ex991.htm

EX-99.1 2 ex991.htm Q3 REPORT ex991.htm

2011 Third Quarter Report

Non-Consolidated Financial and Operating Highlights (1)

	Three months ended						Three months ended
	September 30, 2011						June 30, 2011
Financial ($000, except as otherwise indicated)	$000			per boe			$000			per boe
Petroleum and natural gas sales	$	52,090		$	25.09		$	61,405		$	28.45
Royalties		(5,917	)		(2.85	)		(7,837	)		(3.63	)
Realized gain on derivatives		6,598			3.18			6,200			2.87
Operating expense		(12,239	)		(5.89	)		(14,556	)		(6.74	)
Operating		40,532			19.53			45,212			20.95
General and administrative (2)		(4,164	)		(2.00	)		(4,752	)		(2.20	)
Finance expense (3)		(3,926	)		(1.89	)		(3,963	)		(1.84	)
Miscellaneous income		411			0.20			110			0.05
Funds from operations		32,853		$	15.84			36,607		$	16.96
Dividends from Longview		4,418						2,945
Total	$	37,271					$	39,552
per share (4)	$	0.23					$	0.24

Expenditures on property, plant and equipment	$	40,627					$	6,023
Working capital deficit (5)	$	43,166					$	3,104
Bank indebtedness	$	67,695					$	103,447
Convertible debentures (face value)	$	148,544					$	148,544
Shares outstanding at end of period (000)		165,934						165,145
Basic weighted average shares (000)		165,647						165,076

Operating
Daily Production
Natural gas (mcf/d)		125,250						129,123
Crude oil and NGLs (bbls/d)		1,693						2,198
Total boe/d @ 6:1		22,568						23,719
Average prices (including hedging)
Natural gas ($/mcf)	$	4.17					$	4.30
Crude oil and NGLs ($/bbl)	$	68.10					$	85.14

(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.

MESSAGE TO SHAREHOLDERS

The following Message to Shareholders discusses the non-consolidated financial and operating results for Advantage, excluding Longview.

Third Quarter Production On-Track with Operating Costs Reduced to $5.89/boe

Production for Q3 2011 was on-track and averaged 22,568 boe/d (92% natural gas). Production during Q2 2011 was 23,719 boe/d and included 845 boe/d from assets sold to Longview Oil Corp. (“Longview”) that closed on April 14, 2011. During Q3 2011, production from Glacier was impacted due to planned facility downtime at our gas plant to complete our acid gas injection system and maintenance work conducted by TransCanada pipelines (“TCPL”).

Operating costs for Q3 2011 decreased 13% to $5.89/boe compared to the second quarter of 2011 due to strong operational efficiencies achieved at Glacier. Glacier operating costs, which comprised 65% of total corporate production, averaged $1.80/boe ($0.30/mcf) during Q3 2011. We believe that Advantage is currently one of the lowest operating cost producers among the Canadian intermediate oil and gas sector due to our continued growth at Glacier and divestment of higher cost properties. We anticipate corporate operating costs will decline further as a result of increased production growth from our Glacier Phase IV expansion which is expected to be completed in Q2 2012.

Advantage’s royalty rate during Q3 2011 was 11.4% compared to 12.8% in Q2 2011 and is anticipated to trend lower due to increasing production from our new Glacier Montney wells that are estimated to have a royalty rate of 5% for the life of a well at current commodity prices. Approximately 35% of Advantage’s production is derived from conventional production that generally attracts higher royalty rates as compared to Glacier.

Funds from operations for the three months ended September 30, 2011 were $32.9 million or $0.20 per share. Funds from operations decreased slightly compared to Q2 2011 due to lower average commodity prices but was mostly offset by increased Glacier production, reduced costs and hedging gains of $6.6 million. In addition to the funds from operations, Advantage also received tax-free dividend income of $4.4 million as a result of its 63% ownership in the shares of Longview.

Ø	Capital expenditures for Q3 2011 were $40.7 million primarily related to the commencement of our Glacier Phase IV expansion program.

