base of the Credit Facilities (as defined herein); terms of the Credit Facilities, including Management's expectations regarding extension of the term of the Credit Facilities; the Corporation's plans for managing its capital structure; the Corporation's ability to satisfy all liabilities and commitments as they come due; our future operating and financial results; supply and demand for oil and natural gas; projections of market prices and costs; effect of natural gas, oil prices and exchange rates on the Corporation's financial performance; the Corporation’s exploration and drilling plans; focus of spending and capital budgets; capital expenditure programs; the focus and anticipated timing of capital expenditures; plans for development of the Middle and Lower Montney; projected average production; anticipated timing of incremental production; expected exit rate production for Longview; the Corporation's business strategy and it plans for its assets; Longview's business strategy; the performance characteristics of our properties; and the amount of general and administrative expenses. 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 resources and reserves described can be profitably produced in the future. These forward-looking statements involve substantial known and unknown risks and uncertainties, many of which are beyond our control, including, but not limited to, changes in general economic, market and business conditions; stock market volatility; changes to legislation and regulations and how they are interpreted and enforced; changes to investment eligibility or investment criteria; our ability to comply with current and future environmental or other laws; actions by governmental or regulatory authorities including increasing taxes, changes in investment or other regulations; changes in tax laws, royalty regimes and incentive programs relating to the oil and gas industry; the effect of acquisitions; our success at acquisition, exploitation and development of reserves; unexpected drilling results, changes in commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties; 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; competition from other producers; the lack of availability of qualified personnel or management; individual well productivity; ability to access sufficient capital from internal and external sources; credit risk; and the risks and uncertainties are described 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 other documents Advantage files with Canadian securities authorities. Advantage Oil & Gas Ltd. - 14 With respect to forward-looking statements contained in this MD&A, 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; availability of skilled labour; availability of drilling and related equipment; timing and amount of capital expenditures; the impact of increasing competition; the price of 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 oil and gas properties in the manner currently contemplated; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; 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. Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide shareholders with a more complete perspective on Advantage's future operations and such information may not be appropriate for other purposes. Advantage’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Advantage will derive there from. Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this MD&A and Advantage disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. Advantage Oil & Gas Ltd. - 15 Overview Cash provided by operating activities ($000) Funds from operations ($000) per share (1) per boe Three months ended December 31 Year ended December 31 2011 2010 % change 2011 2010 % change $ $ $ $ 79,932 54,634 0.28 20.18 $ $ $ $ 60,964 40,628 0.25 18.16 31 34 12 11 % % % % $ $ $ $ 218,181 197,031 1.07 19.35 $ $ $ $ 222,866 173,301 1.06 19.67 % (2) 14 % % 1 % (2) (1) Based on basic weighted average shares outstanding and excludes funds from operations attributable to the non-controlling interest of Longview. Funds from operations for 2011 have been strong, driven by increases in production and continued gains from our hedging program, which demonstrates the clear ongoing improvement in our financial and operating results from our focused development program. Average daily production during the fourth quarter of 2011 increased 21% above the same period of 2010, with a 30% increase in natural gas production and a 6% increase in crude oil production, partially offset by a 24% decrease NGLs production. For the three months ended December 31, 2011, we recognized a net realized derivative gain of $6.6 million and for the year ended December 31, 2011, we recognized a net realized derivative gain of $25.8 million on settled derivative contracts, primarily as a result of lower average actual natural gas prices during the periods as compared to our established average hedge prices. Our successful commodity price risk management program continued to realize significant gains on derivatives during 2011 that has helped to offset the continued weak natural gas prices and positively impact funds from operations. Our net realized derivative gain has decreased during 2011 as compared to 2010 as we had less natural gas production hedged for this year at lower average prices and we have generally realized losses on our crude oil hedges. Funds from operations have also benefited during this year from higher crude oil prices and continued cost reductions, such as operating costs, general and administrative expense, and finance expense. Unfortunately, natural gas prices still remain weak and pose a continuing challenge to the entire natural gas industry. When comparing the current quarter to the third quarter of 2011, our funds from operations increased 9% and funds from operations per boe were 6% higher as realized crude oil and NGL prices increased during this quarter and general costs continued to decrease, including operating costs. Our financial and operating results during 2011 as compared to 2010 have been partially impacted by dispositions completed during the second quarter of 2010. On May 31 and June 3, 2010, we closed two asset dispositions of non-core natural gas weighted properties for net proceeds of $66.5 million and representing production of approximately 1,700 boe/d. The net proceeds from the various dispositions were utilized to reduce outstanding debt. As a result of the dispositions, total funds from operations was negatively impacted for 2011 as compared to 2010 with all sales and expenses generally impacted. As a result of asset dispositions completed in 2010 and 2011 and changes in commodity prices, historical financial and operating performance may not be indicative of actual future performance. The primary factor that causes significant variability of the Corporation’s cash provided by operating activities, funds from operations, net income and comprehensive income is commodity prices. Refer to the section “Commodity Prices and Marketing” for a more detailed discussion of commodity prices and our price risk management. Advantage Oil & Gas Ltd. - 16 Petroleum, Natural Gas Sales and Hedging Three months ended December 31 Year ended December 31 ($000) Natural gas sales Realized hedging gains Natural gas sales including hedging Crude oil and NGLs sales Realized hedging losses Crude oil and NGLs sales including hedging Total (1) (1) Total excludes unrealized derivative gains and losses. $ 2011 40,249 7,262 47,511 52,051 (704) 51,347 98,858 $ $ 2010 34,081 12,871 46,952 42,140 (3,080) % change 18 % % (44) % 1 % 24 % (77) $ 2011 169,274 28,657 197,931 186,014 (2,831) $ 2010 146,572 55,360 201,932 172,796 (10,227) % change % 15 % (48) % (2) % 8 % (72) 39,060 86,012 $ 31 % % 15 183,183 381,114 $ 162,569 364,501 $ % 13 % 5 Total sales, excluding hedging, increased 21% and 11% for the three months and year ended December 31, 2011 as compared to 2010, respectively. Sales have been positively impacted from significant increases in our production during these periods due to our successful exploration and development activities. Natural gas sales in particular have benefited from our Montney natural gas resource play at Glacier, Alberta where we have increased production capacity with our Phase III facilities and infrastructure expansion work completed in the first quarter of 2011. Crude oil and NGL production has also increased during the fourth quarter of 2011 due to production additions from Longview’s capital expenditure program that began late in 2011, delayed by poor field conditions from severe wet weather. The increase in sales during 2011 has been partially offset by reduced production attributable to asset dispositions that closed in the second quarter of 2010. We have also experienced an increase in sales during 2011 due to higher realized crude oil and NGLs prices, excluding hedging. However, sales continues to be adversely impacted by the natural gas price environment that has been weak during the last several years attributable to many factors, including continued high US domestic natural gas production that has increased supply and the ongoing weak North American economy that has negatively impacted demand. These factors, in combination with mild weather conditions, have resulted in historic high inventory levels that are currently well-above the five-year average. This current environment has placed considerable downward pressure on natural gas prices. Given the low natural gas price environment, our commodity price risk management program has delivered realized natural gas hedging gains of $7.3 million and $28.7 million for the three months and year ended December 31, 2011, respectively. As crude oil prices have remained relatively strong, we realized minor crude oil hedging losses of $0.7 million for the three months and $2.8 million for the year ended December 31, 2011. The Corporation enters derivative contracts whereby realized hedging gains and losses partially offset commodity price fluctuations, which can positively or negatively impact sales. The realized natural gas hedging gains have been significant and helped us stabilize cash flows and ensure that our capital expenditure program is substantially funded by such cash flows. However, we have no natural gas hedges for 2012. Production Natural gas (mcf/d) Crude oil (bbls/d) NGLs (bbls/d) Total (boe/d) Natural gas (%) Crude oil (%) NGLs (%) Three months ended December 31 Year ended December 31 2011 137,480 5,182 1,316 29,411 78% 18% 4% % change 30 % % 6 (24) % % 21 2010 106,125 4,886 1,734 24,308 73% 20% 7% 2011 130,075 4,711 1,519 27,909 78% 17% 5% % change 28 % % (7) (29) % % 16 2010 101,562 5,076 2,126 24,129 70% 21% 9% Average daily production during the fourth quarter of 2011 increased 21% above the same period of 2010, with a 30% increase in natural gas production and a 6% increase in crude oil production, partially offset by a 24% decrease NGLs production. Production for the current quarter was 3% higher than the 28,638 boe/d reported in the third quarter of 2011. For the year ended December 31, 2011, average daily production increased 16% above the prior year, with a 28% increase in natural gas production and decreases in both crude oil and NGLs production. Advantage Oil & Gas Ltd. - 17 Production for 2010 and 2011 has continued to be primarily impacted by Advantage’s significant production growth at Glacier, Alberta. During the second quarter of 2010 our 100% working interest gas plant (“Glacier gas plant”) was brought on-stream ahead of schedule with production rates exceeding 50 mmcf/d (8,300 boe/d). Due to stronger than expected well performance, we were able to further increase Glacier production exiting 2010 exceeding 60 mmcf/d (10,000 boe/d). Phase III of our Glacier development project was completed during the first quarter of 2011 on-budget and ahead of schedule with production capacity at 100 mmcf/d (16,667 boe/d) resulting in a peak corporate production rate of approximately 30,000 boe/d at March 31, 2011. During the third quarter of 2011, the Glacier gas plant experienced planned facility downtime to complete our acid gas injection system and maintenance work conducted by TransCanada Pipelines (“TCPL”). During the fourth quarter of 2011, we successfully commissioned the acid gas injection system which is now capable of disposing acid gas volumes for plant inlet gas volumes in excess of 140 mmcf/d. In addition, TCPL completed further looping of their sales pipeline lateral in preparation for our plant expansion to 140 mmcf/d. These projects represent significant milestones towards achieving our Glacier Phase IV development and will provide additional flexibility for future production growth. Further plant downtime will be required during the first and second quarters of 2012 to accommodate future equipment installations to finalize the expansion of our Glacier gas plant processing capacity to 140 mmcf/d. Longview’s daily production averaged 6,823 boe/d for the fourth quarter of 2011, an increase of 12% from 6,071 boe/d realized in the third quarter of 2011 with 75% from crude oil and NGLs. During much of the spring and summer, field conditions were poor with severe wet weather that created challenges for the industry to conduct regular well maintenance and sustain production levels. Fortunately, much of Longview’s production is pipeline connected rather than trucked and they experienced less outages such that the weather impact was minimal. However, routine well maintenance and their current year capital program were delayed while conditions improved. During the third quarter Longview began to expedite maintenance activities, workovers and reactivations and commenced their 2011 Alberta capital expenditure program in July with the Saskatchewan program beginning in September. The well maintenance and workover activity continued into the fourth quarter and generally lead to higher operating costs during these periods. Production additions from their capital expenditure program began at the end of the third quarter and resulted in their fourth quarter production increasing 12%. Commodity Prices and Marketing Natural Gas ($/mcf) Realized natural gas prices Excluding hedging Including hedging AECO daily index Three months ended December 31 Year ended December 31 2011 2010 % change 2011 2010 % change $ $ $ 3.18 3.76 3.20 $ $ $ 3.49 4.81 3.63 % (9) % (22) % (12) $ $ $ 3.57 4.17 3.63 $ $ $ 3.95 5.45 3.99 % (10) (23) % % (9) Realized natural gas prices, excluding hedging, for the three months ended December 31, 2011 were 9% lower as compared to the same period of 2010 and decreased 10% for the year ended December 31, 2011 as compared to the prior year. Our realized natural gas prices, excluding hedging, for this quarter were 12% lower than the $3.62/mcf realized during the third quarter of 2011. Although natural gas prices have continued to remain weak, our commodity hedging has resulted in realized natural gas prices, including hedging, that exceeds current market prices and has reduced the volatility of our cash flows. However, realized natural gas prices, including hedging, have decreased more during 2011 as compared to 2010 as we had less natural gas production hedged for this year at lower average prices. We have no natural gas production hedged for 2012. During 2010 and 2011, natural gas prices have remained low from continued high US domestic natural gas production that has increased supply, particularly from non-conventional natural gas resource plays, and the ongoing weak North American economy that has negatively impacted demand. These factors, in combination with mild weather conditions, have resulted in historic high inventory levels that are currently well-above the five-year average. This current environment has placed considerable downward pressure on natural gas prices with AECO gas presently trading at approximately $1.80/mcf and we anticipate that natural gas prices will remain low in the near term. We continue to believe in the longer-term price support for natural gas due to the increased proportion of resource based natural gas supplies that experience higher initial production declines and reduced conventional natural gas drilling, both of which could eventually lead to a more balanced supply and demand environment. We monitor market developments closely and will be proactive in implementing an appropriate hedging strategy to mitigate the volatility in our cash flow as a result of fluctuations in natural gas prices. Advantage Oil & Gas Ltd. - 18 Crude Oil and NGLs ($/bbl) Realized crude oil prices Excluding hedging Including hedging Realized NGLs prices Excluding hedging Realized crude oil and NGLs prices Excluding hedging Including hedging WTI ($US/bbl) $US/$Canadian exchange rate Three months ended December 31 Year ended December 31 2011 2010 % change 2011 2010 % change $ $ 89.34 87.86 $ $ 74.76 67.91 20 % 29 % $ $ 87.02 85.38 $ $ 72.80 67.28 20 % 27 % $ 78.09 $ 53.50 46 % $ 65.64 $ 48.88 34 % $ $ $ $ 87.06 85.88 94.02 0.98 $ $ $ $ 69.19 64.14 85.18 0.99 26 % 34 % 10 % (1) % $ $ $ $ 81.81 80.56 95.14 1.01 $ $ $ $ 65.74 61.85 79.55 0.97 24 % 30 % 20 % 4 % Realized crude oil and NGLs prices, excluding hedging, increased 26% for the three months ended and 24% for the year ended December 31, 2011, as compared to the same periods of 2010. Realized crude oil and NGLs prices, excluding hedging, have increased 14% for the fourth quarter of 2011 in comparison to the third quarter of 2011. Crude oil and NGL pricing has continued to experience considerable volatility with West Texas Intermediate (“WTI”) increasing 5% to US$94.02/bbl as compared to US$89.81/bbl experienced in the third quarter of 2011. Advantage’s realized crude oil price may not change to the same extent as WTI due to changes in the $US/$Canadian exchange rate and changes in Canadian crude oil differentials relative to WTI. The price of WTI fluctuates based on worldwide supply and demand fundamentals with significant price volatility experienced over the last several years. WTI had been relatively strong during 2010 and near the end of the year began to increase and significantly escalated during early 2011, primarily influenced by middle-east tensions and associated supply concerns, with WTI currently trading at approximately US$107/bbl. However, we have also seen a general strengthening of the $US/$Canadian exchange rate during these periods that has partially offset the improvement in WTI. We believe that the long-term pricing fundamentals for crude oil will remain strong with supply management by the OPEC cartel and strong relative demand from developing countries. Commodity Price Risk The Corporation’s financial results and condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely and are determined by economic and political factors. Supply and demand factors, including weather and general economic conditions as well as conditions in other oil and natural gas regions, impact prices. Any movement in oil and natural gas prices will have an effect on the Corporation’s financial condition and performance. Advantage has an established financial hedging strategy and may manage the risk associated with changes in commodity prices by entering into derivative contracts. Although these commodity price risk management activities could expose Advantage to losses or gains, entering derivative contracts helps us to stabilize cash flows and ensures that our capital expenditure program is substantially funded by such cash flows. To the extent that Advantage engages in risk management activities related to commodity prices, it will be subject to credit risk associated with counterparties with which it contracts. Credit risk is mitigated by entering into contracts with only stable, creditworthy parties and through frequent reviews of exposures to individual entities. In addition, the Corporation only enters into derivative contracts with major banks and international energy firms to further mitigate associated credit risk. Our Credit Facilities also prohibit the Corporation from entering into any derivative contract where the term of such contract exceeds three years. Further, the aggregate of such contracts cannot hedge greater than 60% of total estimated oil and natural gas production over two years and 50% over the third year. Currently the Corporation has the following derivatives in place: Description of Derivative Term Volume Average Price Crude oil – WTI Fixed price (1) Collar (1) January 2012 to December 2012 January 2012 to December 2012 1,000 bbls/d 1,000 bbls/d Cdn $97.10/bbl Bought put Cdn $90.00/bbl Sold call Cdn $102.25/bbl (1) These financial contracts were entered by Longview. Advantage Oil & Gas Ltd. - 19 A summary of realized and unrealized hedging gains and losses for the three months and years ended December 31, 2011 and 2010 are as follows: ($000) Realized hedging Natural gas Crude oil Total realized hedging gains Unrealized hedging Natural gas Crude oil Total unrealized hedging gains (losses) Total gains (losses) on derivatives Three months ended December 31 Year ended December 31 2011 2010 % change 2011 2010 % change $ 7,262 (704) 6,558 $ 12,871 (3,080) 9,791 % (44) % (77) % (33) $ 28,657 (2,831) 25,826 $ 55,360 (10,227) 45,133 % % % (48) (72) (43) (6,684) (3,919) (10,603) (4,045) $ 7,637 (21,784) (14,147) (4,356) $ % (188) % (82) (25) % % (7) (25,152) (199) (25,351) 475 $ 11,299 (5,918) 5,381 50,514 $ (323) % % (97) % (571) % (99) For the three months ended December 31, 2011, we recognized a net realized derivative gain of $6.6 million (December 31, 2010 - $9.8 million net realized derivative gain) and for the year ended December 31, 2011, we recognized a net realized derivative gain of $25.8 million (December 31, 2010 - $45.1 million net realized derivative gain) on settled derivative contracts, primarily as a result of lower average actual natural gas prices during the periods as compared to our established average hedge prices. Our net realized derivative gain has decreased during 2011 as compared to 2010 as we had less natural gas production hedged for this year at lower average prices and we have generally realized losses on our crude oil hedges. However, our successful commodity price risk management program continued to realize significant gains on derivatives during 2011 that has helped to offset the continued weak natural gas prices and positively impact funds from operations. As at December 31, 2011, the fair value of the derivative contracts outstanding and to be settled was a net liability of approximately $2.7 million, a decrease of $25.3 million from the $22.6 million net asset recognized as at December 31, 2010. For the year ended December 31, 2011, this $25.3 million decrease in the fair value of derivative contracts was recognized in income as an unrealized derivative loss (December 31, 2010 – $5.4 million unrealized derivative gain). The valuation of the derivatives is the estimated fair value to settle the contracts as at December 31, 2011 and is based on pricing models, estimates, assumptions and market data available at that time. As such, the recognized amounts are not cash and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices and foreign exchange rates as compared to the valuation assumptions. The Corporation does not apply hedge accounting and current accounting standards require changes in the fair value to be included in the consolidated statement of comprehensive income as a derivative gain or loss with a corresponding derivative asset and liability recorded on the statement of financial position. These derivative contracts will settle in 2012 corresponding to when the Corporation will recognize sales from production. Royalties Royalties ($000) per boe As a percentage of petroleum and natural gas sales Three months ended December 31 Year ended December 31 2011 $ $ 13,339 4.93 2010 $ $ 9,661 4.32 % change 38 14 % % 2011 2010 $ $ 52,971 5.20 $ $ 45,954 5.22 % change 15 % % - 14.5% 12.7% 1.8 % 14.9% 14.4% 0.5 % Advantage pays royalties to the owners of mineral rights from which we have leases. The Corporation currently has mineral leases with provincial governments, individuals and other companies. Royalties include payments for Saskatchewan Resource Surcharge which is based on the petroleum and natural gas sales earned within the Province of Saskatchewan. Royalties also include the impact of gas cost allowance (“GCA”), which is a reduction of royalties payable to the Alberta Provincial Government to recognize capital and operating expenditures incurred in the gathering and processing of their share of natural gas production and does not generally fluctuate with natural gas prices. Total royalties paid has increased as compared to the prior year periods mainly due to the higher corporate production. Royalties as a percentage of petroleum and natural gas sales have increased as significant increases in crude oil and NGL prices have more than offset decreases in natural gas prices. The royalty rate realized by each of Advantage and Longview on a stand- alone basis for the current quarter was 9.3% and 20.1%, respectively. Advantage’s royalty rates, that are predominately based on Advantage Oil & Gas Ltd. - 20 natural gas production have decreased due to lower natural gas prices and lower average royalties attributed to production from our significant development at Glacier, Alberta. Longview’s royalty rates are higher due to the stronger relative crude oil and NGL prices. Our average corporate royalty rates are significantly impacted by the Alberta Provincial Government’s royalty framework for conventional oil, natural gas and oil sands whereby Alberta royalties are affected by depths, well production rates, and commodity prices. Additionally, the Alberta Provincial Government has a number of drilling incentive programs with reduced royalty rates for qualifying wells. All of our Montney horizontal wells at Glacier drilled after May 1, 2010 qualify for the Alberta Provincial Government’s Natural Gas Deep Drilling Program (“NGDDP”) which is estimated to provide a royalty incentive of $2.7 to $3.4 million for a typical horizontal well (a typical Advantage horizontal well at Glacier is 4,200 to 4,500 metres in total length). This royalty incentive results in an estimated 5% royalty rate for all Montney horizontal wells for the life of the well. This significantly lowers the natural gas price threshold required to drill economic wells and substantially improves the value of future reserves and upside potential at Glacier. Therefore, corporate royalty rates will continue to fluctuate based on commodity prices, individual well productivity, and our ongoing capital development plans. Operating Expense Three months ended December 31 Year ended December 31 Operating expense ($000) per boe 2011 $ $ 21,717 8.03 2010 $ $ 23,811 10.65 % change (9) (25) % % 2011 2010 $ $ 89,166 8.75 $ $ 95,609 10.86 % change % (7) % (19) Total operating expense decreased 9% for the three months and 7% for the year ended December 31, 2011 as compared to the same periods of 2010. Operating expense per boe decreased 25% and 19% for the three months and year ended December 31, 2011 as compared to the prior year. Operating expense per boe realized by Advantage on a stand-alone basis for the fourth quarter of 2011 was $4.90/boe. The reduction in total operating expense has been primarily due to increased production from Glacier, benefits of our ongoing optimization program, the sale of higher cost assets, and a one-time $1.7 million equalization that was recognized in the fourth quarter of 2011 related to a gas processing facility. Operating expense at Glacier is approximately $0.30/mcf ($1.80/boe) at 100 mmcf/d due to the efficiencies created by increasing the production rate through our 100% owned Glacier gas plant. Operating expense per boe realized by Longview for the current quarter was $18.36/boe. During much of the spring and summer, field conditions were poor with severe wet weather that created challenges for the industry to conduct regular well maintenance and sustain production levels. Therefore, routine well maintenance and Longview’s current year capital program were delayed while conditions improved. During the third quarter Longview began to expedite maintenance activities, workovers and reactivations and commenced their 2011 Alberta capital expenditure program in July with the Saskatchewan program beginning in September. The well maintenance and workover activity continued into the fourth quarter and generally lead to higher operating costs during these periods. To mitigate risks associated with fluctuating power costs, Longview has also fixed the price on 0.9 MW at $77.88/MWh for the period from January 2012 to December 2012. Longview anticipates operating costs to be $16.00 to $17.00/boe during 2012. Advantage Oil & Gas Ltd. - 21 General and Administrative Expense Three months ended December 31 Year ended December 31 2011 2010 % change 2011 2010 % change General and administrative expense Cash expense ($000) per boe Non-cash expense ($000) per boe Total general and administrative expense ($000) per boe Employees at December 31 $ $ $ $ 5,119 1.89 2,107 0.78 $ $ $ $ 6,197 2.77 2,039 0.91 % (17) (32) % % 3 % (14) $ $ $ $ 22,239 2.18 12,348 1.21 $ $ $ $ 25,316 2.87 12,877 1.46 % (12) (24) % % (4) % (17) $ $ 7,226 2.67 $ $ 8,236 3.68 (12) (27) % % $ $ 34,587 3.39 125 $ $ 38,193 4.33 128 % (9) (22) % % (2) Cash general and administrative (“G&A”) expense for the year ended December 31, 2011 has decreased as compared to 2010 due to ongoing cost reduction efforts, which along with the increased production has reduced cash G&A per boe. Non-cash G&A expense is comprised of Advantage’s and Longview’s Restricted Share Performance Incentive Plans (“RSPIP” or the “Plans”) with the purpose to retain and attract employees, to reward and encourage performance, and to focus employees on operating and financial performance that results in lasting shareholder returns. The Plans authorize the Boards of Directors to grant restricted shares of each public company to service providers including directors, officers, employees and consultants of Advantage and Longview. The number of restricted shares granted is based on each Corporations’ share price return for a twelve-month period and compared to the performance of a peer group approved by the Boards of Directors. The share price returns are calculated at the end of each and every quarter and are primarily based on the twelve-month change in the share prices including dividends. If a share price return for a twelve-month period is positive, a restricted share grant will be calculated based on the return. Otherwise, no restricted shares will be granted to service providers for the period. If the share price return for a twelve-month period is negative, but the return is still within the top two-thirds of the approved peer group performance, the Board of Directors may grant a discretionary restricted share award. Restricted shares vest one-third immediately on grant date with the remaining two-thirds vesting on each of the subsequent two anniversary dates. On vesting, common shares are issued to the service providers in exchange for their restricted shares outstanding. Compensation cost related to the Plans are recognized as share-based compensation expense within G&A expense over the service periods of the service providers and incorporates the fair value at grant date, the estimated number of restricted shares to vest, and certain management estimates. For the year ended December 31, 2011, Advantage granted 1,443,956 restricted shares at an average grant price of $7.78 per restricted share and recognized $11.5 million of share-based compensation expense as non-cash G&A expense. During the year ended December 31, 2011 Advantage issued 2,212,031 common shares to service providers in accordance with the vesting provisions of the RSPIP. As at December 31, 2011, 2,117,710 restricted shares remain unvested and will vest to service providers over the next two years with a total of $5.0 million in compensation cost to be recognized over the future service periods. For the year ended December 31, 2011, Longview granted 150,722 restricted shares at a grant price of $11.45 per restricted share and recognized $0.8 million of share-based compensation expense as non-cash G&A expense. During the year ended December 31, 2011 Longview issued 50,422 common shares to service providers in accordance with the vesting provisions of the RSPIP. As at December 31, 2011, 100,300 restricted shares remain unvested and will vest to service providers over the next two years with a total of $0.7 million in compensation cost to be recognized over the future service periods. Depreciation Expense Three months ended December 31 2011 2010 Depreciation expense ($000) per boe $ $ 41,669 15.40 $ $ 32,507 14.54 Year ended December 31 % change 28 % % 6 2011 152,927 15.01 $ $ 2010 124,592 14.15 $ $ % change 23 % % 6 Depreciation of oil and gas properties is provided on the unit-of–production method based on total proved and probable reserves, including future development costs, on a component basis. Depreciation expense has increased for the three months and year ended Advantage Oil & Gas Ltd. - 22 December 31, 2011 as compared to 2010 due to the increase in production and a higher average rate of depreciation per boe. The rate of depreciation per boe is higher partially due to an increase in property, plant and equipment attributable to changes in our decommissioning liability. Decommissioning liabilities are determined by discounting at a risk-free rate the expected future cash flows required to decommission all well sites, gathering systems and processing facilities. With the continued decrease in risk-free rates, the net present value of the decommissioning liability has increased with a corresponding increase in property, plant and equipment which impacts our depreciation expense. Impairment of Oil and Gas Properties Three months ended December 31 Year ended December 31 2011 2010 % change 2011 2010 % change Impairment of oil and gas properties ($000) $ 187,684 $ 17,500 972 % $ 187,684 $ 17,500 972 % At each reporting date, Advantage assesses whether or not there are circumstances that indicate a possibility that the carrying values of exploration and evaluation assets and property, plant and equipment are not recoverable, or impaired. Such circumstances include incidents of physical damage, deterioration of commodity prices, changes in the regulatory environment, or a reduction in estimates of proved and probable reserves. For the purpose of impairment testing of property, plant and equipment, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the “cash-generating unit” or “CGU”). When management judges that circumstances clearly indicate impairment, CGUs are tested for impairment by comparing the carrying values to their recoverable amounts. These calculations require the use of estimates and assumptions, that are subject to change as new information becomes available including information on future commodity prices, expected production volumes, quantities of reserves, discount rates, future development costs and operating costs (refer to the section “Critical Accounting Estimates”). Impairment losses on CGUs are recognized in the Statement of Comprehensive Income as impairment of oil and gas properties and are separately disclosed. As at December 31, 2011, Advantage determined that the significant reduction in natural gas prices recognized within our year-end independent reserves evaluation was an indicator of impairment. As a result, we completed an impairment assessment and calculated an estimated recoverable amount for our natural gas concentrated CGUs, primarily based upon the net present value after tax of our year-end proved plus probable reserves discounted at 10% and adjusted for a number of other estimates and assumptions. Based upon these calculations, we recognized an impairment loss of $187.7 million related to two CGUs that consist of conventional natural gas focused properties located in Western and Eastern Alberta that had suffered a significant deterioration in value due to the challenging natural gas price environment. No impairment losses were recognized for any other CGUs, including our Glacier property. An impairment loss is reversed if there is subsequently an objective change in the estimates used to determine the recoverable amount. Exploration and Evaluation Expense Three months ended December 31 Year ended December 31 2011 2010 % change 2011 2010 % change Exploration and evaluation expense ($000) $ 1,708 $ 752 127 % $ 3,055 $ 752 306 % All exploratory costs incurred subsequent to acquiring the right to explore for oil and natural gas are capitalized as exploration and evaluation assets pending determination of technical feasibility and commercial viability. Such costs can typically include costs to acquire land rights in areas with no proved or probable reserves assigned, geological and geophysical costs, and exploration wells. If the assets are subsequently determined to be technically feasible and commercially viable, the exploratory costs are tested for impairment and then reclassified from exploration and evaluation assets to development and production assets. If exploratory costs are determined not to be technically feasible and commercially viable, the costs are expensed as exploration and evaluation expense. For the year ended December 31, 2011, we expensed exploration and evaluation costs of $3.1 million related to undeveloped land that expired during the period. Advantage Oil & Gas Ltd. - 23 Other Income ($000) Gain (loss) on sale of property, plant and equipment Miscellaneous income (expense) Three months ended December 31 Year ended December 31 2011 2010 % change 2011 2010 % change $ $ $ $ 153 88 241 (1,541) (36) (1,577) (110) (344) (115) % % % $ $ 1,325 647 1,972 $ $ 45,631 511 46,142 (97) 27 (96) % % % Other income primarily consists of gains related to the disposition of property, plant and equipment. During 2010, Advantage disposed of several non-core properties and recognized a $45.6 million net gain. For 2011, Advantage disposed of several minor non- core properties and recognized a $1.3 million net gain. Interest on Bank Indebtedness Three months ended December 31 Year ended December 31 Interest on bank indebtedness ($000) per boe Average effective interest rate 2011 $ $ 2,142 0.79 5.4% 2010 $ $ 3,376 1.51 4.9% % change (37) (48) 0.5 % % % 2011 $ $ 11,483 1.13 5.3% 2010 $ $ 13,346 1.52 5.0% % change (14) (26) 0.3 % % % Bank indebtedness at December 31 ($000) 233,903 290,657 (20) % Total interest on bank indebtedness has decreased during 2011 as compared to 2010 primarily due to the reduction in the average debt balance attributable to raising cash proceeds from selling a 37% non-controlling interest in Longview. However, our bank indebtedness has increased $81.5 million during the fourth quarter of 2011 in comparison to the prior quarter due to the maturity and settlement of our 7.75% and 8.00% convertible debentures in December 2011 for $62.3 million in cash and escalation of our capital expenditure programs that modestly exceeded funds from operations. Consolidated bank indebtedness outstanding at the end of December 31, 2011 was $233.9 million consisting of $142.5 million and $91.4 million for each of the legal entities Advantage and Longview, respectively. Advantage’s consolidated Credit Facilities of $475 million at December 31, 2011 includes $275 million with Advantage and $200 million with Longview. The Corporation’s interest rates are primarily based on short term bankers acceptance rates plus a stamping fee. We monitor the debt level to ensure an optimal mix of financing and cost of capital that will provide a maximum return to our shareholders. Interest and Accretion on Convertible Debentures Interest on convertible debentures ($000) per boe Accretion on convertible debentures ($000) per boe Convertible debentures maturity value at December 31 ($000) Three months ended December 31 Year ended December 31 2011 2010 % change 2011 2010 % change $ $ 1,995 0.74 $ $ 2,303 1.03 (13) (28) % % $ $ 8,871 0.87 $ $ 11,486 1.30 (23) (33) % % $ $ 824 0.30 $ $ 824 0.37 % - % (19) $ $ 3,360 0.33 $ $ 3,263 0.37 % 3 % (11) $ 86,250 $ 148,544 (42) % Interest on convertible debentures for 2011 has decreased compared to 2010 due to the maturity and settlement of the 6.50% debentures in June 2010 and the 7.75% and 8.00% convertible debentures in December 2011. Accretion on convertible debentures has remained relatively comparable for the periods. Advantage Oil & Gas Ltd. - 24 Accretion on Decommissioning Liability Accretion on decommissioning liability ($000) per boe Decommissioning liability at December 31 ($000) Three months ended December 31 Year ended December 31 2011 2010 % change 2011 2010 % change $ $ 1,459 0.54 $ $ 1,270 0.57 % 15 % (5) $ $ 5,748 0.56 $ $ 6,094 0.69 % (6) % (19) $ 253,796 $ 172,130 47 % Decommissioning liabilities are determined by discounting at a risk-free rate the expected future cash flows required to decommission all petroleum and natural gas assets. With the continued decrease in risk-free rates, the net present value of the decommissioning liability has increased with a corresponding increase in property, plant and equipment. Accretion on decommissioning liability represents the increase in the decommissioning liability each reporting period due to the passage of time and is currently calculated at an annualized rate of 2.5% of the liability. Accretion expense has decreased slightly for 2011 primarily due to a lower annualized rate of accretion. Taxes Deferred income taxes arise from differences between the accounting and tax bases of our assets and liabilities. For the year ended December 31, 2011, the Corporation recognized a deferred income tax recovery of $46.8 million compared to a deferred income tax expense of $18.1 million for 2010. The deferred income tax recovery was incurred due to the significant loss before income taxes that was recognized during 2011. As at December 31, 2011, the Corporation had a deferred income tax asset balance of $39.4 million and a deferred income tax liability balance of $29.7 million compared to a net deferred income tax liability balance of $40.2 million at December 31, 2010. Advantage and Longview have approximately $1.6 billion in tax pools and deductions at December 31, 2011, which can be used to reduce the amount of taxes payable. The estimated tax pools in place are as follows: Canadian Development Expenses Canadian Exploration Expenses Canadian Oil and Gas Property Expenses Non-capital losses Undepreciated Capital Cost Other $ Estimated Tax Pools December 31, 2011 ($ millions) Longview Consolidated 141 71 367 704 347 14 1,644 35 - 367 73 76 8 559 $ $ $ Advantage 106 $ 71 - 631 271 6 1,085 $ Advantage has a federal non-capital loss carry forward balance of approximately $631 million that will expire between 2024 and 2031. Longview has a federal non-capital loss carry forward balance of approximately $73 million that will expire in 2031 and 2032. Net Income Attributable to Non-Controlling Interest At December 31, 2011, Advantage had a 63% ownership interest in Longview with the remaining 37% held by outside interests or non-controlling interests. As Advantage is the parent company and has a majority ownership interest of Longview, Advantage’s consolidated financial statements include 100% of Longview’s accounts. To determine the net income attributable to the Advantage shareholders, it is necessary to deduct that portion of the net income related to Longview that is consolidated within Advantage’s financial results but are attributable to the 37% non-controlling interest. Therefore, for the year ended December 31, 2011, Advantage recognized a $7.4 million reduction to net income related to Longview’s net income attributable to the non-controlling interests. Advantage Oil & Gas Ltd. - 25 Net Income (Loss) and Comprehensive Income (Loss) Three months ended December 31 Year ended December 31 2011 2010 % change 2011 2010 % change Net income (loss) and comprehensive income (loss) ($000) per share - basic - diluted $ $ $ (145,063) (0.87) (0.87) $ $ $ (22,888) (0.14) (0.14) 534 521 521 % % % $ $ $ (152,772) (0.92) (0.92) $ $ $ 40,920 0.25 0.25 (473) (468) (468) % % % The net loss and net loss per common share realized for the year ended December 31, 2011 was a considerable decrease as compared to the net income and net income per common share for 2010. Although Advantage experienced strong operating results that have contributed significantly to our 2011 financial results including production and sales increases, significant realized hedging gains and continued cost reductions, we also experienced an increase in depreciation expense and a significant impairment that resulted in our net loss. Additionally, net income for 2010 was much higher primarily due to significant gains on derivatives and asset dispositions. Depreciation expense has increased for 2011 as compared to 2010 due to the increase in production and a higher average rate of depreciation per boe. The rate of depreciation per boe is higher partially due to an increase in property, plant and equipment attributable to changes in our decommissioning liability. As at December 31, 2011, Advantage determined that the significant reduction in natural gas prices recognized within our year-end independent reserves evaluation was an indicator of impairment. As a result, we completed an impairment assessment and calculated an estimated recoverable amount for our natural gas concentrated CGUs. Based upon these calculations, we recognized an impairment loss of $187.7 million related to two CGUs that consist of conventional natural gas focused properties located in Western and Eastern Alberta that had suffered a significant deterioration in value due to the challenging natural gas price environment. The derivative gains recognized include both realized and unrealized amounts. Our net derivative gain has decreased during 2011 as compared to 2010 as we had less natural gas production hedged for this year at lower average prices and we have generally realized losses on our crude oil hedges. During 2010 Advantage also disposed of several non-core properties and recognized a net $45.6 million gain. Cash Netbacks Petroleum and natural gas sales Royalties Realized gain on derivatives Operating expense Operating General and administrative (1) Finance expense (2) Miscellaneous income Funds from operations and cash netbacks Three months ended December 31 Year ended December 31 2011 2010 2011 2010 $ $ $ $ $000 92,300 (13,339) 6,558 (21,717) 63,802 (5,119) (4,137) 88 54,634 per boe 34.11 $ (4.93) 2.42 (8.03) 23.57 (1.89) (1.53) 0.03 20.18 $ $000 76,221 (9,661) 9,791 (23,811) 52,540 (6,197) (5,679) (36) 40,628 per boe 34.08 $ (4.32) 4.38 (10.65) 23.49 (2.77) (2.54) (0.02) 18.16 $ $000 355,288 (52,971) 25,826 (89,166) 238,977 (22,239) (20,354) 647 197,031 per boe 34.88 $ (5.20) 2.54 (8.75) 23.47 (2.18) (2.00) 0.06 19.35 $ $000 319,368 (45,954) 45,133 (95,609) 222,938 (25,316) (24,832) 511 173,301 per boe 36.26 $ (5.22) 5.12 (10.86) 25.30 (2.87) (2.82) 0.06 19.67 $ $ $ $ $ (1) General and administrative expense excludes non-cash G&A and non-cash share-based compensation expense. (2) Finance expense excludes non-cash accretion expense. Funds from operations for 2011 have been strong, driven by increases in production and continued gains from our hedging program, which demonstrates the clear ongoing improvement in our financial and operating results from our focused development program. Average daily production during the fourth quarter of 2011 increased 21% above the same period of 2010, with a 30% increase in natural gas production and a 6% increase in crude oil production, partially offset by a 24% decrease in NGL production. Production increases have been primarily due to completion of the Glacier gas plant Phase III expansion to a production capacity of 100 mmcf/d (16,667 boe/d) at the end of the first quarter of 2011. For the three months and year ended December 31, 2011 we realized gains on derivatives of $6.6 million and $25.8 million, respectively. Our hedging program has helped to offset the continued weak natural gas Advantage Oil & Gas Ltd. - 26 prices and positively impacts funds from operations. However, hedging gains for 2011 have been lower than 2010 as we have a lower percentage of natural gas production hedged at lower average prices. Funds from operations have also benefited during this year from higher crude oil prices and continued cost reductions, such as operating costs, general and administrative expense, and finance expense. Operating costs per boe have significantly decreased as we continue to realize benefits from the addition of lower cost production due to the completion of our Glacier gas plant and our divestment of higher cost assets. We also recognized a one-time $1.7 million equalization in the fourth quarter of 2011 related to a gas processing facility. Finance expense has been reduced as we utilized proceeds from the asset dispositions and disposing of a non-controlling interest in Longview to repay bank indebtedness and maturing convertible debentures. Although funds from operations has also benefited during this year from higher crude oil prices, natural gas prices still remain weak and pose a continuing challenge to the entire natural gas industry. When comparing the current quarter to the third quarter of 2011, our funds from operations increased 9% and funds from operations per boe were 6% higher as realized crude oil and NGL prices increased during this quarter and general costs continued to decrease, including operating costs. Contractual Obligations and Commitments The Corporation has contractual obligations in the normal course of operations including purchases of assets and services, operating agreements, transportation commitments, sales contracts, bank indebtedness and convertible debentures. These obligations are of a recurring and consistent nature and impact cash flow in an ongoing manner. The following table is a summary of the Corporation’s remaining contractual obligations and commitments. Advantage has no guarantees or off-balance sheet arrangements other than as disclosed. ($ millions) Building leases Pipeline/transportation Bank indebtedness (1) Convertible debentures (2) - principal - interest - principal - interest Total contractual obligations $ $ $ Total 7.4 36.6 233.9 18.3 86.2 15.1 397.5 $ Payments due by period 2012 3.4 12.1 - 12.4 - 4.3 32.2 2013 2.5 11.9 233.9 5.9 - 4.3 258.5 $ 2014 1.5 10.4 - - - 4.3 16.2 2015 - $ 2.2 - - 86.2 2.2 90.6 $ $ $ $ (1) The Corporation’s bank indebtedness does not have specific maturity dates. It is governed by credit facility agreements with a syndicate of financial institutions. Under the terms of the agreements, the facilities are reviewed annually, with the next reviews scheduled in April and June 2012. The facilities are revolving, and extendible at each annual review for a further 364 day period at the option of the syndicate. If not extended, the credit facilities are converted at that time into one-year