Bank indebtedness decreased to $67.7 million at September 30, 2011 (compared to $103.4 million at June 30, 2011) resulting in an undrawn credit facility of $207.3 million. Bank indebtedness has decreased 77% 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 debt to annualized cash flow at the end of the third quarter is 0.5 times and 1.7 times including convertible debentures.

A total of $148.5 million of convertible debentures remain outstanding of which $62.3 million will mature in December 2011 and the balance of $86.2 million will mature in January 2015. We currently anticipate settling the debentures that mature in December 2011 with cash from our undrawn credit facilities.

Advantage is in a solid position to fund future growth from our cash flow and our strong balance sheet which includes an undrawn credit facility of $207.3 million and a 63% ownership in the shares of Longview Oil Corp. which has an asset value of $264 million at September 30, 2011. Bank indebtedness will increase during the remainder of our budget cycle as we execute our Phase IV capital expenditure program to expand Glacier’s capacity to 140 mmcf/d.

Phase IV Glacier Development Program Underway with 3 Drilling Rigs Active

Our Phase IV development program at Glacier includes a twelve month (July 2011 to June 2012) capital estimate of $200 million with two key objectives: i) increase throughput capacity at our Glacier gas plant (100% working interest) from 100 mmcf/d to 140 mmcf/d by the second quarter of 2012 and drill a sufficient number of wells to fill our plant; and ii) further evaluate the Middle and Lower Montney formations

Wet weather conditions at Glacier resulted in a staggered start to our capital program and while this has initially delayed our drilling and well completion progress by approximately 1.5 months, we do not anticipate any impact on completion of our Phase IV expansion targeted for the latter part of Q2 2012. Only one drilling rig was able to commence operations in late July with the remaining two drilling rigs delayed until mid-August.

Advantage Oil & Gas Ltd. - 2

Capital expenditures at Glacier during the third quarter of 2011 amounted to $37.1 million and included the drilling of 7 horizontal Montney wells (5 Upper Montney and 2 Middle Montney) and completion of our acid gas injection system. To date, we have drilled a total of 12 wells and our three contracted drilling rigs are currently drilling wells 13 to 15 of our 30 well program. Completion operations have begun and we anticipate providing initial well results this winter.

In October 2011, we successfully commissioned the acid gas injection system which is part of the facility changes required to increase our Glacier gas plant throughput capacity to 140 mmcf/d. Additional plant modifications will be completed during the first half of 2012 to complete the gas plant expansion. TCPL also completed additional looping of their sales gas pipeline lateral at the end of Q3 2011 which will provide the flexibility for growth beyond 140 mmcf/d.

In conjunction with the anticipated production increase at Glacier, Advantage production is forecast to grow 24% to a June 30, 2012 exit rate of approximately 29,000 boe/d at which time Glacier will represent 80% of total production. This target would result in production growth of 138% since we began development at Glacier in 2008 (excluding asset dispositions and Longview).

Commodity Hedging Program

Ø	Advantage’s hedging program includes 28.4 mmcf/d of natural gas for 2011 hedged at an average price of Cdn$6.24 AECO per mcf.

Ø	Additional details on our hedging program are available at our website at www.advantageog.com.

Looking Forward – Solid Operational Results Drives Lower Operating Cost Guidance

Solid operational results and efficiencies at Glacier will result in lower corporate operating costs than previously forecast (see press release dated July 4, 2011 for additional Guidance details). We anticipate operating costs to average $5.90/boe for the H2 2011 and operating costs to be at the low end of guidance of approximately $5.75/boe for H1 2012. These results demonstrate the positive impact that Glacier growth has on reducing our corporate cost structure which improves cash flow margins and drilling economics in this natural gas commodity price environment.

Our capital expenditures are also anticipated to be at the low end of guidance for H2 2011 of approximately $120 million due to delays resulting from the wet weather conditions at Glacier in early Q3 2011. We do not anticipate any concerns with completing our Phase IV development program by the end of Q2 2012 as originally targeted.