term facilities, with the principal payable at the end of such one-year terms. Management fully expects that the facilities will be extended at each annual review. (2) As at December 31, 2011, Advantage had $86.2 million convertible debentures outstanding. The convertible debentures are convertible to common shares based on an established conversion price. All remaining obligations related to convertible debentures can be settled through the payment of cash or issuance of common shares at Advantage’s option. Advantage Oil & Gas Ltd. - 27 Liquidity and Capital Resources The following table is a summary of the Corporation’s capitalization structure. ($000, except as otherwise indicated) Bank indebtedness (non-current) Working capital deficit (1) Net debt Convertible debentures maturity value (non-current) Total debt Shares outstanding Shares closing market price ($/share) Market capitalization (2) $ Advantage 142,548 70,564 213,112 86,250 299,362 166,304,040 4.24 705,129 $ $ $ December 31, 2011 Longview 91,355 $ 20,074 111,429 - 111,429 46,750,432 10.12 473,114 $ $ $ Consolidated 233,903 $ 90,638 324,541 86,250 410,791 $ (1) Working capital deficit is a non-GAAP measure that includes trade and other receivables, prepaid expenses and deposits, trade and other accrued liabilities, and the current portion of other liability (2) Market capitalization is a non-GAAP measure calculated by multiplying shares outstanding by the closing market share price on the applicable date for each legal entity. Advantage monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the business and industry in general. The capital structure of the Corporation is composed of working capital (excluding derivative liabilities), bank indebtedness, convertible debentures and share capital. Advantage may manage its capital structure by issuing new common shares, repurchasing outstanding common shares, obtaining additional financing either through bank indebtedness or convertible debenture issuances, refinancing current debt, issuing other financial or equity-based instruments, declaring a dividend, implementing a dividend reinvestment plan, adjusting capital spending, or disposing of assets or its ownership interest in Longview. The capital structure is reviewed by Management and the Board of Directors on an ongoing basis. Management of the Corporation’s capital structure is facilitated through its financial and operational forecasting processes. The forecast of the Corporation’s future cash flows is based on estimates of production, commodity prices, forecast capital and operating expenditures, and other investing and financing activities. The forecast is regularly updated based on new commodity prices and other changes, which the Corporation views as critical in the current environment. Selected forecast information is frequently provided to the Board of Directors. This continual financial assessment process further enables the Corporation to mitigate risks. The Corporation continues to satisfy all liabilities and commitments as they come due. The economic situation during the last several years has created significant commodity price volatility. Natural gas prices have remained low for several years from continued high US domestic natural gas production that has increased supply and the ongoing weak North American economy that has negatively impacted demand. These factors, in combination with mild weather conditions, have resulted in historic high inventory levels and AECO gas is presently trading at approximately $1.80/mcf. However, crude oil prices have generally remained relatively strong, primarily influenced by middle-east tensions and associated supply concerns, with WTI currently trading at approximately US$107/bbl. The outlook for the Corporation from a prolonged weak commodity price environment, particularly natural gas, would be reductions in operating netbacks, funds from operations and capital expenditures. In order to strengthen our financial position and balance our cash flows, in 2010 we completed two non-core asset dispositions and on April 14, 2011 we closed the sale of a 37% non-controlling interest in Longview with the net proceeds utilized to further repay bank indebtedness. These steps have allowed us to repay significant bank indebtedness and maturing convertible debentures and also enabled us to focus capital spending on our Glacier Montney natural gas resource play. However, we continue to be very cognizant of improving our financial flexibility in the current environment. We believe that Advantage has implemented strategies to protect our business as much as possible in the current industry and economic environment. We have implemented a strategy to substantially balance funds from operations and our capital program expenditure requirements. Historically we have had a successful hedging program that helped to reduce the volatility of funds from operations. However, we have no natural gas hedges for 2012 and are exposed to risks as a result of the current economic situation. We continue to closely monitor the possible impact on our business and strategy, and will make adjustments as necessary with prudent management. Advantage Oil & Gas Ltd. - 28 Shareholders’ Equity and Convertible Debentures Advantage has utilized a combination of equity, convertible debentures and bank debt to finance acquisitions and development activities. As at December 31, 2011, Advantage had 166.3 million common shares outstanding. During 2011 Advantage issued 2,212,031 common shares to employees in accordance with the vesting provisions of the RSPIP. As at March 23, 2012, common shares outstanding have increased to 166.6 million. The Corporation had $86.2 million convertible debentures outstanding at December 31, 2011 that were immediately convertible to 10.0 million common shares based on the applicable conversion price (December 31, 2010 - $148.5 million outstanding and convertible to 13.0 million common shares). During the year ended December 31, 2011, there were no conversions of debentures. The principal amounts of the 7.75% and 8.00% convertible debentures matured in December 2011 and were settled with $62.3 million in cash. We have $86.2 million of 5.00% debentures outstanding that mature in January 2015. Our convertible debenture obligation can be settled through the payment of cash or issuance of common shares at Advantage’s option. Bank Indebtedness, Credit Facilities and Other Obligations At December 31, 2011, Advantage had consolidated bank indebtedness outstanding of $233.9 million consisting of $142.5 million and $91.4 million for each of the legal entities Advantage and Longview, respectively. Bank indebtedness has decreased $56.8 million since December 31, 2010, primarily due to net proceeds received from the sale of a 37% non-controlling interest in Longview, partially offset by the maturity and settlement of convertible debentures and capital expenditures to complete our Phase III and to commence our Phase IV development programs at Glacier. Advantage’s consolidated credit facilities of $475 million at December 31, 2011 include $275 million with Advantage and $200 million with Longview (the “Credit Facilities”). The credit facilities are each collateralized by a $1 billion floating charge demand debenture covering all assets of the legal entities. As well, the borrowing bases for the credit facilities are determined through utilizing the legal entities regular reserve estimates. The banking syndicate thoroughly evaluates the reserve estimates based upon their own commodity price expectations to determine the amount of the borrowing bases. Revisions or changes in the reserve estimates and commodity prices can have either a positive or a negative impact on the borrowing bases. As a result of the disposition of a non-controlling interest in Longview that closed on April 14, 2011, the Advantage credit facility was reduced to $275 million and Longview’s credit facility was established at $200 million. The next annual reviews are scheduled to occur in April and June 2012. There can be no assurance that the credit facilities will be renewed at the current borrowing base levels at that time. Advantage had a consolidated working capital deficiency of $90.6 million as at December 31, 2011. Our working capital includes items expected for normal operations such as trade receivables, prepaids, deposits, trade payables and accruals. Working capital varies primarily due to the timing of such items, the current level of business activity including our capital expenditure program, commodity price volatility, and seasonal fluctuations. Our working capital deficiency is usually higher during the winter months, as would be expected, due to accounts payable and accrued liabilities associated with our active capital expenditure program. We do not anticipate any problems in meeting future obligations as they become due given the level of our funds from operations and undrawn Credit Facilities. It is also important to note that working capital is effectively integrated with Advantage’s revolving operating loan facility, which assists with the timing of cash flows as required. Non-Controlling Interest On April 14, 2011, Longview completed its initial public offering at a price of $10 per common share issuing 17,250,000 common shares and raising gross proceeds of $172.5 million (including full exercise of the over-allotment option on April 28, 2011). Concurrent with the closing of the Offering, Longview purchased the Acquired Assets from Advantage for total consideration of $546.9 million, comprised of 29,450,000 common shares of Longview representing a 63% equity ownership and $252.4 million in cash. The remaining 37% equity ownership of Longview is held by outside interests or non-controlling interests. As Advantage is the parent company and has a majority ownership interest of Longview, Advantage’s consolidated financial statements include 100% of Longview’s accounts. On closing of the Acquisition, non-controlling interest of $106.1 million was recognized which represents Longview’s independent shareholders 37% ownership interest in the net assets of Longview. Non-controlling interest on the statement of financial position is continually adjusted for the independent shareholders’ share of Longview’s net income that is consolidated within Advantage’s financial results and reduced for any dividends paid by Longview to the independent shareholders. Therefore, for the year ended December 31, 2011, Advantage recognized a $7.4 million reduction to net income related to Longview’s net income attributable to the non-controlling interests. This $7.4 million increased non-controlling interest on the statement of financial position with a decrease of $6.9 million related to dividends declared by Longview to the non-controlling interest ownership. Advantage Oil & Gas Ltd. - 29 Capital Expenditures ($000) Drilling, completions and workovers Well equipping and facilities Land and seismic Other Expenditures on property, plant and equipment Expenditures on exploration and evaluation assets Proceeds from property disposition Net capital expenditures (1) Three months ended December 31 2011 2010 Year ended December 31 $ $ $ $ 85,061 15,984 138 14 101,197 1,624 (114) 102,707 55,578 11,896 458 97 68,029 529 (226) 68,332 2011 199,170 52,857 1,704 443 254,174 3,006 (1,099) 256,081 2010 169,769 48,782 2,729 403 221,683 2,091 (69,676) 154,098 $ $ $ $ (1) Net capital expenditures excludes changes in non-cash working capital and change in decommissioning liability. Advantage’s preference is to operate a high percentage of properties such that we can maintain control of capital expenditures, operations and cash flows. Advantage’s business structure has been established in order to fully capitalize on both natural gas and crude oil exploration and development opportunities. Advantage is focused primarily on developing the significant natural gas resource play at Glacier, Alberta while retaining a significant investment in Longview that is focused on oil and natural gas liquids production and development. Advantage on a legal entity basis spent a net $202.1 million on property, plant and equipment and exploration and evaluation assets for the year ended December 31, 2011, including $178.6 million at Glacier, $4.0 million at Brazeau, $4.0 million in Saskatchewan, $3.0 million at Nevis, $3.0 million at Westerose and the remaining balance at other areas. Capital spending projects at Brazeau, Saskatchewan, Nevis and Westerose were incurred by Advantage in preparation for the eventual disposition of the properties to Longview that closed on April 14, 2011. However, Advantage continues to focus on development of our Montney natural gas resource play at Glacier where we will continue to employ a phased development approach. Our Phase III expansion began at the end of the second quarter of 2010 and finished in the second quarter of 2011, including the drilling of 28 horizontal wells (100% working interest) and the fabrication of a new processing train to facilitate expansion of our Glacier gas plant to its current capacity of 100 mmcf/d. In July 2011, the Board of Directors of Advantage approved a capital and operating budget for the twelve month period ending June 30, 2012 of $216 million of which $200 million (93%) is allocated to Glacier. The capital budget is focused on a Phase IV development program at Glacier with two key objectives: i) increase throughput capacity at our Glacier gas plant from 100 mmcf/d to 140 mmcf/d by the second quarter of 2012; and ii) further evaluate the Middle and Lower Montney formations. During much of the spring and summer, field conditions were poor with severe wet weather that created challenges for the industry and our Glacier Phase IV capital program was delayed by approximately 1½ months while conditions improved. As at December 31, 2011, Advantage had three drilling rigs contracted and had drilled 18 wells of our Phase IV program with 3 wells drilling at year-end and subsequently rig released. Completion of our Phase IV wells has begun and 8 wells were completed and tested by year-end. In October 2011, we successfully commissioned the acid gas injection system which is now capable of disposing acid gas volumes for plant inlet gas volumes in excess of 140 mmcf/d. In addition, TCPL completed further looping of their sales pipeline lateral in preparation for our expansion to 140 mmcf/d. These projects represent significant milestones towards achieving our Glacier Phase IV development and will provide additional flexibility for future production growth. Longview’s 2011 capital budget was 100% focused on oil or oil with liquids rich solution gas projects. The majority of their 2011 capital program was completed during the third and fourth quarters of 2011 due to the wet ground conditions that hampered activities in the spring and summer. For the period from April 14 to December 31, 2011, Longview spent a net $55.0 million on property, plant and equipment and exploration and evaluation assets which included $15.1 million at Nevis, $13.5 million at Brazeau, $7.1 million at Westerose, $5.7 million at Steelman, $4.3 million at Sunset, and $4.0 million at Midale with the remaining spending for miscellaneous projects. Longview deployed two drilling rigs in Alberta and an additional rig targeting the Midale formation in southeast Saskatchewan. As of December 31, 2011, they drilled 20.7 net (30 gross) oil wells (100% success rate). During the third and fourth quarters Longview conducted maintenance activities, workovers and reactivations that had been delayed due to poor field conditions. This activity positively impacted production for the fourth quarter of 2011 that average 6,823 boe/d, an increase of 12% as compared to the prior quarter. Advantage Oil & Gas Ltd. - 30 Sources and Uses of Funds The following table summarizes the various funding requirements during the years ended December 31, 2011 and 2010 and the sources of funding to meet those requirements: ($000) Sources of funds Funds from operations Proceeds from change in ownership of Longview Change in non-cash working capital and other Property dispositions Increase in bank indebtedness Uses of funds Expenditures on property, plant and equipment Convertible debenture maturities Decrease in bank indebtedness Dividends declared by Longview to non-controlling interest Expenditures on decommissioning liability Expenditures on exploration and evaluation assets Reduction of capital lease obligations Year ended December 31 2011 2010 $ $ $ $ 197,031 160,757 27,659 1,099 - 386,546 254,174 62,294 56,754 6,915 3,335 3,006 68 386,546 $ $ 173,301 - 17,979 69,676 40,395 301,351 221,683 69,927 - - 6,275 2,091 1,375 301,351 $ $ Advantage has historically focused on balancing our funds from operations and expenditures, particularly property, plant and equipment, to maintain a strong financial position and preserve financial flexibility. Funds from operations for 2011 have been strong, driven by increases in production and continued gains from our hedging program, which demonstrates the clear ongoing improvement in our financial and operating results from our focused development program. For the year ended December 31, 2011, average daily production increased 16% above the prior year, with a 28% increase in natural gas production partially offset by decreases in both crude oil and NGLs production. For the year ended December 31, 2011, we recognized a net realized derivative gain of $25.8 million on settled derivative contracts, primarily as a result of lower average actual natural gas prices during the year as compared to our established average hedge prices. Our successful commodity price risk management program continued to realize significant gains on derivatives during 2011 that has helped to offset the continued weak natural gas prices and positively impact funds from operations. Our net realized derivative gain has decreased during 2011 as compared to 2010 as we had less natural gas production hedged for this year at lower average prices and we have generally realized losses on our crude oil hedges. Funds from operations have also benefited during this year from higher crude oil prices and continued cost reductions, such as operating costs, general and administrative expense, and finance expense. Unfortunately, natural gas prices still remain weak and pose a continuing challenge to the entire natural gas industry. During the second quarter of 2011 Advantage disposed of a 37% non-controlling interest in Longview thereby raising net cash proceeds that significantly reduced bank indebtedness. In December 2011 the principal amounts of the 7.75% and 8.00% convertible debentures matured and were settled with $62.3 million in cash. Advantage Oil & Gas Ltd. - 31 Annual Financial Information The following is a summary of selected financial information of the Corporation for the years indicated. Total sales (before royalties) ($000) Net income (loss) ($000) per share - basic and diluted Total assets ($000) Long term financial liabilities ($000) (1) Distributions declared per Trust Unit (2) Year ended Dec. 31, 2011 $ 355,288 $ (152,772) $ (0.92) $ 1,972,789 $ 308,574 $ - Year ended Year ended Dec. 31, 2010 Dec. 31, 2009 (3) 319,368 343,005 $ 40,920 (86,426) $ 0.25 (0.56) $ 1,965,945 1,927,241 $ 363,675 384,700 $ 0.08 $ - $ $ $ $ $ $ (1) Long term financial liabilities exclude decommissioning liability and deferred income tax liability. (2) On March 18, 2009 Advantage annouced the discontinuance of distributions. (3) Total sales (before royalties) and net loss for 2009 were prepared in accordance with the previous Canadian generally accepted accounting principles. Total sales (before royalties) decreased from 2009 to 2010 due to lower natural gas prices and corporate production. The decrease in production was primarily attributable to significant non-core asset dispositions completed during both 2009 and 2010, with the net proceeds from such dispositions utilized to reduce outstanding bank indebtedness. Sales (before royalties) have increased during 2011 primarily from significant increases in our production due to our successful exploration and development activities. Natural gas sales in particular have benefited from our Montney natural gas resource play at Glacier, Alberta where we have increased production capacity with our continued facilities and infrastructure expansion work. However, the low natural gas prices that have persisted during these years have contributed to the recognized net losses. During 2010 Advantage disposed of several non-core properties during the year and recognized a $45.6 million net gain which resulted in the reported net income. Our net loss for 2011 was considerable as Advantage determined that the significant reduction in natural gas prices recognized within our year-end independent reserves evaluation was an indicator of impairment. As a result, we completed an impairment assessment and calculated an estimated recoverable amount for our natural gas concentrated CGUs. Based upon these calculations, we recognized an impairment loss of $187.7 million related to two CGUs that consist of conventional natural gas focused properties located in Western and Eastern Alberta that had suffered a significant deterioration in value due to the challenging natural gas price environment. Total assets have continually decreased from 2009 through 2011 due to the asset dispositions, depreciation expense and impairment losses that have exceeded capital expenditure activity. From 2009 to 2011 we have also experienced significant decreases in long term financial liabilities due to our concerted efforts to reduce debt, including utilizing net proceeds from significant asset dispositions, an equity financing, and a convertible debenture issuance. We also suspended all distributions in March 2009 and completed our conversion from an income trust to a corporation in July 2009. Advantage Oil & Gas Ltd. - 32 Quarterly Performance ($000, except as otherwise indicated) Daily production 2011 2010 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Natural gas (mcf/d) Crude oil and NGLs (bbls/d) Total (boe/d) 137,480 6,498 29,411 134,353 6,246 28,638 136,986 5,919 28,750 111,145 6,251 24,775 106,125 6,620 24,308 104,714 6,835 24,287 107,821 7,395 25,365 87,346 7,975 22,533 Average prices Natural gas ($/mcf) Excluding hedging Including hedging AECO daily index Crude oil and NGLs ($/bbl) Excluding hedging Including hedging WTI ($US/bbl) Total sales including realized hedging Net income (loss) per share - basic - diluted Funds from operations $ $ $ 3.18 3.76 3.20 $ $ $ 3.62 4.16 3.66 $ $ $ 3.77 4.29 3.88 $ $ $ 3.72 4.55 3.78 $ $ $ 3.49 4.81 3.63 $ $ $ 3.51 4.80 3.53 $ $ $ 3.81 5.58 3.89 $ $ $ 5.26 6.87 4.95 $ $ $ $ $ $ $ $ 87.06 85.88 94.02 98,858 (145,063) (0.87) (0.87) 54,634 $ $ $ $ $ $ $ $ 76.56 77.33 89.81 95,797 (2,997) (0.02) (0.02) 50,108 $ $ $ $ $ $ $ $ 88.27 86.21 102.55 99,971 997 0.01 0.01 52,041 $ $ $ $ $ $ $ $ 75.41 72.82 94.25 86,488 (5,709) (0.03) (0.03) 40,248 $ $ $ $ $ $ $ $ 69.19 64.14 85.18 86,012 (22,889) (0.14) (0.14) 40,628 61.84 $ 59.01 $ 76.21 $ 83,335 $ $ (659) $ - $ - $ 37,698 $ $ $ $ $ $ $ $ 64.66 61.80 77.98 96,377 31,379 0.19 0.19 45,291 $ $ $ $ $ $ $ $ 67.23 62.42 78.79 98,777 33,089 0.20 0.20 49,685 The table above highlights the Corporation’s performance for the fourth quarter of 2011 and also for the preceding seven quarters. Production for the first quarter of 2010 was comparable to the fourth quarter of 2009 but increased dramatically during the second quarter of 2010 as our new gas plant was completed and production from Glacier was increased to between 50 and 55 mmcf/d. We completed two asset dispositions during the end of the second quarter of 2010 representing approximately 1,700 boe/d that resulted in slightly lower production. The full impact of these dispositions resulted in a decrease in production for the third quarter of 2010 with our production remaining relatively consistent through to the first quarter of 2011. Production increased significantly in the second quarter of 2011 as the Phase III expansion at Glacier was completed with production capacity at 100 mmcf/d. Our production has remained comparable for the remainder of 2011 with a modest increase in the fourth quarter from production additions attributed to Longview’s capital expenditure program. Our financial results, particularly sales and funds from operations are significantly impacted by commodity prices. During 2010 and 2011, natural gas prices have remained low which has decreased our corresponding sales and funds from operations, although increasing production and strengthening crude oil and NGLs prices have partially mitigated the impact. Advantage has recognized net losses during 2010 and 2011 primary driven by weak natural gas prices. During these periods we have continued to experience a reduction in costs including royalties, operating expenses, general and administrative expense, and finance expense. We recognized net income in the first and second quarters of 2010 due to higher natural gas prices and a $45.6 million net gain recognized on the disposal of several non-core properties. Our net loss during the fourth quarter of 2011 was considerable as we recognized an impairment loss of $187.7 million related to two CGUs that consist of conventional natural gas focused properties located in Western and Eastern Alberta that had suffered a significant deterioration in value due to the challenging natural gas price environment. Critical Accounting Estimates The preparation of financial statements in accordance with IFRS requires Management to make certain judgments and estimates. Changes in these judgments and estimates could have a material impact on the Corporation’s financial results and financial condition. Management relies on the estimate of reserves as prepared by the Corporation’s independent qualified reserves evaluator. The process of estimating reserves is critical to several accounting estimates. The process of estimating reserves is complex and requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development and production activities becomes available and as economic conditions impact crude oil and natural gas prices, operating expense, royalty burden changes, and future development costs. Reserve estimates impact net income and comprehensive income through depreciation and impairment of oil and gas properties. The reserve estimates are also used to assess the borrowing bases for the Corporation’s credit facilities. Revision or changes in the reserve estimates can have either a positive or a negative impact on asset values, net income, comprehensive income and the borrowing bases of the Corporation. Advantage Oil & Gas Ltd. - 33 Management’s process of determining the provision for deferred income taxes, the provision for decommissioning liability costs and related accretion expense, the fair values initially assigned to the convertible debentures liability and equity components, and the fair values assigned to any acquired company’s assets and liabilities in a business combination is based on estimates. These estimates are significant and can include proved and probable reserves, future production rates, future commodity prices, future costs, future interest rates, future tax rates and other relevant assumptions. Revisions or changes in any of these estimates can have either a positive or a negative impact on asset and liability values, net income and comprehensive income. In accordance with IFRS, derivative assets and liabilities are recorded at their fair values at the reporting date, with gains and losses recognized directly into comprehensive income in the same period. The fair value of derivatives outstanding is an estimate based on pricing models, estimates, assumptions and market data available at that time. As such, the recognized amounts are non-cash items and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions. International Financial Reporting Standards Canadian publicly accountable enterprises have implemented International Financial Reporting Standards (“IFRS”) for the fiscal years beginning on or after January 1, 2011. The transition date to IFRS was January 1, 2010 and comparative figures for 2010 and Advantage’s financial position as at January 1, 2010 have been restated to IFRS from the previous Canadian generally accepted accounting principles (“Previous GAAP”). Reconciliations to IFRS from Previous GAAP financial statements including the impact of the transition on the Corporation's reported financial position and financial performance, including the nature and effect of significant changes in accounting policies from those used in the Corporation’s consolidated financial statements for the year ended December 31, 2010, are summarized in note 25 to the unaudited consolidated financial statements. The following discussion explains the significant differences between IFRS and the Previous GAAP followed by the Corporation. a) Property, plant and equipment Under Previous GAAP, the Corporation, like many Canadian oil and gas reporting issuers, applied the “full cost” concept in accounting for its oil and gas assets. Under full cost, capital expenditures were maintained in a single cost centre for each country, and the cost centre was subject to a single depletion and depreciation calculation and impairment test. Under IFRS, the Corporation makes a much more detailed assessment of its oil and gas assets that impact depreciation and impairment calculations. Included in this assessment is an ongoing appraisal of exploration and evaluation expenditures (“E&E”). Under Canadian GAAP, it was only necessary to track costs associated with unproved properties that would be excluded from depletion and depreciation calculations. Under IFRS, a company may choose to account for E&E under its previous GAAP and capitalize such costs without recording depreciation expense until the expenditures are determined to represent technically feasible and commercially viable projects at which time the costs are moved to development properties or expensed accordingly. Advantage capitalizes E&E costs except for costs incurred before the acquisition of rights to explore, and to begin depreciating when technically feasible and commercially viable. As at transition on January 1, 2010, $6.9 million was reclassified from property, plant and equipment to exploration and evaluation assets. As well, under Previous GAAP the Corporation did not recognize gains or losses on the disposal of oil and gas properties unless such dispositions would change the depletion rate by 20% or more while IFRS requires such recognition. This results in an increase to the carrying value and a gain on sale of property, plant and equipment. b) Depreciation For Previous GAAP purposes, the full cost method of accounting for oil and gas properties requires a single calculation of depletion and depreciation of the carrying value of PP&E based on proved reserves. However, IFRS requires an allocation of the amount recognized as PP&E to each significant identified component and each component depreciated separately, utilizing an appropriate method of depreciation. This component depreciation of PP&E results in an increased number of calculations of depreciation expense and impacts the amount of depreciation expense recognized. IFRS also permits the option of using either proved or proved and probable reserves in the depreciation calculation. Advantage has utilized proved and probable reserves to calculate depreciation expense as we believe it represents a better approximation of useful life and depletion of reserves. c) Impairment of Assets Under Canadian GAAP, impairment calculations are prepared according to a two-step test generally conducted at a country level. Step one involves a comparison of the PP&E carrying value to the undiscounted net cash flows of proved reserves. If a company should fail step one, step two is completed to measure the amount of impairment whereby the PP&E carrying value is compared to a calculated fair value with any excess carrying value above the fair value recognized as an impairment loss. Impairment losses recognized under Canadian GAAP are not subsequently reversed. Under IFRS, impairment testing is completed at an individual asset group or “Cash Generating Unit” level (“CGU”) when indicators suggest there may be impairment. A CGU is defined as the smallest Advantage Oil & Gas Ltd. - 34 group of assets that produce independent cash flows. Impairment of assets at a CGU level use a one-step approach for testing and measuring asset impairment, with asset carrying values compared to the higher of “Value in Use” and “Fair Value less Costs to Sell”. The IFRS methodology may result in the possibility of more frequent impairments in the carrying value of PP&E. However, under IFRS previous impairment losses must be reversed where circumstances change such that the previously recognized impairment has been reduced. d) Decommissioning Liabilities Both Canadian GAAP and IFRS require a company to provide for a liability related to decommissioning PP&E. Both methodologies are similar and we have determined there to be no significant difference for Advantage, other than a difference related to discount rates. Canadian GAAP requires that the decommissioning liability be discounted at a credit-adjusted risk-free rate while IFRS requires that the decommissioning liability be discounted at an appropriate rate with either the cash flows or rate adjusted for risks. Advantage has selected to use the risk-free rate for discounting purposes as we believe this accurately represents a market-based rate for such a liability and at transition date the decommission liability was increased $101.1 million and charged to deficit. e) Convertible debentures liability component Under Previous GAAP convertible debentures are financial liabilities consisting of a liability with an embedded conversion feature. As such, the debentures were segregated between liabilities and equity and the debenture liabilities are presented at less than their eventual maturity values. The discount of the liability component as compared to maturity value is accreted over the debenture term and expensed accordingly. As debentures are converted to common shares, an appropriate portion of the liability and equity components were transferred to share capital. Prior to July 9, 2009, Advantage was an Income Trust that operated under the name Advantage Energy Income Fund. As an income trust, convertible debentures were convertible into Trust Units, which contained a redemption feature which effectively made the conversion option a “putable instrument” according to IFRS. As such, convertible debentures were liabilities, with no equity component. Upon conversion to a corporation on July 9, 2009, all convertible debentures became convertible into common shares, and were no longer deemed to contain a “putable instrument”. Under IFRS, retrospective restatement of the convertible debentures in existence at July 9, 2009 and still outstanding at transition resulted in the liability component restated to their full maturity values, less any issue costs and no value assigned to the equity component of the conversion features of these same debentures. Accretion expense as recorded under Previous GAAP was reduced, as only debenture issue costs gave rise to accretion expense. f) Deferred Income Taxes Deferred income tax calculated according to IFRS is substantially similar to Previous GAAP and arises from differences between the accounting and tax bases of our assets and liabilities. To the extent that assets and liabilities have changed from transition to IFRS, the amount of deferred income tax liability has been impacted. Additionally, under Previous GAAP deferred income tax liabilities were required to be disclosed as either current or long-term. Under IFRS, all deferred income tax liabilities are considered to be non-current liabilities. g) First Time Adoption of International Financial Reporting Standards IFRS 1 provides the framework for the first time adoption of IFRS and specifies that an entity shall apply the principles under IFRS retrospectively. IFRS 1 also specifies that the adjustments that arise on retrospective conversion to IFRS from other GAAP should be directly recognized in retained earnings. Certain optional exemptions and mandatory exceptions to retrospective application are provided under IFRS 1. The Corporation has taken the following exemptions:  Companies using full-cost accounting are allowed to measure their oil and gas assets at the amount determined under the Previous GAAP at the date of transition. This amount is pro-rated to the underlying assets based upon the value of proved and probable reserves at transition date, discounted at 10%.  Companies using the full cost book value as deemed cost exemption are allowed to measure the liabilities for decommissioning, restoration and similar liabilities at the date of transition and recognize directly in retained earnings any difference between that amount and the carrying amount determined under Previous GAAP.    IFRS 3 Business Combinations has not been applied to acquisitions of subsidiaries or of interests in associates and joint ventures that occurred before January 1, 2010. IFRS 2 Share-based Payment has not been applied to any equity instruments that were granted on or before November 7, 2002, nor has it been applied to equity instruments granted after November 7, 2002 that vested before January 1, 2010. IAS 17 Leases has been applied as of transition date rather than at the lease’s inception date. Advantage Oil & Gas Ltd. - 35   IAS 32 Financial Instruments Presentation will not be applied for compound financial instruments where the liability component is no longer outstanding. IAS 23 Borrowing Costs will not be applied before January 1, 2010. h) New standards and interpretations not yet adopted Standards issued but not yet effective up to the date of issuance of the Corporation’s financial statements are listed below. This listing is of standards and interpretations issued which the Corporation reasonably expects to be applicable at a future date. The Corporation intends to adopt those standards when they become effective. The Corporation has yet to assess the full impact of these standards. Standards issued but not yet effective up to the date of issuance of the Corporation’s financial statements are listed below. This listing is of standards and interpretations issued which the Corporation reasonably expects to be applicable at a future date. The Corporation intends to adopt those standards when they become effective. The Corporation has yet to assess the full impact of these standards. IFRS 9 Financial Instruments: Classification and Measurement IFRS 9 is intended to supersede IAS 39, Financial Instruments: Recognition and Measurement and will be published in three phases, of which the first phase has been published. The first phase addresses the accounting for financial assets and financial liabilities. The second phase will address the impairment of financial instruments, and the third phase will address hedge accounting. For financial assets, IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, and replaces the multiple rules in IAS 39. The approach in IFRS 9 is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The new standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39. For financial liabilities, although the classification criteria for financial liabilities will not change under IFRS 9, the approach to the fair value option for financial liabilities may require different accounting for changes to the fair value of a financial liability as a result of changes to an entity’s own credit risk. This standard is not applicable until January 1, 2015. IFRS 10 Consolidated Financial Statements IFRS 10 is a new standard that will replace SIC 12, “Consolidation – Special Purpose Entities” and IAS 27 “Consolidated and Separate Financial Statements”. The new standard eliminates the current risks and rewards approach and establishes control as the single basis for determining the consolidation of an entity. This standard is not applicable until January 1, 2013. IFRS 11 Joint Arrangements IFRS 11 requires a venture to classify its interest in a joint arrangement as a joint venture or joint operation. Joint ventures will be accounted for using the equity method of accounting whereas for a joint operation, the venture will recognize its share of the assets, liabilities, revenue and expenses. Under existing IFRS, entities have the choice to proportionately consolidate or equity account for interests in joint ventures. IFRS 11 supersedes IAS 31, Interests in Joint Ventures and SIC-13, Jointly Controlled Entities, Non-Monetary Contributions by Venturers. This standard is not applicable until January 1, 2013. IFRS 12 Disclosure of Interests in Other Entities IFRS 12 provides the required disclosures for interests in subsidiaries and joint arrangements. These disclosures will require information that will assist users of financial statements to evaluate the nature, risks and financial effects associated with an entity’s interests in subsidiaries and joint arrangements. This standard is not applicable until January 1, 2013. IFRS 13 – Fair Value Measurement IFRS 13 is a comprehensive standard for fair value measurement and disclosure requirements for use across all IFRS standards. The new standard clarifies that fair value is the price that would be received to sell an asset, or paid to transfer a liability in an orderly transaction between market participants, at the measurement date. It also establishes disclosures about fair value measurement. Under existing IFRS, guidance on measuring and disclosing fair value is dispersed among the specific standards requiring fair value measurement and in many cases does not reflect a clear measurement basis or consistent disclosures. This standard is not applicable until January 1, 2013. Advantage Oil & Gas Ltd. - 36 IAS 28 – Investments in Associates and Joint Ventures IAS 28 has been amended to include joint ventures in its scope and to address the changes in IFRS 10 – 13. Evaluation of Disclosure Controls and Procedures Advantage’s Chief Executive Officer and Chief Financial Officer have designed disclosure controls and procedures (“DCP”), or caused it to be designed under their supervision, to provide reasonable assurance that all material information relating to the Corporation is made known to them by others, particularly during the period in which the annual filings are being prepared, and information required to be disclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. Management of Advantage, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Corporation’s DCP as at December 31, 2011. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that the DCP are effective as of the end of the year, in all material respects. Evaluation of Internal Controls over Financial Reporting Advantage’s Chief Executive Officer and Chief Financial Officer are responsible for establishing and maintaining internal control over financial reporting (“ICFR”). They have as at the quarter ended December 31, 2011, designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The control framework Advantage’s officers used to design the Corporation’s ICFR is the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations. Management of Advantage, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Corporation’s ICFR as at December 31, 2011. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that the ICFR are effective as of the end of the year, in all material respects. Advantage’s Chief Executive Officer and Chief Financial Officer are required to disclose any change in the ICFR that occurred during our most recent interim period that has materially affected, or is reasonably likely to affect, the Corporation’s internal controls over financial reporting. No material changes in the internal controls were identified during the interim period ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, our ICFR. It should be noted that while the Chief Executive Officer and Chief Financial Officer believe that the Corporation’s design of DCP and ICFR provide a reasonable level of assurance that they are effective, they do not expect that the control system will prevent all errors and fraud. A control system, no matter how well conceived or operated, does not provide absolute, but rather is designed to provide reasonable assurance that the objective of the control system is met. The Corporation’s internal control over financial reporting may not prevent or detect all misstatements because of inherent limitations. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with the Corporation’s policies and procedures. Corporate Governance The Corporation’s corporate governance practices can be found in the Management Information Circular. As a foreign private issuer listed on the New York Stock Exchange (the "NYSE"), Advantage is not required to comply with most of the NYSE rules and listing standards and instead may comply with domestic Canadian requirements. Advantage is, however, required to comply with the following NYSE Rules: (i) Advantage must have an audit committee that satisfies the requirements of Rule 10A-3 under the United States Securities Exchange Act of 1934, as amended; (ii) the Chief Executive Officer must promptly notify the NYSE in writing after an executive officer becomes aware of any non-compliance with the applicable NYSE Rules; (iii) submit an executed section 303A annual written affirmation to the NYSE, as well as a Section 303A interim affirmation each time certain changes occurs to the audit committee; and (iv) provide a brief description of any significant differences between its corporate governance practices and those followed by U.S. domestic issuers under NYSE listing standards. Advantage has reviewed the NYSE listing standards followed by U.S. domestic issuers listed under the NYSE and confirms that its corporate governance practices do not differ significantly from such standards. Advantage Oil & Gas Ltd. - 37 Outlook Advantage’s business structure has been established in order to fully capitalize on both natural gas and crude oil exploration and development opportunities. Advantage is focused primarily on developing the significant natural gas resource play at Glacier, Alberta while retaining a significant investment in Longview that is focused on crude oil and natural gas liquids production and development. Advantage At Glacier, our continued successful drilling results has increased the quality and magnitude of our Montney natural gas resource which is contained in approximately 300 meters in the Upper, Middle and Lower Montney formations. Our high quality asset at Glacier contains significant scope and scale as validated by Sproule’s resource assessment and is underpinned with one of the lowest cost structures in Western Canada which provides Advantage with a significant drilling inventory. Our recent drilling which involved lateral and vertical delineation through the very thick Montney formation across our contiguous land block has added another dimension to Glacier, specifically with the Middle Montney. We estimate that the current drilling inventory at Glacier to be in excess of 900 wells which only includes development of 3 layers in the Montney formation. Our capital budget for the twelve month period ending June 30, 2012 was set at $216 million of which $200 million is focused on a Phase IV development program at Glacier with two key objectives: i) increase throughput capacity at our Glacier gas plant from 100 mmcf/d to 140 mmcf/d by the second quarter of 2012; and ii) further evaluate the Middle and Lower Montney formations. As a result of the prevailing low natural gas pricing environment, production at Glacier will be maintained between 90 mmcf/d to 100 mmcf/d until we see a sustained increase in natural gas pricing. We will utilize our inventory of 29 gross (28.5 net) Montney wells that have been drilled to maintain targeted production rates at Glacier by producing and/or completing these wells as required. Additionally, we believe that the high industry activity levels that have increased service and supply costs could subside during the latter part of 2012 which would benefit natural gas development economics. We believe that it is prudent to maintain capital spending discipline and financial flexibility in this current natural gas price environment. We also believe that the current price of natural gas is unsustainable for generating sufficient full cycle economic returns in the vast majority of North American natural gas plays and anticipate an improvement in the natural gas price environment. As a result, we are positioning our Glacier gas plant with the capability to ramp up production capacity to 140 mmcf/d by completing modifications as planned in our Phase IV capital program. At this time, we are providing interim guidance for the six months ending June 30, 2012: Production average 22,800 boe/d to 23,400 boe/d Royalty rate 8% to 10% Operating expense $5.70/boe to $6.00/boe Capital expenditures $65 million to $75 million Additional capital budget and guidance details will be provided pending our evaluation of future delineation plans for our liquids rich Middle Montney formation in order to determine the natural gas and NGL production and reserves potential. This evaluation will include detailed analysis and interpretation of recent geological, engineering and completions data which we obtained from our Middle Montney Phase IV wells. In addition, we have 1 remaining Middle Montney well and 2 Lower Montney wells that are drilled and are awaiting completion which we anticipate undertaking after spring break-up. We expect the results of this information and our evaluation to provide more information in regard to determining a systematic delineation plan for the balance of 2012 and beyond. We will continue with a technically focused and financially disciplined approach to create value from our Glacier property and will revisit our 2012 capital spending plans as required taking into account commodity price and market dynamics. Longview With regards to Longview, Advantage has retained a 63% controlling ownership interest with the potential for growth opportunities accompanied by a stable yield. Our investment provides a significant contribution to funds from operations from annual dividends of approximately $17.7 million that will be utilized to partially fund our capital expenditure program. Longview’s operations commenced on April 14, 2011 and from April 14 to December 31, 2011, Longview has demonstrated strong financial and operating results with funds from operations supported by high crude oil prices and demonstrated production growth. Longview’s 2011 capital program and routine well maintenance activities were initially delayed due to poor field conditions from severe wet weather during much of the spring and summer. Longview was able to commence their Alberta capital expenditure program in July with the Saskatchewan