Advantage is well positioned to grow production and reserves at Glacier with a strong balance sheet and cash flow to fund our Phase IV capital development program. Results at Glacier have exceeded expectations and we are encouraged with the scalable potential that has been identified in each of the Upper, Middle and Lower Montney layers which are all gas saturated. The low operating cost and attractive royalty structure at Glacier supports economic development at current natural gas prices and our financially disciplined approach positions Advantage to deliver shareholder value.

Advantage Oil & Gas Ltd. - 3

Management’s Discussion & Analysis

The following Management’s Discussion and Analysis (“MD&A”), dated as of November 10, 2011, 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 and nine months ended September 30, 2011 and should be read in conjunction with the unaudited consolidated financial statements for the three and nine months ended September 30, 2011 and the audited consolidated financial statements and MD&A for the year ended December 31, 2010. All per barrel of oil equivalent (“boe”) amounts are stated at a conversion rate of six thousand cubic feet of natural gas being equal to one barrel of oil or liquids, based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation.

Transition to International Financial Reporting Standards

The consolidated financial statements, MD&A and comparative information have been prepared in Canadian dollars unless otherwise indicated and in accordance with International Financial Reporting Standards (“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, 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 24 to the unaudited 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 the Corporation’s exploration and drilling plans; spending and capital budgets; capital expenditure programs; the focus and anticipated timing of capital expenditures; availability of funds for our capital program; effect on production due to completion of facilities and infrastructure expansion work in Glacier, Alberta; expected production from the Glacier development; effect of commodity prices on drilling activity and supply levels; anticipated timing of incremental production; 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; 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 performance characteristics of our properties; effect on income of the Corporation's derivative and hedging activities; the Corporation's hedging strategy; effect of the Corporation's risk management activities; projected royalty rates; average royalty rates; plans to improve operating cost structure and effect on corporate operating costs; 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 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; and credit risk. Many of these 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. - 4

With respect to forward-looking statements contained in this MD&A, Advantage has made assumptions regarding: 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; and the impact of increasing competition.

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.

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. 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									Nine months ended
	September 30									September 30
($000)	2011			2010			% change			2011			2010			% change
Cash provided by operating activities	$	64,025		$	53,681			19	%	$	138,249		$	161,902			(15	)%
Expenditures on decommissioning liability		1,029			2,603			(60	)%		2,574			4,464			(42	)%
Changes in non-cash working capital		(9,841	)		(12,962	)		(24	)%		17,791			(14,540	)		(222	)%
Finance expense (1)		(5,105	)		(5,625	)		(9	)%		(16,217	)		(19,153	)		(15	)%
Funds from operations	$	50,108		$	37,697			33	%	$	142,397		$	132,673			7	%

(1)	Finance expense excludes non-cash accretion expense.

Advantage Oil & Gas Ltd. - 5

Creation of Longview Oil Corp.

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 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 with consideration comprised of 29,450,000 common shares of Longview representing a 63% equity ownership and $251.5 million in cash, subject to final adjustments per the purchase and sale agreement (the “Acquisition”). The Acquired Assets were purchased with an effective date of January 1, 2011 and a closing date of April 14, 2011 with adjustments reflected within the purchase price. 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 September 30, 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.

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.

Advantage Oil & Gas Ltd. - 6

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 September 30, 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.