program beginning in September after delays created by wet weather conditions. Notwithstanding the delays, Longview was able to expedite their efforts and complete their capital expenditure program. Longview Advantage Oil & Gas Ltd. - 38 deployed two drilling rigs in Alberta and an additional rig targeting the Midale formation in southeast Saskatchewan. As of December 31, 2011, they spent a net $55.0 million and drilled 20.7 net (30 gross) oil wells (100% success rate). This activity significantly increased production whereby Longview daily production averaged 6,823 boe/d for the fourth quarter, an increase of 16% from that realized during their initial quarter ended June 30, 2012. Longview’s 2012 budget is approximately $73 million including the drilling of 25.3 net (34 gross) wells. The following table summarizes operational guidance for Longview for the year ending December 31, 2012: Production average 6,600 boe/d to 6,800 boe/d % of oil & liquids 77% Exit rate 6,800 boe/d to 7,000 boe/d Production growth % 8% Royalty rate 18% to 20% Operating expense $16.00/boe to $17.00/boe Capital expenditures $70 million to $75 million Longview has contracted three rigs, two of which will target Alberta prospects and the additional rig will target the Midale formation in southeast Saskatchewan. The capital expenditure program also includes analysis of cores that were taken from the Duvernay and Nordegg shale formations on a well that was drilled at Sunset in the fourth quarter of 2011. Detailed core analysis is expected by summer of 2012. Longview has begun executing their 2012 capital program, focusing on operational and cost efficiencies to increase returns and produce stable cash flows with a conservative financial structure. Longview's business strategy is to provide shareholders with attractive long term returns that combine both growth and yield by exploiting their assets in a financially disciplined manner and by acquiring additional long-life oil and gas assets of a similar nature. Additional Information Additional information relating to Advantage can be found on SEDAR at www.sedar.com and the Corporation’s website at www.advantageog.com. Such other information includes the annual information form, the annual information circular – proxy statement, press releases, material change reports, material contracts and agreements, and other financial reports. The annual information form will be of particular interest for current and potential shareholders as it discusses a variety of subject matter including the nature of the business, description of our operations, general and recent business developments, risk factors, reserves data and other oil and gas information. March 23, 2012 Advantage Oil & Gas Ltd. - 39 Consolidated C Financial St tatements Managem ment’s Respo onsibility for Financial St tatements The Manag of the con annual rep Internation best estima contained t gement of Adva solidated finan port. The con nal Financial Re ates and carefu throughout the antage Oil & G cial statements nsolidated finan eporting Standa ul judgments of annual report i Gas Ltd. (the “C together with ncial statemen ards as issued b f Management, is consistent wi Corporation”) i all operational ts have been by the Internat where approp ith that provide is responsible f l and other fin prepared by tional Account priate. Operatio ed in the consol for the preparat nancial informat Management ting Standards B onal and other lidated financia tion and presen tion contained in accordance Board and utili financial inform al statements. ntation in the e with ize the mation Manageme transaction Corporatio financial in nt has develope ns are accurate on’s operating nformation pres ed and maintain ely and reliably and financial r sented is accura ns a system of i y recorded, th results within ate, and that the internal control hat the consoli acceptable lim e Corporation’s ls designed to p idated financia mits of material assets are prop provide reasona al statements a ality, that all o perly safeguarde able assurance t accurately repo ther operation ed. that all ort the nal and The Audit Manageme meeting re financial re the consoli Board of D Committee, co nt fulfills its fin gularly with M eporting proces idated financial Directors. The B omprised of non nancial reportin Management, th ses, auditing m l statements wi Board of Direct n-management ng and internal e external audi atters and vario ith Managemen tors has approv directors, acts control respon itors, and the i ous aspects of f nt and the exte ved these conso on behalf of th nsibilities. The internal audito financial report ernal auditors, olidated financia he Board of Di Audit Commit rs to discuss in ting. The Audit and recommen al statements. rectors to ensu ttee is responsib nternal control t Committee rev nded approval ure that ble for ls over viewed to the Pricewaterh external au 2011, Dece shareholder their audits access to th houseCoopers uditor of the C ember 31, 2010 rs’ equity and c s in accordanc he Audit Comm LLP, an indep Corporation, ha 0 and January 1 cash flows for t e with Canadia mittee. pendent firm o s audited the c 1, 2010, the con the years ended an generally ac of Chartered Ac consolidated st nsolidated state d December 31 ccepted auditin ccountants, ap tatement of fin ement of comp 1, 2011 and 201 ng standards an pointed by the nancial position prehensive inco 10. The externa nd have unlimi e shareholders n as at Decemb ome (loss), chan al auditors cond ited and unres as the ber 31, nges in ducted stricted Andy J. Ma President a March 23, 2 ah and CEO 2012 Drader Kelly I. D CFO Advantage e Oil & Gas Ltd d. - 40 Managem ment’s Repor rt on Internal l Control ove er Financial R The Manag adequate in Securities E Officer, we the Interna Commissio control ove Because of even those statement p subject to compliance Pricewaterh shareholder Corporatio Pricewaterh gement of Adv nternal control Exchange Act o e have conduct al Control-Inte on (“COSO”). er financial repo f inherent limit e systems deter preparation an the risk that e with the polic houseCoopers rs to audit an on’s internal co houseCoopers L vantage Oil & over financial of 1934, as ame ted an evaluatio egrated Framew Based on our orting was effec ations, internal rmined to be e d presentation. controls may b ies or procedur LLP, the Corp d provide an ontrol over fina LLP has provid Gas Ltd. (the reporting for t ended. Under th on of the effect work issued by assessment, w “Corporation” the Corporation he supervision o tiveness of our y the Committe we have conclu ctive. l control over f effective can p . Further, proj become inadeq res may deterio poration’s inde independent o ancial reporting ded such opinio financial report provide only re ections of any quate because rate. ependent firm o opinion on bot g as at Decemb on. Reporting ”) is responsib n as such term of our Chief Ex r internal contro ee of Sponsori uded that as o ble for establish m is defined in R xecutive Office ol over financia ing Organizatio f December 3 hing and maint Rule 13a-15(f) er and Chief Fin al reporting ba ons of the Tre 1, 2011, our in taining of the nancial sed on eadway nternal ting may not p easonable assu y evaluation of of changes in prevent or dete urance with res effectiveness t n conditions, o ct misstatemen spect to the fin to future perio or that the deg nts and nancial ods are gree of of Chartered A th the consolid ber 31, 2011, a Accountants, w dated financial as stated in th was appointed l statements an eir Auditor’s R by the nd the Report. Andy J. Ma President a March 23, 2 ah and CEO 2012 Drader Kelly I. D CFO Advantage e Oil & Gas Ltd d. - 41 Independent Auditor’s Report To the Shareholders of Advantage Oil & Gas Ltd. We have completed an integrated audit of Advantage Oil & Gas Ltd.’s 2011 consolidated financial statements and its internal control over financial reporting as at December 31, 2011 and an audit of its 2010 consolidated financial statements. Our opinions, based on our audits, are presented below. Report on the consolidated financial statements We have audited the accompanying consolidated financial statements of Advantage Oil & Gas Ltd., which comprise the consolidated statement of financial position as at December 31, 2011, December 31, 2010 and January 1, 2010 and the consolidated statements of comprehensive income (loss), changes in shareholders’ equity, and cash flows for the years ended December 31, 2011 and 2010, and the related notes, which comprise a summary of significant accounting policies and other explanatory information. Management’s responsibility for the consolidated financial statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. Auditor’s responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. Canadian generally accepted auditing standards require that we comply with ethical requirements. An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting principles and policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Advantage Oil & Gas Ltd. - 42 We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion on the consolidated financial statements. Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Advantage Oil & Gas Ltd. as at December 31, 2011, December 31, 2010, and January 1, 2010 and its financial performance and its cash flows for the years ended December 31, 2011 and 2010 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. Report on internal control over financial reporting We have also audited Advantage Oil & Gas Ltd.’s internal control over financial reporting as at December 31, 2011 based on criteria established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management’s responsibility for internal control over financial reporting Management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Auditor’s responsibility Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control, based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our audit opinion on the company’s internal control over financial reporting. Definition of internal control over financial reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Advantage Oil & Gas Ltd. - 43 Inherent Because o misstatem that contr with the p t limitation of its inherent ments. Also, p rols may beco policies or pro s t limitations, i rojections of ome inadequa ocedures may internal contr any evaluatio ate because of y deteriorate. rol over finan on of effective f changes in co ncial reporting eness to future onditions or t g may not pre e periods are that the degre ct event or detec e risk subject to the nce ee of complian Opinion In our opi over finan Integrated inion, Advant ncial reporting d Framework tage Oil & Gas g as at Decem k issued by CO s Ltd. mainta mber 31, 2011 OSO. ined, in all m based on crite material respec eria establish cts, effective i hed in Interna internal contr al Control - rol Chartere Calgary, March 23 ed Accounta Alberta , 2012 ants Advantage e Oil & Gas Ltd d. - 44 Co onsolidated St atement of Fin nancial Positio on (th housands of Cana dian dollars) AS SSETS Cu urrent assets Tra ade and other rece eivables Pre epaid expenses an nd deposits De erivative asset To otal current assets No s on-current assets De erivative asset Ex xploration and eva aluation assets Pro operty, plant and equipment De eferred income tax x asset To otal non-current as ssets To otal assets LI ABILITIES Cu urrent liabilities Tra ade and other accr rued liabilities Ca apital lease obligati ions Co onvertible debentu ures De erivative liability Ot ther liability To otal current liabiliti ies No on-current liabil ities De erivative liability Ca apital lease obligati ions Ba ank indebtedness Co onvertible debentu ures De ecommissioning li iability De eferred income tax x liability Ot ther liability To otal non-current lia abilities To otal liabilities SH HAREHOLDER RS' EQUITY Sh are capital Co onvertible debentu ures equity compo onent Co s ontributed surplus De eficit To otal shareholders' e equity attributable e to Advantage sh hareholders No on-controlling int erest To otal shareholders' e equity Notes 7 6 6 8 9 22 12 6 14 6 11 12 13 22 14 15 12 5 To otal liabilities and s shareholders' equi ity Co ommitments (no te 24) See On e accompanying N behalf of the Boar Notes to the Conso rd of Directors of A olidated Financial Advantage Oil & G Gas Ltd.: Statements December 3 31, 2011 Decem mber 31, 2010 January 1, 2010 J note 25) (n (note 25) $ 42,344 $ 42,276 $ 6,045 - 48,389 - 7,730 1,8 877,287 39,383 1,9 924,400 $ 1,9 972,789 6,488 25,157 73,921 - 8,262 54,531 9,936 30,829 95,296 323 6,923 1,883,762 1,824,699 - - 1,892,024 1,831,945 $ 1,965,945 $ 1,927,241 $ 138,119 1 $ 112,457 $ 113,062 - - 2,738 908 141,765 1 - - 232,684 2 75,890 253,796 2 29,723 - 592,093 5 759 62,013 2,367 - 177,596 177 - 288,852 72,811 172,130 40,231 1,835 576,036 1,375 69,927 12,755 - 197,119 1,165 759 247,784 131,561 169,665 22,115 3,431 576,480 733,858 7 753,632 773,599 2,2 214,784 8,348 71,762 (1,1 163,081) 1, ,131,813 107,118 1 1,2 238,931 $ 1,9 972,789 2,199,491 2,190,409 8,348 14,783 (1,010,309) 1,212,313 - 1,212,313 $ 1,965,945 $ 8,348 6,114 (1,051,229) 1,153,642 - 1,153,642 1,927,241 ___ Pau _______________ ul G. Haggis, Direc ___ tor ______ Andy J. ____________ Mah, Director Advantage e Oil & Gas Ltd d. - 45 Consolidated Statement of Comprehensive Income (Loss) (thousands of Canadian dollars, except for per share amounts) Notes Petroleum and natural gas sales Less: royalties Petroleum and natural gas revenue Operating expense General and administrative expense Depreciation expense Impairment of oil and gas properties Exploration and evaluation expense Finance expense Gains on derivatives Other income Income (loss) before taxes and non-controlling interest Income tax recovery (expense) Net income (loss) and comprehensive income (loss) before non-controlling interest Net income attributable to non-controlling interest Net income (loss) and comprehensive income (loss) attributable to Advantage shareholders Net income (loss) per share attributable to Advantage shareholders Basic Diluted 18 19 9 9 8 21 6 20 22 17 See accompanying Notes to the Consolidated Financial Statements Year ended December 31, 2011 Year ended December 31, 2010 (note 25) $ 355,288 (52,971) 302,317 $ 319,368 (45,954) 273,414 (89,166) (34,587) (152,927) (187,684) (3,055) (29,561) 475 1,972 (192,216) 46,807 (145,409) (7,363) (95,609) (38,193) (124,592) (17,500) (752) (34,388) 50,514 46,142 59,036 (18,116) 40,920 - $ (152,772) $ 40,920 $ $ (0.92) (0.92) $ $ 0.25 0.25 Advantage Oil & Gas Ltd. - 46 Consolidated Statement of Changes in Shareholders' Equity Convertible debentures equity component $ 8,348 Contributed surplus $ 14,783 Deficit (1,010,309) $ Notes Share capital $ 2,199,491 Total shareholders' equity attributable to Advantage shareholders $ 1,212,313 Non- controlling interest $ - Total shareholders' equity $ 1,212,313 15, 16 5 - 15,293 - - - - - - - (770) (152,772) - (152,772) 14,523 7,363 - (145,409) 14,523 57,749 - - - 57,749 106,093 163,842 - 577 577 - 2,214,784 $ - 8,348 $ - 71,762 $ - (1,163,081) $ - 1,131,813 $ (6,915) 107,118 $ (6,915) 1,238,931 $ (thousands of Canadian dollars) Balance, January 1, 2011 Net income (loss) and comprehensive income (loss) Share based compensation Common control transaction and change in ownership interest Change in ownership interest, share based compensation Dividends declared by Longview ($0.40 per Longview share) Balance, December 31, 2011 Balance, January 1, 2010 Share based compensation Net income and comprehensive income Balance, December 31, 2010 25 15, 16 $ 2,190,409 9,082 - 2,199,491 $ 8,348 - - 8,348 6,114 8,669 - 14,783 (1,051,229) - 40,920 (1,010,309) 1,153,642 17,751 40,920 1,212,313 $ - - - $ - $ $ 1,153,642 17,751 40,920 1,212,313 $ $ $ $ $ $ $ $ See accompanying Notes to the Consolidated Financial Statements Advantage Oil & Gas Ltd. - 47 Consolidated Statement of Cash Flows (thousands of Canadian dollars) Notes Operating Activities Income (loss) before taxes and non-controlling interest Add (deduct) items not requiring cash: Share based compensation Depreciation expense Impairment of oil and gas properties Exploration and evaluation expense Non-cash general and administrative Unrealized loss (gain) on derivatives Gain on sale of property, plant and equipment Finance expense Expenditures on decommissioning liability Changes in non-cash working capital Cash provided by operating activities Financing Activities Proceeds from Longview financing Increase (decrease) in bank indebtedness Convertible debenture maturities Dividends paid by Longview Reduction of capital lease obligations Convertible debenture issue costs Interest paid Cash provided by (used in) financing activities Investing Activities Expenditures on property, plant and equipment Expenditures on exploration and evaluation assets Property dispositions Cash used in investing activities Net change in cash Cash, beginning of year Cash, end of year 16 9 9 8 6 20 21 13 23 5 11 12 9 8 See accompanying Notes to the Consolidated Financial Statements Year ended December 31, 2011 Year ended December 31, 2010 (note 25) $ (192,216) $ 59,036 12,348 152,927 187,684 3,055 - 25,351 (1,325) 29,561 (3,335) 4,131 218,181 160,757 (56,754) (62,294) (6,050) (68) - (20,076) 15,515 13,415 124,592 17,500 752 (538) (5,381) (45,631) 34,388 (6,275) 31,008 222,866 - 40,395 (69,927) - (1,375) (310) (21,532) (52,749) (231,789) (3,006) 1,099 (233,696) - - $ - (237,702) (2,091) 69,676 (170,117) - - $ - Advantage Oil & Gas Ltd. - 48 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2011 and 2010 All tabular amounts are in thousands of Canadian dollars except as otherwise indicated. 1. Business and structure of Advantage Oil & Gas Ltd. Advantage Oil & Gas Ltd. and its subsidiaries (together “Advantage” or the “Corporation”) are a growth oriented intermediate oil and natural gas development and production corporation with properties located in Western Canada. Advantage is domiciled and incorporated in Canada under the Business Corporations Act (Alberta). Advantage’s head office address is 700, 400 – 3rd Avenue SW, Calgary, Alberta, Canada. The Corporation’s primary listing is on the Toronto Stock Exchange and is also traded on the New York Stock Exchange as a Foreign Private Issuer, under the symbol “AAV”. 2. Basis of preparation (a) Statement of compliance The Corporation prepares its financial statements in accordance with Canadian generally accepted accounting principles as defined in the Handbook of the Canadian Institute of Chartered Accountants (“CICA Handbook”). In 2010, the CICA Handbook was revised to incorporate International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board and to require publicly accountable enterprises to apply these standards effective for years beginning on or after January 1, 2011. Accordingly, these consolidated financial statements are Advantage’s first annual audited consolidated financial statements to be prepared and issued under IFRS. The consolidated financial statements are prepared in compliance with IFRS. The comparative figures for 2010 and Advantage’s financial position as at January 1, 2010 have been restated from previous Canadian Generally Accepted Accounting Principles (“Previous GAAP”) to IFRS. The reconciliations to IFRS from Previous GAAP are summarized in note 25 and disclose the impact of the transition to IFRS on the Corporation's reported financial position and financial performance, including the nature and effect of significant changes in accounting policies from those used in the Corporation’s consolidated financial statements for the year ended December 31, 2010. Subject to certain transition elections disclosed in note 25, the Corporation has consistently applied the same accounting policies in its opening IFRS statement of financial position at January 1, 2010 and throughout all periods presented, as if these policies had always been in effect. The accounting policies applied in these financial statements are based on IFRS issued and outstanding as of March 23, 2012, the date the Board of Directors approved the statements. (b) Basis of measurement The consolidated financial statements have been prepared on the historical cost basis, except as detailed in the Corporation’s accounting policies in note 3. The methods used to measure fair values of derivative instruments are discussed in note 6. (c) Functional and presentation currency These consolidated financial statements are presented in Canadian dollars, which is the Corporation’s functional currency. (d) Basis of consolidation These consolidated financial statements include the accounts of the Corporation and all subsidiaries over which it has control, including Longview Oil Corp. (“Longview”), a public Canadian corporation of which Advantage owns 63%, and remaining ownership is disclosed as non-controlling interest. All inter-corporate balances, income and expenses resulting from inter-corporate transactions are eliminated. Advantage Oil & Gas Ltd. - 49 3. Significant accounting policies The accounting policies set out below have been applied consistently to all years presented in these financial statements, and have been applied consistently by the Corporation. (a) Cash and cash equivalents Cash consists of balances held with banks, and other short-term highly liquid investments with original maturities of three months or less from inception. (b) Basis of consolidation (i) Subsidiaries Subsidiaries are entities controlled by the Corporation. Control exists when the Corporation has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases. (ii) Non-controlling interests The Corporation treats transactions with non-controlling interests as transactions with equity owners of the Corporation. For purchases of shares from non-controlling interests, the difference between any consideration paid and the relevant ownership acquired of the carrying value of net assets of the subsidiary is recorded in equity. Gains or losses on disposals of shares to non-controlling interests are also recorded in equity, unless the disposal results in the Corporation’s loss of control of the subsidiary, in which case the gain or loss is recognized in net income and comprehensive income. (iii) Joint interests A significant portion of the Corporation’s oil and natural gas activities involve jointly controlled assets. The consolidated financial statements include the Corporation’s share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs. (c) Financial instruments All financial instruments are initially recognized at fair value on the Statement of Financial Position. Measurement of financial instruments subsequent to the initial recognition, as well as resulting gains and losses, is based on how each financial instrument was initially classified. The Corporation has classified each identified financial instrument into the following categories: fair value through profit or loss, loans and receivables, held to maturity investments, available for sale financial assets, and financial liabilities at amortized cost. Fair value through profit or loss financial instruments are measured at fair value with gains and losses recognized in income immediately. Available for sale financial assets are measured at fair value with gains and losses, other than impairment losses, recognized in other comprehensive income and transferred to income when the asset is derecognized. Loans and receivables, held to maturity investments and financial liabilities at amortized cost, are recognized at amortized cost using the effective interest method and impairment losses are recorded in income when incurred. Derivative instruments executed by the Corporation to manage market risk associated with volatile commodity prices are classified as fair value through profit or loss and recorded on the Statement of Financial Position at fair value as derivative assets and liabilities. Gains and losses on these instruments are recorded as gains and losses on derivatives in the Statement of Comprehensive Income (Loss) in the period they occur. Gains and losses on derivative instruments are comprised of cash receipts and payments associated with periodic settlement that occurs over the life of the instrument, and non-cash gains and losses associated with changes in the fair values of the instruments, which are remeasured at each reporting date and recorded on the Statement of Financial Position. Advantage Oil & Gas Ltd. - 50 3. Significant accounting policies (continued) (c) Financial instruments (continued) Transaction costs are frequently attributed to the acquisition or issue of a financial asset or liability. Such costs incurred on fair value through profit or loss financial instruments are expensed immediately. For other financial instruments, transaction costs are added to the fair value initially recognized for financial assets and liabilities that are not classified as fair value through profit or loss. Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related, a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is not measured at fair value through profit or loss. Changes in the fair value of separable embedded derivatives are recognized immediately in income. Equity instruments issued by the Corporation are recorded at the proceeds received, with direct issue costs as a deduction therefrom, net of any associated tax benefit. (d) Property, plant and equipment and exploration and evaluation assets (i) Recognition and measurement a) Exploration and evaluation costs Pre-license costs are recognized in the Statement of Comprehensive Income (Loss) as incurred. All exploratory costs incurred subsequent to acquiring the right to explore for oil and natural gas and before technical feasibility and commercial viability of the area have been established are capitalized. Such costs can typically include costs to acquire land rights, geological and geophysical costs, decommissioning costs, and exploration well costs. Exploration and evaluation costs are not depreciated and are accumulated in cost centers by well, field or exploration area and carried forward pending determination of technical feasibility and commercial viability. The technical feasibility and commercial viability of extracting a mineral resource from exploration and evaluation assets is considered to be generally determinable when proved and probable reserves are determined to exist. Upon determination of proved and probable reserves, exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to development and production assets, net of any impairment loss. Management reviews and assesses exploration and evaluation assets to determine if technical feasibility and commercial viability exist. If Management decides not to continue the exploration and evaluation activity, the unrecoverable costs are charged to exploration and evaluation expense in the period in which the determination occurs. b) Development and production costs Items of property, plant and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depreciation and accumulated impairment losses. Costs include lease acquisition, drilling and completion, production facilities, decommissioning costs, geological and geophysical costs and directly attributable general and administrative costs related to development and production activities, net of any government incentive programs. When significant parts of an item of property, plant and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (major components). Advantage Oil & Gas Ltd. - 51 3. Significant accounting policies (continued) (d) Property, plant and equipment and exploration and evaluation assets (continued) (ii) Subsequent costs Costs incurred subsequent to development and production that are significant are recognized as oil and gas property only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in comprehensive income as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or area basis. The carrying amount of any replaced or sold component is derecognized in accordance with our policies. The costs of the day-to-day servicing of property, plant and equipment are recognized in the Statement of Comprehensive Income (Loss) as incurred. (iii) Depreciation The net carrying value of oil and gas properties is depreciated using the unit-of-production method by reference to the ratio of production in the period to the related proved and probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually. (e) Asset swaps and dispositions Exchanges of development and production assets are measured at fair value unless the exchange transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable. The cost of the acquired asset is measured at the fair value of the asset given up, unless the fair value of the asset received is more clearly evident. Where fair value is not used, the cost of the acquired asset is measured at the carrying amount of the amount given up. Any gain or loss on derecognition of the asset given up is recognised in the Statement of Comprehensive Income (Loss). For exchanges or parts of exchanges that involve only exploration and evaluation assets, the exchange is accounted for at carrying value. Gains and losses on disposal of an item of property, plant and equipment, including oil and natural gas interests, are determined by comparing the proceeds from disposition with the carrying amount of property, plant and equipment and are recognized net within “other income” or “other expenses” in the Statement of Comprehensive Income (Loss). (f) Impairment (i) Financial assets At each reporting date, the Corporation assesses whether there is objective evidence that a financial asset is impaired. If a financial asset carried at amortized cost is impaired, the amount of the loss is measured as the difference between the amortized cost of the loan or receivable and the present value of the estimated future cash flows, discounted using the instrument’s original effective interest rate. The loss is recognized in other expenses in the period incurred. Advantage Oil & Gas Ltd. - 52 3. Significant accounting policies (continued) (f) Impairment (continued) (ii) Property, plant and equipment and exploration and evaluation assets The carrying amounts of the Corporation’s property, plant and equipment are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. For the purpose of impairment testing of property, plant and equipment, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the “cash-generating unit” or “CGU”). Exploration and evaluation assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability, and facts and circumstances suggest that the carrying amount exceeds the recoverable amount. Exploration and evaluation assets are allocated to CGU’s or groups of CGU’s for the purposes of assessing such assets for impairment. The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves. Fair value less cost to sell is assessed utilizing market valuation based on an arm’s length transaction between active participants. In the absence of any such transactions, fair value less cost to sell is estimated by discounting the expected after-tax cash flows of the cash generating unit at an after-tax discount rate that reflects the risk of the properties in the cash generating unit. The discounted cash flow calculation is then increased by a tax-shield calculation, which is an estimate of the amount that a prospective buyer of the cash generating unit would be entitled. The carrying value of the cash generating unit is reduced by the deferred tax liability associated with its property, plant and equipment. Impairment losses on property, plant and equipment are recognized in the Statement of Comprehensive Income (Loss) as impairment of oil and gas properties and are separately disclosed. An impairment of exploration and evaluation assets is recognized as exploration and evaluation expense in the Statement of Comprehensive Income (Loss). Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation, if no impairment loss had been recognized. (g) Decommissioning liability A decommissioning liability is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Decommissioning liabilities are determined by discounting the expected future cash flows at a risk-free rate. Advantage Oil & Gas Ltd. - 53 3. Significant accounting policies (continued) (h) Share based compensation Advantage accounts for share based compensation expense based on the fair value of rights granted under its share based compensation plan. Advantage’s Restricted Share Performance Incentive Plan (“RSPIP” or the “Plan”), authorizes the Board of Directors to grant restricted shares to service providers, including directors, officers, employees, and consultants of Advantage and Longview. The restricted share grants generally vest one-third immediately on grant date, with the remaining two- thirds vesting on each of the two subsequent anniversary dates. Compensation cost related to the Plan is recognized as share based compensation expense within general and administrative expense over the service period of the service providers and incorporates the fair value at grant date, the estimated number of restricted shares to vest, and certain management estimates. As compensation expense is recognized, contributed surplus is recorded until the restricted shares vest at which time the appropriate shares are then issued to the services providers and the contributed surplus is transferred to share capital. (i) Common-control transaction Business combinations involving entities under common control are outside the scope of IFRS 3 Business Combinations. IFRS provides no guidance on the accounting for these types of transactions and an entity is required to develop an accounting policy. The two most common methods utilized are the purchase method and the predecessor values method. A business combination involving entities under common control is a business combination in which all of the combining entities are ultimately controlled by the same party, both before and after the business combination, and control is not transitory. Management has determined the predecessor values method to be most appropriate. The predecessor method requires the financial statements to be prepared using the predecessor carrying values without any step up to fair value. The difference between any consideration and the aggregate carrying value of the assets and liabilities are recorded in shareholders’ equity. (j) Revenue Revenue from the sale of petroleum and natural gas is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer which is usually when legal title passes to the external party. For natural gas, this is generally at the time product enters the pipeline. For crude oil, this is generally at the time the product reaches a trucking terminal. For natural gas liquids, this is generally at the time the product reaches a gas plant. Revenue is measured net of discounts, customs duties and royalties. Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements. (k) Finance expense Finance expense comprises interest expense on bank indebtedness, capital leases, and accretion of the discount on the decommissioning liability and convertible debentures. Advantage Oil & Gas Ltd. - 54 3. Significant accounting policies (continued) (l) Income tax Income tax expense comprises current and deferred income tax. Income tax expense is recognized in income or loss except to the extent that it relates to items recognized directly in shareholders’ equity. Current income tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to income tax payable in respect of previous years. Deferred income tax is recognized using the liability method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred income tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination, and at the time of the transaction, affects neither accounting income nor taxable income. Deferred income tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. A deferred income tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred income tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized. Deferred income tax assets and liabilities are only offset when they are within the same legal entity and same tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current. (m) Net income (loss) per share Basic net income (loss) per share is calculated by dividing the net income (loss) attributable to common shareholders of the Corporation by the weighted average number of common shares outstanding during the period. Diluted net income (loss) per share is determined by adjusting the net income (loss) attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as restricted shares granted to service providers and convertible debentures, using the treasury stock method. Advantage Oil & Gas Ltd. - 55 3. Significant accounting policies (continued) (n) New standards and interpretations not yet adopted Standards issued but not yet effective up to the date of issuance of the Corporation’s financial statements are listed below. This listing is of standards and interpretations issued which the Corporation reasonably expects to be applicable at a future date. The Corporation intends to adopt those standards when they become effective. The Corporation has yet to assess the full impact of these standards. IFRS 9 Financial Instruments: Classification and Measurement IFRS 9 is intended to supersede IAS 39, Financial Instruments: Recognition and Measurement and will be published in three phases, of which the first phase has been published. The first phase addresses the accounting for financial assets and financial liabilities. The second phase will address the impairment of financial instruments, and the third phase will address hedge accounting. For financial assets, IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, and replaces the multiple rules in IAS 39. The approach in IFRS 9 is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The new standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39. For financial liabilities, although the classification criteria for financial liabilities will not change under IFRS 9, the approach to the fair value option for financial liabilities may require different accounting for changes to the fair value of a financial liability as a result of changes to an entity’s own credit risk. This standard is not applicable until January 1, 2015. IFRS 10 Consolidated Financial Statements IFRS 10 is a new standard that will replace SIC 12, “Consolidation – Special Purpose Entities” and IAS 27 “Consolidated and Separate Financial Statements”. The new standard eliminates the current risks and rewards approach and establishes control as the single basis for determining the consolidation of an entity. This standard is not applicable until January 1, 2013. IFRS 11 Joint Arrangements IFRS 11 requires a venture to classify its interest in a joint arrangement as a joint venture or joint operation. Joint ventures will be accounted for using the equity method of accounting whereas for a joint operation, the venture will recognize its share of the assets, liabilities, revenue and expenses. Under existing IFRS, entities have the choice to proportionately consolidate or equity account for interests in joint ventures. IFRS 11 supersedes IAS 31, Interests in Joint Ventures and SIC-13, Jointly Controlled Entities, Non-Monetary Contributions by Venturers. This standard is not applicable until January 1, 2013. IFRS 12 Disclosure of Interests in Other Entities IFRS 12 provides the required disclosures for interests in subsidiaries and joint arrangements. These disclosures will require information that will assist users of financial statements to evaluate the nature, risks and financial effects associated with an entity’s interests in subsidiaries and joint arrangements. This standard is not applicable until January 1, 2013. IFRS 13 – Fair Value Measurement IFRS 13 is a comprehensive standard for fair value measurement and disclosure requirements for use across all IFRS standards. The new standard clarifies that fair value is the price that would be received to sell an asset, or paid to transfer a liability in an orderly transaction between market participants, at the measurement date. It also establishes disclosures about fair value measurement. Under existing IFRS, guidance on measuring and disclosing fair value is dispersed among the specific standards requiring fair value measurement and in many cases does not reflect a clear measurement basis or consistent disclosures. This standard is not applicable until January 1, 2013. IAS 28 – Investments in Associates and Joint Ventures IAS 28 has been amended to include joint ventures in its scope and to address the changes in IFRS 10 to 13. Advantage Oil & Gas Ltd. - 56 4. Significant accounting judgments, estimates and assumptions The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates, and differences could be material. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected. Estimates and assumptions Information about significant areas of estimation uncertainty in applying accounting policies that have the most significant effect on the amounts recognized in the consolidated financial statements is included in the following notes:  Note 6 – valuation of financial instruments;  Note 9 – valuation of property, plant and equipment;  Note 8 & 9 – impairment of property, plant and equipment and exploration and evaluation assets;  Note 6, 12 – valuation of convertible debentures;  Note 13 – measurement of decommissioning liability;  Note 16 – measurement of share based compensation; and  Note 22 – measurement of deferred income tax. Judgments In the process of applying the Corporation’s accounting policies, management has made the following judgments, apart from those involving estimates, which may have the most significant effect on the amounts recognized in the consolidated financial statements. (a) Exploration and evaluation assets Costs incurred to acquire rights to explore for oil and natural gas may be grouped into either exploration and evaluation or development and production, depending on facts and circumstances. Costs incurred in respect of properties that have been determined to have proved and probable reserves, are classified as development and production properties. In such circumstances, technical feasibility and commercial viability are considered to be established. Costs incurred in respect of new prospects with no nearby established development past or present and no proved or probable reserves assigned are classified as exploration and evaluation assets (note 8). (b) Reserves base The oil and gas development and production properties are depreciated on a unit-of-production (“UOP”) basis at a rate calculated by reference to proved and probable reserves determined in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” and incorporating the estimated future cost of developing and extracting those reserves. Proved plus probable reserves are determined using estimates of oil and natural gas in place, recovery factors and future oil and natural gas prices. Future development costs are estimated using assumptions as to number of wells required to produce the reserves, the cost of such wells and associated production facilities and other capital costs. Advantage Oil & Gas Ltd. - 57 4. Significant accounting judgments, estimates and assumptions (continued) (c) Depreciation of oil and gas assets Oil and gas properties are depreciated using the UOP method over proved plus probable reserves. The calculation of the UOP rate of depreciation could be impacted to the extent that actual production in the future is different from current forecast production based on proved plus probable reserves (note 9). (d) Determination of cash generating units Oil and gas properties are grouped into cash generating units for purposes of impairment testing. Management has evaluated the oil and gas properties of the Corporation, and grouped the properties into cash generating units on the basis of their ability to generate independent cash flows, similar reserve characteristics, geographical location, and shared infrastructure. (e) Impairment indicators and calculation of impairment At each reporting date, Advantage assesses whether or not there are circumstances that indicate a possibility that the carrying values of exploration and evaluation assets and property, plant and equipment are not recoverable, or impaired. Such circumstances include incidents of physical damage, deterioration of commodity prices, changes in the regulatory environment, or a reduction in estimates of proved and probable reserves. When management judges that circumstances indicate potential impairment, property, plant and equipment are tested for impairment by comparing the carrying values to their recoverable amounts. The recoverable amounts of cash generating units are determined based on the higher of value-in-use calculations and fair values less costs to sell. These calculations require the use of estimates and assumptions, that are subject to change as new information becomes available including information on future commodity prices, expected production volumes, quantities of reserves, discount rates, future development costs and operating costs (note 8 & 9). (f) Decommissioning liability Decommissioning costs will be incurred by the Corporation at the end of the operating life of some of the Corporation’s facilities and properties. The ultimate decommissioning liability is uncertain and can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques, experience at other production sites, or changes in the risk-free discount rate. The expected timing and amount of expenditure can also change in response to changes in reserves or changes in laws and regulations or their interpretation. As a result, there could be significant adjustments to the provisions established which would affect future financial results. (g) Income taxes The Corporation recognizes deferred income tax assets to the extent that it is probable that taxable profit will be available to allow the benefit of that deferred income tax asset to be utilized. Assessing the recoverability of deferred income tax assets requires the Corporation to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Corporation to realize the deferred income tax assets recorded at the reporting date could be impacted. Additionally, future changes in tax laws in the jurisdictions in which the Corporation operates could limit the ability of the Corporation to obtain tax deductions in future periods. (h) Contingencies By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events. Advantage Oil & Gas Ltd. - 58 5. Common-Control Transaction Advantage sold certain oil-weighted assets to Longview for total consideration of $546.9 million, comprised of 29,450,000 common shares of Longview representing a 63% equity ownership and $252.4 million in cash. The assets were sold with an effective date of January 1, 2011 and a closing date of April 14, 2011. As Advantage is the parent company and has a majority ownership interest of Longview, this transaction was deemed a common-control transaction. As such, Advantage has recognized a non-controlling interest in shareholders’ equity, representing the carrying value of the 37% shareholding of Longview held by outside interests. The difference of $57.7 million between the proceeds from the change in ownership interest and the carrying value of the non-controlling interest has been recognized within contributed surplus of shareholders’ equity. At December 31, 2011, Advantage held 63% of Longview’s issued and outstanding shares. 6. Financial risk management Financial instruments of the Corporation include trade and other receivables, deposits, trade and other accrued liabilities, bank indebtedness, convertible debentures, other liabilities and derivative assets and liabilities. Trade and other receivables and deposits are classified as loans and receivables and measured at amortized cost. Trade and other accrued liabilities, bank indebtedness and other liabilities are all classified as financial liabilities at amortized cost. As at December 31, 2011, there were no significant differences between the carrying amounts reported on the Statement of Financial Position and the estimated fair values of these financial instruments due to the short terms to maturity and the floating interest rate on the bank indebtedness. The Corporation has convertible debenture obligations outstanding, of which the liability component has been classified as financial liabilities at amortized cost. The convertible debentures have different fixed terms and interest rates (note 12) resulting in fair values that will vary over time as market conditions change. As at December 31, 2011, the estimated fair value of the total outstanding convertible debenture obligation was $82.8 million (December 31, 2010 - $153.2 million). The fair value of the liability component of convertible debentures was determined based on the current public trading activity of such debentures. Fair value is determined following a three level hierarchy: Level 1: Quoted prices in active markets for identical assets and liabilities. The Corporation does not have any financial assets or liabilities that require level 1 inputs. Level 2: Inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly. Such inputs can be corroborated with other observable inputs for substantially the complete term of the contract. Advantage uses Level 2 inputs in the determination of the fair value of derivative assets and liabilities. Pricing inputs include quoted forward prices for commodities, foreign exchange rates, volatility and risk-free rate discounting, all of which can be observed or corroborated in the marketplace. The actual gains and losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions. Level 3: Under this level, fair value is determined using inputs that are not observable. Advantage has no assets or liabilities that use level 3 inputs. The Corporation’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities such as:     credit risk; liquidity risk; price and currency risk; and interest rate risk. Advantage Oil & Gas Ltd. - 59 6. Financial risk management (continued) (a) Credit risk Credit risk is the risk of financial loss to the Corporation if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Corporation’s receivables from joint venture partners and oil and natural gas marketers. The maximum exposure to credit risk is as follows: Trade and other receivables Deposits Derivative asset $ December 31, 2011 42,344 3,157 - 45,501 $ $ December 31, 2010 42,276 2,936 25,157 70,369 $ $ January 1, 2010 54,531 6,108 31,152 91,791 $ Trade and other receivables, deposits, and derivative assets are subject to credit risk exposure and the carrying values reflect Management’s assessment of the associated maximum exposure to such credit risk. Advantage mitigates such credit risk by closely monitoring significant counterparties and dealing with a broad selection of partners that diversify risk within the sector. The Corporation’s deposits are primarily due from the Alberta Provincial government and are viewed by Management as having minimal associated credit risk. To the extent that Advantage enters derivatives to manage commodity price risk, it may be subject to credit risk associated with counterparties with which it contracts. Credit risk is mitigated by entering into contracts with only stable, creditworthy parties and through frequent reviews of exposures to individual entities. In addition, the Corporation only enters into derivative contracts with major banks and international energy firms to further mitigate associated credit risk. Substantially all of the Corporation’s trade and other receivables are due from customers and joint operation partners concentrated in the Canadian oil and gas industry. As such, trade and other receivables are subject to normal industry credit risks. As at December 31, 2011, $0.5 million or 1.2% of trade and other receivables are outstanding for 90 days or more (December 31, 2010 - $2.3 million or 5.4% of trade and other receivables). The Corporation believes the entire balance is collectible, and in some instances has the ability to mitigate risk through withholding production or offsetting payables with the same parties. Management has not provided an allowance for doubtful accounts at December 31, 2011 (December 31, 2010 - $0.2 million). The Corporation’s most significant customer, a Canadian oil and natural gas marketer, accounts for $12.3 million of the trade and other receivables at December 31, 2011 (December 31, 2010 - $12.1 million). Advantage Oil & Gas Ltd. - 60 6. Financial risk management (continued) (b) Liquidity risk The Corporation is subject to liquidity risk attributed from trade and other accrued liabilities, bank indebtedness, convertible debentures, other liabilities, and derivative liabilities. Trade and other accrued liabilities, other liabilities, and derivative liabilities are primarily due within one year of the statement of financial position date and Advantage does not anticipate any problems in satisfying the obligations from cash provided by operating activities and the existing credit facilities. The Corporation’s bank indebtedness is subject to $475 million credit facility agreements. Although the credit facilities are a source of liquidity risk, the facilities also mitigates liquidity risk by enabling Advantage to manage interim cash flow fluctuations. The terms of the credit facilities are such that they provide Advantage adequate flexibility to evaluate and assess liquidity issues if and when they arise. Additionally, the Corporation regularly monitors liquidity related to obligations by evaluating forecasted cash flows, optimal debt levels, capital spending activity, working capital requirements, and other potential cash expenditures. This continual financial assessment process further enables the Corporation to mitigate liquidity risk. Advantage has convertible debentures outstanding that mature in 2015 (note 12). Interest payments are made semi- annually with excess cash provided by operating activities. As the debentures become due, the Corporation can satisfy the obligations in cash or issue shares at a price determined in the applicable debenture agreements. This settlement alternative allows the Corporation to adequately manage liquidity, plan available cash resources and implement an optimal capital structure. To the extent that Advantage enters derivatives to manage commodity price risk, it may be subject to liquidity risk as derivative liabilities become due. While the Corporation has elected not to follow hedge accounting, derivative instruments are not entered for speculative purposes and Management closely monitors existing commodity risk exposures. As such, liquidity risk is mitigated since any losses actually realized are subsidized by increased cash flows realized from the higher commodity price environment. The timing of cash outflows relating to financial liabilities as at December 31, 2011 and 2010 are as follows: December 31, 2011 Trade and other accrued liabilities Derivative liability Bank indebtedness - principal - interest - principal - interest Convertible debentures Other liability $ Less than one year 138,119 2,738 - 12,373 - 4,313 908 158,451 $ One to three years - $ - 233,903 5,882 - 8,625 - 248,410 $ Three to five years Thereafter - - $ $ - - - - - - - 86,250 - 2,156 - - $ - 88,406 $ $ Total 138,119 2,738 233,903 18,255 86,250 15,094 908 495,267 $ Interest on bank indebtedness was calculated assuming conversion of the revolving credit facility to a one-year term facility. December 31, 2010 Trade and other accrued liabilities Capital lease obligations Derivative liability Bank indebtedness - principal - interest - principal - interest Convertible debentures Other liability $ Less than one year 112,457 779 2,367 - 13,717 62,294 9,179 - 200,793 $ One to three years - $ - 177 290,657 6,577 - 8,625 1,966 308,002 $ Four to five years - $ - - - - 86,250 6,469 - 92,719 $ Thereafter - $ - - - - - - - $ - $ Total 112,457 779 2,544 290,657 20,294 148,544 24,273 1,966 601,514 $ Interest on bank indebtedness was calculated assuming conversion of the revolving credit facility to a one-year term facility. Advantage Oil & Gas Ltd. - 61 6. Financial risk management (continued) (b) Liquidity risk (continued) The Corporation’s bank indebtedness does not have specific maturity dates. It is governed by credit facility agreements with a syndicate of financial institutions (note 11). Under the terms of the agreements, the facilities are reviewed annually, with the next reviews scheduled in April and June 2012. The facilities are revolving and are extendible at each annual review for a further 364 day period at the option of the syndicate. If not extended, the credit facilities are converted at that time into one year term facilities, with the principal payable at the end of such one year terms. Management fully expects that the facilities will be extended at each annual review. (c) Price and currency risk Advantage’s derivative assets and liabilities are subject to both price and currency risks as their fair values are based on assumptions including forward commodity prices and foreign exchange rates. The Corporation enters into non- financial derivatives to manage commodity price risk exposure relative to actual commodity production and does not utilize derivative instruments for speculative purposes. Changes in the price assumptions can have a significant effect on the fair value of the derivative assets and liabilities and thereby impact earnings. It is estimated that a 10% change in the forward crude oil prices used to calculate the fair value of the crude oil derivatives at December 31, 2011 would result in a $3.0 million change in net loss for the year ended December 31, 2011. As at December 31, 2011, the Corporation had the following derivatives in place: Description of Derivative Term Volume Average Price Crude oil - WTI Fixed price Collar Electricity – Alberta Pool Price Fixed price January 2012 to December 2012 January 2012 to December 2012 Cdn $97.10/bbl 1,000 bbls/d 1,000 bbls/d Bought put Cdn $90.00/bbl Sold call Cdn $102.25/bbl January 2012 to December 2012 0.9 MW Cdn $77.88/MWh As at December 31, 2010 the Corporation had the following derivatives in place: Description of Derivative Term Volume Average Price Natural gas - AECO Fixed price Fixed price Fixed price Fixed price Crude oil – WTI Fixed price Fixed price April 2010 to January 2011 January 2011 to December 2011 18,956 mcf/d 9,478 mcf/d January 2011 to December 2011 January 2011 to December 2011 9,478 mcf/d 9,478 mcf/d Cdn$7.25/mcf Cdn$6.24/mcf Cdn$6.24/mcf Cdn$6.26/mcf April 2010 to January 2011 January 2011 to December 2011 2,000 bbls/d 1,500 bbls/d Cdn$69.50/bbl Cdn $91.05/bbl Advantage Oil & Gas Ltd. - 62 6. Financial risk management (continued) (c) Price and currency risk (continued) As at December 31, 2011, the fair value of the derivatives outstanding resulted in an asset of $Nil (December 31, 2010 – $25.2 million) and a liability of $2.7 million (December 31, 2010 – $2.5 million). For the year ended December 31, 2011, $0.5 million was recognized in net loss as a derivative gain (December 31, 2010 - $50.5 million derivative gain). The table below summarizes the realized and unrealized gains (losses) on derivatives. Realized gains on derivatives Unrealized gains (losses) on derivatives Year ended December 31, 2011 $ 25,826 (25,351) 475 $ Year ended December 31, 2010 $ 45,133 5,381 50,514 $ The fair value of the commodity risk management derivatives have been allocated to current and non-current assets and liabilities on the basis of expected timing of cash settlement and the applicable counterparties. (d) Interest rate risk Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The interest charged on the outstanding bank indebtedness fluctuates with the interest rates posted by the lenders. The Corporation is exposed to interest rate risk and has not entered into any mitigating interest rate hedges or swaps. Had the borrowing rate been different by 100 basis points throughout the year ended December 31, 2011, net income (loss) and comprehensive income (loss) would have changed by $2.2 million (December 31, 2010 - $1.9 million) based on the average debt balance outstanding during the year. Advantage Oil & Gas Ltd. - 63 6. Financial risk management (continued) (e) Capital management The Corporation manages its capital with the following objectives:  To ensure sufficient financial flexibility to achieve the ongoing business objectives including replacement of production, funding of future growth opportunities, and pursuit of accretive acquisitions; and  To maximize shareholder return through enhancing the share value. Advantage monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the business and industry in general. The capital structure of the Corporation is composed of working capital (excluding derivative assets and liabilities), bank indebtedness, convertible debentures, and share capital. Advantage may manage its capital structure by issuing new shares, repurchasing outstanding shares, obtaining additional financing either through bank indebtedness or convertible debenture issuances, refinancing current debt, issuing other financial or equity-based instruments, declaring a dividend, implementing a dividend reinvestment plan, adjusting capital spending, or disposing of assets or its ownership interest in Longview. The capital structure is reviewed by Management and the Board of Directors on an ongoing basis. Advantage’s capital structure as at December 31, 2011, December 31, 2010 and January 1, 2010 is as follows: ($000, except as otherwise indicated) Bank indebtedness (non-current) (note 11) Working capital deficit (1) Net debt Shares outstanding (note 15) Share closing market price ($/share) Market capitalization (2) Convertible debentures maturity value (current and non-current) Capital lease obligations (non-current) Total capitalization December 31, 2011 $ $ 233,903 90,638 324,541 166,304,040 4.24 705,129 December 31, 2010 $ $ 290,657 64,452 355,109 164,092,009 6.76 1,109,262 January 1, 2010 $ $ 250,262 49,970 300,232 162,745,528 6.90 1,122,944 86,250 - 1,115,920 $ 148,544 - 1,612,915 $ 218,471 759 1,642,406 $ (1) Working capital deficit is a non-GAAP measure that includes trade and other receivables, prepaid expenses and deposits, trade and other accrued liabilities, the current portion of capital lease obligations, and current portion of other liability. (2) Market capitalization is a non-GAAP measure calculated by multiplying shares outstanding by the closing market share price on the applicable date. The Corporation’s bank indebtedness is governed by credit facility agreements for $475 million (note 11) that contains standard commercial covenants for facilities of this nature. The only financial covenant is a requirement for Advantage to maintain a minimum cash flow to interest expense ratio of 3.5:1, determined on a rolling four quarter basis. The Corporation is in compliance with all credit facility covenants. As well, the borrowing base for the Corporation’s credit facilities is determined through utilizing Advantage’s regular reserve estimates. The banking syndicate thoroughly evaluates the reserve estimates based upon their own commodity price expectations to determine the amount of the borrowing base. Revision or changes in the reserve estimates and commodity prices can have either a positive or a negative impact on the borrowing base of the Corporation. Management of the Corporation’s capital structure is facilitated through its financial and operational forecasting processes. The forecast of the Corporation’s future cash flows is based on estimates of production, commodity prices, forecast capital and operating expenditures, and other investing and financing activities. The forecast is regularly updated based on new commodity prices and other changes, which the Corporation views as critical in the current environment. Selected forecast information is frequently provided to the Board of Directors. The Corporation’s capital management objectives, policies and processes have remained unchanged during the years ended December 31, 2011 and 2010. Advantage Oil & Gas Ltd. - 64 7. Trade and other receivables Trade receivables Receivables from joint venture partners Other December 31, 2011 32,655 $ 9,038 651 42,344 $ December 31, 2010 30,997 $ 6,296 4,983 42,276 $ 8. Exploration and evaluation assets Balance at January 1, 2010 Additions Exploration and evaluation expense Balance at December 31, 2010 Additions Transferred to property, plant and equipment (note 9) Exploration and evaluation expense Balance at December 31, 2011 $ January 1, 2010 31,608 13,719 9,204 54,531 $ $ $ $ 6,923 2,091 (752) 8,262 3,006 (483) (3,055) 7,730 There were no indicators of impairment of exploration and evaluation assets during the years ended December 31, 2011 and 2010. Advantage Oil & Gas Ltd. - 65 9. Property, plant and equipment Cost Balance at January 1, 2010 Additions Change in decommissioning liability (note 13) Disposals Balance at December 31, 2010 Additions Change in decommissioning liability (note 13) Disposals Transferred from exploration and evaluation assets (note 8) Balance at December 31, 2011 Accumulated depreciation and impairment losses Balance at January 1, 2010 Depreciation Impairment of oil and gas properties Disposals Balance at December 31, 2010 Depreciation Impairment of oil and gas properties Disposals Balance at December 31, 2011 Oil & gas properties Furniture and equipment Total $ $ $ $ $ $ 1,821,078 221,280 37,073 (60,482) 2,018,949 253,731 79,660 (184) 483 2,352,639 3,621 403 - - 4,024 443 - - - 4,467 1,824,699 221,683 37,073 (60,482) 2,022,973 254,174 79,660 (184) 483 2,357,106 $ $ $ Oil & gas properties - $ 123,360 17,500 (2,881) 137,979 152,279 187,684 (3) 477,939 $ $ Furniture and equipment - $ 1,232 - - 1,232 648 - - 1,880 $ $ Total $ - 124,592 17,500 (2,881) 139,211 152,927 187,684 (3) 479,819 $ $ Net book value At January 1, 2010 At December 31, 2010 At December 31, 2011 Oil & gas properties $ $ $ 1,821,078 1,880,970 1,874,700 Furniture and equipment $ $ $ 3,621 2,792 2,587 Total $ $ $ 1,824,699 1,883,762 1,877,287 During the year ended December 31, 2011, Advantage capitalized general and administrative expenditures directly related to development activities of $7.6 million (December 31, 2010 - $8.9 million). Advantage included future development costs of $1.7 billion (December 31, 2010 – $1.6 billion) in property, plant and equipment costs subject to depreciation. Advantage Oil & Gas Ltd. - 66 9. Property, plant and equipment (continued) For the year ended December 31, 2011, Advantage recognized an impairment of oil and gas properties of $187.7 million (December 31, 2010 - $17.5 million). Impairment of oil and gas properties occur when management determines that indicators of impairment are present in specific cash generating units. Recorded impairments are the amount by which carrying amounts of the cash generating units exceed their respective recoverable amount based on a fair value less costs to sell determination. Fair value less costs to sell is based on discounted after-tax future net cash flows of proved and probable reserves using forecast prices and costs, discounted at 10%. Forecast natural gas prices used in the calculation of impairment of oil and gas properties for the year ended December 31, 2011 are as follows: Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 (1) AECO ($Cdn/MMBtu) 3.16 3.78 4.13 5.53 5.65 5.77 5.89 6.01 6.14 6.27 (1) Escalation of 1.5% thereafter The impairment of oil and gas properties recognized in the year ended December 31, 2011 relates to natural gas producing assets in West and East Alberta. The decline in the price of natural gas was considered to be an indicator of impairment. The impairment of oil and gas properties recognized in the year ended December 31, 2010 related to a West Alberta oil cash generating unit, that was subject to negative reserve revisions at year end. Advantage Oil & Gas Ltd. - 67 10. Related party transactions Transactions between Advantage and Longview Advantage sold certain oil-weighted properties to Longview on April 14, 2011 (note 5). Concurrent with the disposition, Advantage entered into a Technical Services Agreement (“TSA”) with Longview. Under the TSA, Advantage provides the necessary personnel and technical services to manage Longview’s business and Longview reimburses Advantage on a monthly basis for its share of administrative charges based on respective levels of production. All amounts paid are recorded as general and administrative expenses and measured at the exchange amount, which is the amount agreed upon by the transacting parties. At December 31, 2011, amounts due from Longview totaled $1.7 million (December 31, 2010 - $Nil). Advantage charged Longview $3.8 million during the year ended December 31, 2011 under the TSA. Dividends declared and paid or payable from Longview to Advantage during the year ended December 31, 2011 totaled $11.8 million (December 31, 2010 - $Nil). All amounts due to and from Longview are non-interest bearing in nature, are settled monthly and were incurred within the normal course of business. All inter-corporate balances, income and expenses resulting from inter-corporate transactions are eliminated. Key management compensation The compensation paid or payable to key management, including directors, is as follows: Salaries, director fees and short-term benefits Other long-term benefits Share based compensation (1) December 31, 2011 $ 4,821 - 5,067 9,888 $ December 31, 2010 $ 4,786 - 8,242 13,028 $ (1) Represents the grant date fair value of Restricted Shares granted under the RSPIP for the respective years. Advantage Oil & Gas Ltd. - 68 11. Bank indebtedness Revolving credit facility Discount on Bankers Acceptances and other fees Balance, end of year December 31, 2011 233,903 $ (1,219) 232,684 $ December 31, 2010 290,657 $ (1,805) 288,852 $ January 1, 2010 250,262 $ (2,478) 247,784 $ The Corporation has credit facilities (the "Credit Facilities") of $475 million, comprised of $275 million held by Advantage and $200 million held by Longview. The Credit Facilities are comprised of $40 million extendible revolving operating loan facilities from one financial institution and $435 million of extendible revolving loan facilities from a syndicate of financial institutions. Amounts borrowed under the Credit Facilities bear interest at a floating rate based on the applicable Canadian prime rate, US base rate, LIBOR rate or bankers' acceptance rate plus between 1.00% and 3.50% depending on the type of borrowing and the Corporations’ debt to cash flow ratio. The Credit Facilities are each collateralized by a $1 billion floating charge demand debenture covering all assets. The amounts available to the Corporation from time to time under the Credit Facilities are based upon the borrowing base determined semi-annually by the lenders. The revolving period for the Credit Facilities will end in April and June 2012 unless extended at the option of the syndicate for a further 364 day period. If the Credit Facilities are not extended, they will convert to non-revolving term facilities due 365 days after the last day of the revolving period. The Credit Facilities prohibit the Corporation from entering into any derivative contract where the term of such contract exceeds three years. Further, the aggregate of such contracts cannot hedge greater than 60% of total estimated petroleum and natural gas production over two years and 50% over the third year, in each respective legal entity. The Credit Facilities contain standard commercial covenants for credit facilities of this nature. The only financial covenant is a requirement for each entity to maintain a minimum cash flow to interest expense ratio of 3.5:1, determined on a rolling four- quarter basis. These covenants were met at December 31, 2011, December 31, 2010, and January 1, 2010. Breach of any covenant will result in an event of default in which case the Corporation has 20 days to remedy such default. If the default is not remedied or waived, and if required by the lenders, the administrative agent of the lenders has the option to declare all obligations under the credit facilities to be immediately due and payable without further demand, presentation, protest, days of grace, or notice of any kind. Interest payments under the debentures are subordinated to the repayment of any amounts owing under the Credit Facilities and are not permitted if the Corporation is in default of such Credit Facilities or if the amount of outstanding indebtedness under such facilities exceeds the then existing current borrowing base. For the year ended December 31, 2011, the average effective interest rate on the outstanding amounts under the facility was approximately 5.3% (December 31, 2010 – 5.0%). Advantage also has issued letters of credit totaling $8.8 million at December 31, 2011 (December 31, 2010 – $2.9 million). Advantage Oil & Gas Ltd. - 69 12. Convertible debentures The convertible unsecured subordinated debentures pay interest semi-annually and are convertible at the option of the holder into shares of Advantage at the applicable conversion price per share plus accrued and unpaid interest. The details of the convertible debentures including fair market values initially assigned and issuance costs are as follows: 6.50% 7.75% 8.00% 5.00% Trading symbol Issue date Maturity date Conversion price Liability component Equity component Gross proceeds Issuance costs Net proceeds AAV.DBE May 18, 2005 June 30, 2010 Dec. 1, 2011 Dec. 31, 2011 20.33 $ AAV.DBD AAV.DBH AAV.DBG Sep. 15, 2004 Nov. 13, 2006 Dec. 31, 2009 Jan. 30, 2015 8.60 $ $ $ 21.00 24.96 $ 69,952 - $ 50,000 - $ 41,445 - $ 73,019 13,231 69,952 - 50,000 (2,190) 41,445 - 86,250 (3,735) $ 69,952 $ 47,810 $ 41,445 $ 82,515 The convertible debentures are redeemable prior to their maturity dates, at the option of the Corporation, upon providing appropriate advance notification as per the debenture indentures. The redemption prices for the various debentures, plus accrued and unpaid interest, is dependent on the redemption periods and are as follows: Convertible Debenture Redemption Periods 7.75% 8.00% 5.00% After December 1, 2009 and before December 1, 2011 After December 31, 2010 and before December 31, 2011 After January 31, 2013 and on or before January 30, 2015 Provided that Current Market Price exceeds 125% of Conversion Price Redemption Price $ $ $ 1,000 1,025 1,000 Advantage Oil & Gas Ltd. - 70 12. Convertible debentures (continued) The balance of debentures outstanding at December 31, 2011 and changes in the liability and equity components during the years ended December 31, 2011 and 2010 are as follows: Trading symbol Debentures outstanding Liability component: Balance at January 1, 2010 Accretion of discount Matured Balance at December 31, 2010 Accretion of discount Matured Balance at December 31, 2011 Trading symbol Debentures outstanding Liability component: Balance at January 1, 2010 Accretion of discount Matured Balance at December 31, 2010 Accretion of discount Matured Balance at December 31, 2011 Equity component: 6.50% AAV.DBE $ - $ 69,927 - (69,927) - - - $ - 8.00% AAV.DBG $ - $ 15,528 - - 15,528 - (15,528) $ - 7.75% AAV.DBD $ - $ 46,176 309 - 46,485 281 (46,766) $ - 5.00% AAV.DBH 86,250 $ Total $ 86,250 $ $ 69,857 2,954 - 72,811 3,079 - 75,890 201,488 3,263 (69,927) 134,824 3,360 (62,294) 75,890 $ $ Balance at January 1, 2010 Balance at December 31, 2010 Balance at December 31, 2011 $ - $ - $ - $ $ $ 8,348 8,348 8,348 $ $ $ 8,348 8,348 8,348 The principal amount of 7.75% convertible debentures matured on December 1, 2011, and was settled with $46.8 million in cash. The principal amount of 8.00% convertible debentures matured on December 31, 2011, and was settled with $15.5 million in cash. The principal amount of 6.50% convertible debentures matured on June 30, 2010 and was settled with $69.9 million in cash. There were no conversions of convertible debentures during the years ended December 31, 2011 and 2010. Advantage Oil & Gas Ltd. - 71 13. Decommissioning liability The Corporation’s decommissioning liability results from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities, all of which will require future costs of decommissioning under environmental legislation. These costs are expected to be incurred between 2012 and 2071. A risk-free rate of 2.50% (December 31, 2010 – 3.54%) and an inflation factor of 2% were used to calculate the fair value of the decommissioning liability. A reconciliation of the decommissioning liability is provided below: Year ended December 31, 2011 Year ended December 31, 