	Three months ended									Nine months ended
	September 30, 2011									September 30, 2011
	Advantage			Longview			Consolidated			Advantage			Longview (1)			Consolidated
Production
Natural gas (mcf/d)		125,250			9,103			134,353			121,891			9,135			127,580
Crude oil (bbls/d)		664			3,995			4,658			2,121			3,903			4,552
NGLs (bbls/d)		1,029			559			1,588			1,242			553			1,587
Total (boe/d)		22,568			6,071			28,638			23,678			5,979			27,402
Natural gas (%)		92	%		25	%		78	%		86	%		25	%		78	%
Crude oil (%)		3	%		66	%		16	%		9	%		65	%		17	%
NGLs (%)		5	%		9	%		6	%		5	%		10	%		5	%

Natural Gas Prices ($/mcf)
Realized natural gas prices
Excluding hedging	$	3.60		$	3.91		$	3.62		$	3.69		$	4.02		$	3.69
Including hedging	$	4.17		$	3.91		$	4.16		$	4.33		$	4.02		$	4.33

Crude Oil and NGLs Prices ($/bbl)
Realized crude oil prices
Excluding hedging	$	84.01		$	82.03		$	82.31		$	85.11		$	87.03		$	86.13
Including hedging	$	84.01		$	83.23		$	83.34		$	82.10		$	86.45		$	84.42
Realized NGLs prices
Excluding hedging	$	57.85		$	63.07		$	59.69		$	62.07		$	62.51		$	62.16
Realized crude oil and NGLs prices
Excluding hedging	$	68.10		$	79.70		$	76.56		$	76.60		$	83.98		$	79.94
Including hedging	$	68.10		$	80.76		$	77.33		$	74.70		$	83.48		$	78.67

Cash netbacks ($/boe)
Petroleum and natural gas sales	$	25.09		$	65.65		$	33.69		$	29.88		$	68.73		$	35.16
Royalties		(2.85	)		(13.60	)		(5.13	)		(3.90	)		(14.22	)		(5.30	)
Realized gain (loss) on derivatives		3.18			0.79			2.67			3.04			(0.38	)		2.58
Operating expense		(5.89	)		(18.47	)		(8.56	)		(7.62	)		(17.87	)		(9.02	)
Operating	$	19.53		$	34.37		$	22.67		$	21.40		$	36.26		$	23.42
General and administrative expense (2)		(2.00	)		(1.39	)		(1.87	)		(2.34	)		(1.99	)		(2.29	)
Finance expense (3)		(1.89	)		(2.11	)		(1.94	)		(2.17	)		(2.12	)		(2.17	)
Miscellaneous income		0.20			0.02			0.16			0.08			0.01			0.07
Cash netbacks	$	15.84		$	30.89		$	19.02		$	16.97		$	32.16		$	19.03

(1)	The nine months ended September 30, 2011 represents Longview's financial and operating results for the period from April 14 to September 30, 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. - 7

	Three months ended									Nine months ended
	September 30, 2011									September 30, 2011
($000, except as otherwise indicated)	Advantage			Longview			Consolidated			Advantage			Longview (1)			Consolidated
Sales including realized hedging
Natural gas sales	$	41,486		$	3,277		$	44,763		$	122,788		$	6,237		$	129,025
Realized hedging gains		6,598			-			6,598			21,395			-			21,395
Natural gas sales including hedging	$	48,084		$	3,277		$	51,361		$	144,183		$	6,237		$	150,420
Crude oil and NGLs sales	$	10,604		$	33,390		$	43,994		$	70,339		$	63,624		$	133,963
Realized hedging gains (losses)		-			442			442			(1,741	)		(386	)		(2,127	)
Crude oil and NGLs sales including hedging	$	10,604		$	33,832		$	44,436		$	68,598		$	63,238		$	131,836
Total	$	58,688		$	37,109		$	95,797		$	212,781		$	69,475		$	282,256
per boe	$	28.27		$	66.44		$	36.36		$	32.92		$	68.35		$	37.74

Royalties	$	5,917		$	7,598		$	13,515		$	25,180		$	14,452		$	39,632
per boe	$	2.85		$	13.60		$	5.13		$	3.90		$	14.22		$	5.30
As a percentage of petroleum and natural gas sales		11.4	%		20.7	%		15.2	%		13.0	%		20.7	%		15.1	%

Operating expense	$	12,239		$	10,313		$	22,552		$	49,282		$	18,167		$	67,449
per boe	$	5.89		$	18.47		$	8.56		$	7.62		$	17.87		$	9.02