2010 $ $ The Corporation has a non-cancellable lease for office space which, due to changes in its activities, the Corporation ceased to use in September 2009, while the lease expires in 2012. Management considers this to be an onerous contract, therefore the obligation for the discounted future payments, net of expected rental income, has been provided for as a liability. Balance, beginning of year Accretion expense Liabilities incurred Change in estimates Effect of change in risk-free rate Property dispositions Liabilities settled Balance, end of year 14. Other liability A reconcilation of the other liability is as follows: Balance, beginning of year Accretion expense (note 21) Reduction of liability by subleasing space Liability settled Balance, end of year 15. Share capital (a) Authorized 172,130 5,748 4,714 (3,699) 78,645 (407) (3,335) 253,796 1,835 99 - (1,026) 908 $ $ Year ended December 31, 2011 Year ended December 31, 2010 $ $ $ $ 169,665 6,094 3,331 6,601 27,141 (34,427) (6,275) 172,130 3,431 199 (538) (1,257) 1,835 The Corporation is authorized to issue an unlimited number of shares without nominal or par value. (b) Issued Balance at January 1, 2010 Share based compensation (note 16) Balance at December 31, 2010 Share based compensation (note 16) Balance at December 31, 2011 Number of Shares Amount $ $ $ 2,190,409 9,082 2,199,491 15,293 2,214,784 162,745,528 1,346,481 164,092,009 2,212,031 166,304,040 Advantage Oil & Gas Ltd. - 72 16. Share based compensation Advantage has a Restricted Share Performance Incentive Plan (“RSPIP” or the “Plan”) as approved by the shareholders. The Plan authorizes the Board of Directors to grant restricted shares to service providers, including directors, officers, employees, and consultants of Advantage. The number of restricted shares granted is based on the Corporation’s share price return for a twelve-month period and compared to the performance of a peer group approved by the Board of Directors. The share price return is calculated at the end of each and every quarter and is primarily based on the twelve-month change in the share price. If the share price return for a twelve-month period is positive, a restricted share grant will be calculated based on the return. Otherwise, no restricted shares will be granted to service providers for the period. If the share price return for a twelve-month period is negative, but the return is still within the top two-thirds of the approved peer group performance, the Board of Directors may grant a discretionary restricted share award. The restricted share grants generally vest one-third immediately on grant date, with the remaining two-thirds vesting on each of the two subsequent anniversary dates. On vesting, common shares are issued to the service providers in exchange for the restricted shares outstanding. The holders of restricted shares may elect to receive cash upon vesting in lieu of the number of shares to be issued, subject to consent of the Corporation. However, it is the intent to settle unvested amounts with shares. The following table is a continuity of restricted shares: Restricted Shares Balance at January 1, 2010 Granted Vested Forfeited Balance at December 31, 2010 Granted Vested Forfeited Balance at December 31, 2011 The following table summarizes information about restricted shares outstanding at December 31, 2011: Date Granted September 2, 2009 January 12, 2010 April 12, 2010 July 12, 2010 January 12, 2011 April 11, 2011 July 12, 2011 Total Number of Restricted Shares 344,353 247,439 314,232 257,010 43,955 539,263 371,458 2,117,710 2,226,904 2,547,020 (1,818,707) (29,349) 2,925,868 1,443,956 (2,212,031) (40,083) 2,117,710 Weighted Average Fair Value at Grant Date $5.80 $7.27 $6.97 $6.53 $6.95 $8.28 $7.15 During the year ended December 31, 2011, the Corporation recognized share based compensation of $15.1 million (December 31, 2010 - $19.9 million), of which $2.8 million (December 31, 2010 - $3.9 million) was capitalized to property, plant and equipment, and $12.3 million (December 31, 2010 - $16.0 million) was recorded as an expense in the Statement of Income (Loss) and Comprehensive Income (Loss). Advantage Oil & Gas Ltd. - 73 17. Net income (loss) per share attributable to Advantage shareholders The calculations of basic and diluted net income (loss) per share are derived from both net income (loss) attributable to Advantage common shareholders and weighted average shares outstanding, calculated as follows: Year ended December 31, 2011 Year ended December 31, 2010 Net income (loss) attributable to Advantage shareholders Basic Restricted shares (note 16) Convertible debentures Diluted Weighted average shares outstanding Basic Restricted shares (note 16) Convertible debentures Diluted $ $ (152,772) - - (152,772) 40,920 - - 40,920 $ $ 165,370,777 - - 165,370,777 163,467,225 1,094,135 - 164,561,360 The calculation of diluted net income (loss) per share for the years ended December 31, 2011 and 2010 excludes convertible debentures, as their impact would be anti-dilutive. Total weighted average shares issuable in exchange for the series of convertible debentures excluded from the diluted net income (loss) per share calculation for the year ended December 31, 2011 was 12,828,588 (year ended December 31, 2010 – 14,401,412 shares). As at December 31, 2011, the total convertible debentures outstanding were immediately convertible to 10,029,070 shares (December 31, 2010 – 13,019,819 shares). Restricted shares have been excluded from the calculation of diluted net loss per share for the year ended December 31, 2011, as the impact would have been anti-dilutive. Total weighted average shares issuable in exchange for the restricted shares and excluded from the diluted net loss per share calculation for the year ended December 31, 2011 was 1,192,566 shares. Advantage Oil & Gas Ltd. - 74 18. Petroleum and natural gas sales Crude oil and natural gas liquid sales Natural gas sales Total petroleum and natural gas sales 19. General and administrative expense (“G&A”) Salaries and benefits Share based compensation (notes 15,16) Office rent Other Total G&A Capitalized (note 9) Net G&A 20. Other income Gain on sale of property, plant and equipment Miscellaneous income Total other income 21. Finance expense Interest on bank indebtedness Interest on convertible debentures Accretion on convertible debentures (note 12) Accretion of decomissioning liability (note 13) Accretion of other liability (note 14) Total finance expense Year ended December 31, 2011 186,014 $ 169,274 355,288 $ Year ended December 31, 2010 172,796 $ 146,572 319,368 $ Year ended December 31, 2011 20,778 $ 15,100 2,337 3,955 42,170 (7,583) 34,587 $ Year ended December 31, 2010 20,334 $ 19,851 2,192 4,755 47,132 (8,939) 38,193 $ Year ended December 31, 2011 $ 1,325 647 1,972 $ Year ended December 31, 2010 $ 45,631 511 46,142 $ Year ended December 31, 2011 $ 11,483 8,871 3,360 5,748 99 29,561 $ Year ended December 31, 2010 $ 13,346 11,486 3,263 6,094 199 34,388 $ Advantage Oil & Gas Ltd. - 75 22. Income taxes The provision for income taxes is as follows: Current income tax expense Deferred income tax expense (recovery) Income tax expense (recovery) Year ended December 31, 2011 - $ (46,807) (46,807) $ Year ended December 31, 2010 - $ 18,116 18,116 $ The provision for income taxes varies from the amount that would be computed by applying the combined federal and provincial income tax rates for the following reasons: Income (loss) before taxes and non-controlling interest Combined federal and provincial income tax rates Expected income tax expense (recovery) Increase (decrease) in income taxes resulting from: Non-deductible share based compensation Difference between current and expected tax rates Effective tax rate Year ended December 31, 2011 $ (192,216) 26.57% (51,072) $ Year ended December 31, 2010 59,036 28.17% 16,630 $ 4,031 234 (46,807) 24.35% $ 5,162 (3,676) 18,116 30.69% The Canadian combined statutory tax rates decreased from 28.17% in 2010 to 26.57% in 2011 as a result of legislation enacted in 2007. Advantage Oil & Gas Ltd. - 76 22. Income taxes (continued) The movement in deferred income tax liabilities and assets without taking into consideration the offsetting of balances within the same tax jurisdiction is as follows: Deferred income tax liability Balance at January 1, 2010 Charged (credited) to income Balance at December 31, 2010 Charged (credited) to income Balance at December 31, 2011 Deferred income tax asset Balance at January 1, 2010 Charged (credited) to income Balance at December 31, 2010 Charged (credited) to income Charged (credited) to equity Balance at December 31, 2011 Net deferred income tax liability (asset) Balance at January 1, 2010 Charged (credited) to income Balance at December 31, 2010 Charged (credited) to income Charged (credited) to equity Balance at December 31, 2011 Property, plant and equipment $ Derivative asset/liability $ 194,515 47,597 242,112 (3,771) 238,341 4,867 1,166 6,033 (6,737) (704) Total $ 199,382 48,763 248,145 (10,508) 237,637 $ $ $ Decommissioning liability $ Non-capital losses $ Other $ Total $ (42,910) (581) (43,491) (20,444) - (63,935) (127,941) (31,417) (159,358) (15,970) (1,091) (176,419) (6,416) 1,351 (5,065) 115 (1,993) (6,943) (177,267) (30,647) (207,914) (36,299) (3,084) (247,297) $ $ $ $ Longview $ Advantage $ Total $ - - - (36,299) (3,084) (39,383) 22,115 18,116 40,231 (10,508) - 29,723 22,115 18,116 40,231 (46,807) (3,084) (9,660) $ $ $ The net deferred income tax asset is expected to reverse within 12 months. The estimated tax pools available at December 31, 2011 are as follows: Longview Advantage Total Canadian development expenses Canadian exploration expenses Canadian oil and gas property expenses Non-capital losses Undepreciated capital cost Other $ $ $ 35,402 - 366,793 72,582 76,362 7,911 559,050 105,300 70,761 - 631,660 271,190 5,951 1,084,862 140,702 70,761 366,793 704,242 347,552 13,862 1,643,912 $ $ $ The non-capital loss carry forward balances above expire no earlier than 2023. Advantage Oil & Gas Ltd. - 77 23. Supplemented cash flow information Changes in non-cash working capital is comprised of: Source (use) of cash: Trade and other receivables Prepaid expenses and deposits Trade and other accrued liabilities Related to operating activities Related to financing activities Related to investing activities Year ended December 31, 2011 Year ended December 30, 2010 $ $ (68) 443 25,662 26,037 4,131 2,274 19,632 26,037 $ $ $ $ $ $ 12,255 3,448 (605) 15,098 31,008 2,408 (18,318) 15,098 24. Commitments Advantage has several lease commitments relating to office buildings and transportation. The estimated remaining annual minimum operating lease payments are as follows, of which $0.9 million is recognized in other liability (note 14): 2011 2012 2013 2014 2015 December 31, 2011 $ - 15,543 14,413 11,812 2,246 44,014 $ December 31, 2010 11,756 $ 11,791 10,576 8,723 2,108 44,954 $ Advantage Oil & Gas Ltd. - 78 25. Transition to IFRS For all periods up to and including the year ended December 31, 2010 the Corporation prepared its financial statements in accordance with previous Canadian generally accepted accounting principles (“Previous GAAP”). These financial statements, for the year ended December 31, 2011, are prepared in accordance with International Financial Reporting Standards (“IFRS”). The Corporation has prepared financial statements which comply with IFRS applicable for periods beginning on or after January 1, 2010 and the significant accounting policies meeting those requirements are described in note 3. The Corporation has prepared its IFRS opening balance sheet as at January 1, 2010, its date of transition to IFRS. IFRS 1 allows first-time adopters certain exemptions from the general requirement to apply IFRS retrospectively. The Corporation has taken the following exemptions:  Companies using full-cost accounting are allowed to measure their oil and gas assets at the amount determined under the Previous GAAP at the date of transition. This amount is pro-rated to the underlying assets based upon the value of proved and probable reserves at transition date, discounted at 10%.  Companies using the full cost book value as deemed cost exemption are allowed to measure the liabilities for decommissioning, restoration and similar liabilities at the date of transition and recognize directly in retained earnings any difference between that amount and the carrying amount determined under Previous GAAP.      IFRS 3 Business Combinations has not been applied to acquisitions of subsidiaries or of interests in associates and joint ventures that occurred before January 1, 2010. IFRS 2 Share-based Payment has not been applied to any equity instruments that were granted on or before November 7, 2002, nor has it been applied to equity instruments granted after November 7, 2002 that vested before January 1, 2010. IAS 17 Leases has been applied as of transition date rather than at the lease’s inception date. IAS 32 Financial Instruments Presentation will not be applied for compound financial instruments where the liability component is no longer outstanding. IAS 23 Borrowing Costs will not be applied before January 1, 2010. Reconciliations to IFRS from Previous GAAP financial statements including the impact of the transitioning on the Corporation’s reported financial position and financial performance, including the nature and effect of significant changes in accounting policies are summarized as follows. Advantage Oil & Gas Ltd. - 79 25. Transition to IFRS (continued) Reconciliation of Consolidated Statement of Financial Position at the date of IFRS transition, January 1, 2010. (thousands of Canadian dollars) ASSETS Current assets Trade and other receivables Prepaid expenses and deposits Derivative asset Total current assets Non-current assets Derivative asset Exploration and evaluation assets Property, plant and equipment Total non-current assets Total assets LIABILITIES Current liabilities Trade and other accrued liabilities Capital lease obligations Convertible debentures Derivative liability Deferred income tax liability Total current liabilities Non-current liabilities Derivative liability Capital lease obligations Bank indebtedness Convertible debentures Decommissioning liability Deferred income tax liability Other liability Total non-current liabilities Total liabilities SHAREHOLDERS' EQUITY Share capital Convertible debentures equity component Contributed surplus Deficit Total shareholders' equity Total liabilities and shareholders' equity Notes Previous GAAP Effect of Transition to IFRS IFRS Reclassifications IFRS $ 54,531 9,936 30,829 95,296 - $ - - - - $ - - - $ 54,531 9,936 30,829 95,296 323 - 1,831,622 1,831,945 - - - - - 6,923 (6,923) - 323 6,923 1,824,699 1,831,945 $ 1,927,241 $ - $ - $ 1,927,241 $ 111,901 1,375 69,553 12,755 4,704 200,288 $ - - 374 - - 374 $ 1,161 - - - (4,704) (3,543) $ 113,062 1,375 69,927 12,755 - 197,119 1,165 759 247,784 130,658 68,555 38,796 3,431 491,148 - - - 903 101,110 (21,385) - 80,628 691,436 81,002 - - - - - 4,704 - 4,704 1,161 1,165 759 247,784 131,561 169,665 22,115 3,431 576,480 773,599 2,190,409 18,867 7,275 (980,746) 1,235,805 1,927,241 $ - (10,519) - (70,483) (81,002) $ - - - (1,161) - (1,161) $ - 2,190,409 8,348 6,114 (1,051,229) 1,153,642 1,927,241 $ 2 2 6 4 5 4 3 5 4 6 Advantage Oil & Gas Ltd. - 80 25. Transition to IFRS (continued) Reconciliation of Consolidated Statement of Financial Position at the end of the last reporting year under Previous GAAP, December 31, 2010. (thousands of Canadian dollars) ASSETS Current assets Trade and other receivables Prepaid expenses and deposits Derivative asset Total current assets Non-current assets Exploration and evaluation assets Property, plant and equipment Total non-current assets Notes Previous GAAP Effect of Transition to IFRS IFRS Reclassifiications IFRS $ 42,276 6,488 25,157 73,921 - $ - - - - $ - - - $ 42,276 6,488 25,157 73,921 2 1, 2, 3 - 1,768,650 1,768,650 - 123,374 123,374 8,262 (8,262) - 8,262 1,883,762 1,892,024 Total assets $ 1,842,571 $ 123,374 $ - $ 1,965,945 LIABILITIES Current liabilities Trade and other accrued liabilities Capital lease obligations Convertible debentures Derivative liability Deferred income tax liability Total current liabilities Non-current liabilities Derivative liability Bank indebtedness Convertible debentures Decommissioning liability Deferred income tax liability Other liability Total non-current liabilities Total liabilities SHAREHOLDERS' EQUITY Share capital Convertible debentures equity component Contributed surplus Deficit Total shareholders' equity Total liabilities and shareholders' equity 4 5 3 5 4 4 $ 112,457 759 61,570 2,367 5,876 183,029 - $ - 443 - - 443 - $ - - - (5,876) (5,876) $ 112,457 759 62,013 2,367 - 177,596 177 288,852 72,811 58,281 29,399 1,835 451,355 - - - 113,849 4,956 - 118,805 - - - - 5,876 - 5,876 177 288,852 72,811 172,130 40,231 1,835 576,036 634,384 119,248 - 753,632 2,199,491 15,896 17,754 (1,024,954) 1,208,187 1,842,571 $ - (7,548) (2,971) 14,645 4,126 123,374 $ - - - - - $ - 2,199,491 8,348 14,783 (1,010,309) 1,212,313 1,965,945 $ Advantage Oil & Gas Ltd. - 81 25. Transition to IFRS (continued) Reconciliation of Consolidated Statement of Comprehensive Income (Loss) for the year ended December 31, 2010: (thousands of Canadian dollars) Petroleum and natural gas sales Less: royalties Petroleum and natural gas revenue Operating expense General and administrative expense Depreciation expense Impairment of oil and gas properties Exploration and evaluation expense Finance expense Gains on derivatives Other income Income (loss) before taxes Income tax recovery (expense) Net income (loss) and comprehensive income (loss) Net income (loss) per share Notes Previous GAAP Effect of Transition to IFRS IFRS Reclassifications IFRS 8 $ 319,368 (44,640) 274,728 - $ - - $ - (1,314) (1,314) $ 319,368 (45,954) 273,414 1c 1c 1, 7 1d 2 3, 4, 7 1a 5, 8 (93,875) (37,578) (215,780) - - (29,128) 50,514 - (51,119) 6,911 (1,734) (615) 86,695 (17,500) (752) (767) - 46,142 111,469 (26,341) - - 4,493 - - (4,493) - - (1,314) 1,314 (95,609) (38,193) (124,592) (17,500) (752) (34,388) 50,514 46,142 59,036 (18,116) $ (44,208) $ 85,128 $ - $ 40,920 Basic Diluted $ $ (0.27) (0.27) $ $ 0.25 0.25 1. Property, Plant and Equipment a. Gain on sale of property, plant and equipment Under Previous GAAP, the Corporation did not recognize gains or losses on the disposal of oil and gas properties unless such dispositions would change the depletion rate by 20% or more while IFRS does require such recognition. This results in an increase to the carrying value and a gain on sale of property, plant and equipment included in other income. b. Depreciation expense Under Previous GAAP, depletion and depreciation was calculated on a unit-of-production basis for oil and gas properties using proved reserves, on a cost center basis that was defined as a country. Under IFRS, depreciation is calculated based on proved and probable reserves over individual components resulting in a decrease in depreciation expense and increase in the carrying value of property, plant and equipment. c. Capitalization During the transition to IFRS, revisions and refinements were made to capitalization. As a result, certain expenditures incurred in 2010 were expensed as operating expense and general and administrative expense. d. Impairment At December 31, 2010 an impairment loss was recognized associated with a cash generating unit located in West Central Alberta that was subject to negative reserve revisions at year end. The cash generating unit was written down to fair value less costs to sell, determined on a discounted cash flow model, using a discount rate of 10%. Advantage Oil & Gas Ltd. - 82 25. Transition to IFRS (continued) 2. Exploration and evaluation assets Under Previous GAAP, exploration and evaluation assets were included in the full cost pool of property, plant and equipment. Under IFRS, these assets must be reclassified from developed oil and natural gas property, plant and equipment and presented separately. When exploration and evaluation assets are determined to be technically feasible and commercially viable, the costs are moved to developed oil and natural gas property, plant and equipment. Assets that are not technically feasible and commercially viable are expensed. 3. Decommissioning liability Under Previous GAAP asset retirement obligations were discounted at a credit-adjusted risk-fee rate. Under IFRS the discount rate has been reduced to a risk-free rate of 4.00% on January 1, 2010. Accordingly, the decommissioning liability has increased by $101.1 million at transition date, and due to the exemption allowed by IFRS 1, the offsetting charge has been recognized in deficit. As a result, under IFRS both the accretion expense associated with the decommissioning liability will be different and changes in the estimate of the decommissioning liability will impact property, plant and equipment. 4. Convertible debentures liability component Prior to July 9, 2009, Advantage was an Income Trust that operated under the name Advantage Energy Income Fund. As an income trust, convertible debentures were convertible into Trust Units, which contained a redemption feature which effectively made the conversion option a “putable instrument” under IAS 32. As such, convertible debentures were liabilities, with no equity component. Upon conversion to a corporation on July 9, 2009, all convertible debentures became convertible into common shares, and were no longer deemed to contain a “putable instrument”. Retrospective restatement of the convertible debentures in existence at July 9, 2009 and still outstanding at transition date resulted in the liability component restated to their full maturity values, less any issue costs and no value assigned to the equity component of the conversion features of these same debentures. Accretion expense as recorded under Previous GAAP was reduced, as only debenture issue costs gave rise to accretion expense for these convertible debentures. 5. Deferred income tax liability: a. Deferred income tax calculated according to IFRS is substantially similar to Previous GAAP and arises from differences between the accounting and tax bases of our assets and liabilities. To the extent that assets and liabilities have changed from transition to IFRS, the amount of deferred income tax liability would be impacted. b. Under Previous GAAP, deferred income tax liabilities were required to be disclosed as either current or long-term. Under IFRS, all deferred income tax liabilities are considered to be non-current liabilities. 6. Contributed surplus At January 1, 2010, a portion of unvested RSPIP compensation costs included in contributed surplus effectively represented cash payments. Under IFRS, this portion was considered a liability and accordingly reclassified to trade and other accrued liabilities. 7. Finance expense Under Previous GAAP, accretion of decommissioning liability was included in the amount presented as depreciation of property, plant and equipment on the Statement of Income and Comprehensive Income. Under IFRS, accretion of decommissioning liability has been reclassified and is included in finance expense. 8. Royalties Under Previous GAAP, current taxes included Saskatchewan resource surcharge. Under IFRS, Saskatchewan resource surcharge has been deemed a royalty and deducted from petroleum and natural gas revenues. 9. Adjustments to the Consolidated Statement of Cash Flows The transition from Previous GAAP to IFRS had no significant impact on cash flows generated by the Corporation. Cash flows related to interest are classified as financing while under Previous GAAP, cash flows relating to interest were classified as operating. Advantage Oil & Gas Ltd. - 83 Directors Stephen E. Balog (1)(2) Kelly I. Drader Paul G. Haggis(1) John A. Howard (2)(3) Andy J. Mah Ronald A. McIntosh (1)(2) Sheila H. O’Brien (2)(3) Carol D. Pennycook (1)(3) Steven Sharpe (1) Member of Audit Committee (2) Member of Reserve Evaluation Committee (3) Member of Human Resources, Compensation & Corporate Governance Committee Officers Andy J. Mah, President and CEO Kelly I. Drader, CFO Patrick J. Cairns, Senior Vice President Craig Blackwood, Vice President, Finance Weldon M. Kary, Vice President, Geosciences and Land Neil Bokenfohr, Vice President, Exploitation Corporate Secretary Jay P. Reid, Partner Burnet, Duckworth and Palmer LLP Auditors PricewaterhouseCoopers LLP Bankers The Bank of Nova Scotia National Bank of Canada Royal Bank of Canada Canadian Imperial Bank of Commerce Union Bank, Canada Branch Alberta Treasury Branches HSBC Bank Canada BNP Paribas (Canada) Independent Reserve Evaluators Sproule Associates Limited Legal Counsel Burnet, Duckworth and Palmer LLP Transfer Agent Computershare Trust Company of Canada Abbreviations - barrels bbls - barrels per day bbls/d - barrels of oil equivalent (6 mcf = 1 bbl) boe - barrels of oil equivalent per day boe/d - thousand cubic feet mcf - thousand cubic feet per day mcf/d - million cubic feet mmcf mmcf/d - million cubic feet per day - billion cubic feet bcf - trillion cubic feet tcf - gigajoules gj - natural gas liquids NGLs - West Texas Intermediate WTI Corporate Office 700, 400 – 3 Avenue SW Calgary, Alberta T2P 4H2 (403) 718-8000 Contact Us Toll free: 1-866-393-0393 Email: ir@advantageog.com Visit our website at www.advantageog.com Toronto Stock Exchange Trading Symbols Shares: AAV 5.00% Convertible Debentures: AAV.DBH New York Stock Exchange Trading Symbol Shares: AAV Advantage Oil & Gas Ltd. - 84 

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