General and administrative expense (2)	$	4,164		$	777		$	4,941		$	15,097		$	2,023		$	17,120
per boe	$	2.00		$	1.39		$	1.87		$	2.34		$	1.99		$	2.29

Interest on bank indebtedness	$	1,612		$	1,179		$	2,791		$	7,184		$	2,157		$	9,341
per boe	$	0.78		$	2.11		$	1.06		$	1.11		$	2.12		$	1.25

Interest on convertible debentures	$	2,314		$	-		$	2,314		$	6,876		$	-		$	6,876
per boe	$	1.11		$	-		$	0.88		$	1.06		$	-		$	0.92

Miscellaneous income	$	411		$	13		$	424		$	546		$	13		$	559
per boe	$	0.20		$	0.02		$	0.16		$	0.08		$	0.01		$	0.07

Funds from operations	$	32,853		$	17,255		$	50,108		$	109,708		$	32,689		$	142,397
per boe	$	15.84		$	30.89		$	19.02		$	16.97		$	32.16		$	19.03
per share (3) (4)	$	0.20		$	0.37		$	0.26		$	0.66		$	1.13		$	0.79

Dividends from Longview (declared by Longview)	$	4,418		$	(7,013	)	$	(2,595	)	$	7,363		$	(11,683	)	$	(4,320	)

Expenditures on property, plant and equipment	$	40,627		$	21,589		$	62,216		$	123,645		$	29,332		$	152,977
Expenditures on exploration and evaluation assets		112			45			157			1,326			56			1,382
Total capital spending	$	40,739		$	21,634		$	62,373		$	124,971		$	29,388		$	154,359

Debt and working capital
Bank indebtedness										$	67,695		$	84,692		$	152,387
Convertible debentures										$	148,544		$	-		$	148,544
Working capital deficit										$	43,166		$	13,914		$	57,080

(1)	The nine months ended September 30, 2011 represents Longview's financial and operating results for the period from April 14 to September 30, 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 entity.

(4)	Consolidated funds from operations per share excludes funds from operations attributable to the non-controlling interest of Longview.

Advantage Oil & Gas Ltd. - 8

Overview

	Three months ended							Nine months ended
	September 30							September 30
	2011		2010		% change			2011		2010		% change
Cash provided by operating activities ($000)	$	64,025	$	53,681		19	%	$	138,249	$	161,902		(15	)%
Funds from operations ($000)	$	50,108	$	37,697		33	%	$	142,397	$	132,673		7	%
per share (1)	$	0.26	$	0.23		13	%	$	0.79	$	0.81		(3	)%
per boe	$	19.02	$	16.87		13	%	$	19.03	$	20.18		(6	)%

(1)	Based on basic weighted average shares outstanding and excludes funds from operations attributable to the non-controlling interest of Longview.

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. - 9

Petroleum and Natural Gas Sales and Hedging

	Three months ended								Nine months ended
	September 30								September 30
($000)	2011		2010			% change			2011			2010			% change
Natural gas sales	$	44,763	$	33,832			32	%	$	129,025		$	112,491			15	%
Realized hedging gains		6,598		12,388			(47	)%		21,395			42,489			(50	)%
Natural gas sales including hedging	$	51,361	$	46,220			11	%	$	150,420		$	154,980			(3	)%
Crude oil and NGLs sales	$	43,994	$	38,890			13	%	$	133,963		$	130,656			3	%
Realized hedging gains (losses)		442		(1,775	)		(125	)%		(2,127	)		(7,147	)		(70	)%
Crude oil and NGLs sales including hedging	$	44,436	$	37,115			20	%	$	131,836		$	123,509			7	%
Total (1)	$	95,797	$	83,335			15	%	$	282,256		$	278,489			1	%

(1) Total excludes unrealized derivative gains and losses.

Total sales, excluding hedging, increased 22% and 8% for the three and nine months ended September 30, 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. We have also experienced an increase in sales during 2011 due to higher realized crude oil and NGLs prices, excluding hedging. However, sales continue to be adversely impacted by the natural gas price environment that has been weak during the last several years attributable to many factors, including reduced energy demand and higher North American natural gas production, both of which have maintained relatively high natural gas inventory levels. The increase in sales during 2011 has also been partially offset by reduced production attributable to asset dispositions that closed in the second quarter of 2010.

Given the low natural gas price environment, our commodity price risk management program has delivered realized natural gas hedging gains of $6.6 million and $21.4 million for the three and nine months ended September 30, 2011, respectively. As crude oil prices have remained relatively strong, we realized a minor crude oil hedging gain of $0.4 million for the three months ended September 30, 2011 and a net crude oil hedging loss of $2.1 million for the nine months ended September 30, 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.

Production

	Three months ended									Nine months ended
	September 30									September 30
	2011			2010			% change			2011			2010			% change
Natural gas (mcf/d)		134,353			104,714			28	%		127,580			100,024			28	%
Crude oil (bbls/d)		4,658			4,686			(1	)%		4,552			5,140			(11	)%
NGLs (bbls/d)		1,588			2,149			(26	)%		1,587			2,258			(30	)%
Total (boe/d)		28,638			24,287			18	%		27,402			24,069			14	%
Natural gas (%)		78	%		72	%					78	%		69	%
Crude oil (%)		16	%		19	%					17	%		21	%
NGLs (%)		6	%		9	%					5	%		10	%

Average daily production during the third quarter of 2011 increased 18% above the same period of 2010, with a 28% increase in natural gas production partially offset by decreases in both crude oil and NGLs production. Production for the current quarter was comparable to the 28,750 boe/d reported in the second quarter of 2011.

Advantage Oil & Gas Ltd. - 10

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, production from Glacier was impacted due to planned facility downtime at our gas plant to complete our acid gas injection system and maintenance work conducted by TransCanada Pipelines (“TCPL”). In October 2011, we successfully commissioned the acid gas injection system which is now capable of injecting 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 in the second quarter of 2012. Current Glacier throughput is approximately 100 mmcf/d. These projects represent significant milestones towards achieving our Glacier Phase IV development and will provide additional flexibility for future production growth. Additional plant downtime will be required to accommodate future equipment installations to expand our Glacier gas plant processing capacity to 140 mmcf/d.

Longview’s production averaged 6,071 boe/d for the third quarter of 2011, an increase of 3% from 5,870 boe/d realized in the second quarter of 2011 with 75% from crude oil and NGLs. During the third quarter Longview conducted a variety of maintenance, workovers and reactivations that were delayed by approximately one quarter, due to wet weather conditions, and commenced their 2011 Alberta capital expenditure program in July with the Saskatchewan program beginning in September. Production additions resulted in Longview exiting the third quarter producing in excess of 6,400 boe/d. Additionally, at September 30, 2011, Longview had an estimated 400 boe/d behind-pipe that will be brought on production in the fourth quarter of 2011 to offset normal declines.

Commodity Prices and Marketing

Natural Gas

	Three months ended							Nine months ended
	September 30							September 30
($/mcf)	2011		2010		% change			2011		2010		% change
Realized natural gas prices
Excluding hedging	$	3.62	$	3.51		3	%	$	3.69	$	4.12		(10	)%
Including hedging	$	4.16	$	4.80		(13	)%	$	4.33	$	5.68		(24	)%
AECO daily index	$	3.66	$	3.54		3	%	$	3.77	$	4.12		(8	)%

Realized natural gas prices, excluding hedging, for the three months ended September 30, 2011 were slightly higher as compared to the same period of 2010 but decreased 10% for the nine months ended September 30, 2011 as compared to the same period of the prior year. Our realized natural gas prices, excluding hedging, for this quarter were 4% lower than the $3.77/mcf realized during the second quarter of 2011. Although natural gas prices have continued to remain weak, our commodity hedging strategy 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 have less natural gas production hedged for this year at lower average prices.

During 2010 and 2011, natural gas prices have remained low 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 have resulted in generally high inventory that has placed considerable downward pressure on natural gas prices. The 2009/2010 winter season experienced stronger inventory withdraws which helped to modestly strengthen prices in early 2010. However, as we exited the winter, natural gas prices significantly decreased and remained weak throughout 2010. During the 2010/2011 winter there were reasonable storage withdraws that helped to reduce natural gas inventory but natural gas prices still remained weak. Strong injections experienced in 2011 have pushed current inventory levels above the five-year average and kept natural gas prices low. We anticipate that, given the current environment, 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 increased drilling for new 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 continue to 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. - 11

Crude Oil and NGLs

	Three months ended							Nine months ended
	September 30							September 30
($/bbl)	2011		2010		% change			2011		2010		% change
Realized crude oil prices
Excluding hedging	$	82.31	$	70.75		16	%	$	86.13	$	72.17		19	%
Including hedging	$	83.34	$	66.63		25	%	$	84.42	$	67.07		26	%
Realized NGLs prices
Excluding hedging	$	59.69	$	42.41		41	%	$	62.16	$	47.68		30	%
Realized crude oil and NGLs prices
Excluding hedging	$	76.56	$	61.84		24	%	$	79.94	$	64.69		24	%
Including hedging	$	77.33	$	59.01		31	%	$	78.67	$	61.15		29	%
WTI ($US/bbl)	$	89.81	$	76.21		18	%	$	95.52	$	77.65		23	%
$US/$Canadian exchange rate	$	1.02	$	0.96		6	%	$	1.02	$	0.97		6	%

Realized crude oil and NGLs prices, excluding hedging, increased 24% for the three and nine month periods ended September 30, 2011, as compared to the same periods of 2010. However, realized crude oil and NGLs prices, excluding hedging, have decreased 13% for the third quarter of 2011 in comparison to the second quarter of 2011. Crude oil and NGL pricing experienced significant volatility during the third quarter whereby West Texas Intermediate (“WTI”) dropped 12% to US$89.81/bbl from US$102.55/bbl experienced in the second 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 civil unrest and associated supply concerns, with WTI currently trading at approximately US$97/bbl. However, we have also seen a constant 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 could 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 that are members of the syndicate for our Credit Facilities 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.

Advantage Oil & Gas Ltd. - 12

We have historically been active in entering financial contracts to protect future cash flows and currently the Corporation has the following derivatives in place:

Description of Derivative	Term	Volume	Average Price

Natural gas - AECO
Fixed price	January 2011 to December 2011	9,478 mcf/d	Cdn$6.24/mcf
Fixed price	January 2011 to December 2011	9,478 mcf/d	Cdn$6.24/mcf
Fixed price	January 2011 to December 2011	9,478 mcf/d	Cdn$6.26/mcf
		28,434 mcf/d	Cdn$6.25/mcf

Crude oil – WTI
Fixed price (1)	January 2011 to December 2011	1,500 bbls/d	Cdn$91.05/bbl

(1)

This financial contract was assumed by Longview from Advantage on April 14, 2011.

A summary of realized and unrealized hedging gains and losses for the three and nine months ended September 30, 2011 and 2010 are as follows:

	Three months ended									Nine months ended
	September 30									September 30
($000)	2011			2010			% change			2011			2010			% change
Realized hedging
Natural gas	$	6,598		$	12,388			(47	)%	$	21,395		$	42,489			(50	)%
Crude oil		442			(1,775	)		(125	)%		(2,127	)		(7,147	)		(70	)%
Total realized hedging gains	$	7,040		$	10,613			(34	)%	$	19,268		$	35,342			(45	)%
Unrealized hedging
Natural gas	$	(5,595	)	$	(18,776	)		(70	)%	$	(18,468	)	$	3,662			(604	)%
Crude oil		1,707			22,464			(92	)%		3,720			15,866			(77	)%
Total unrealized hedging gains (losses)	$	(3,888	)	$	3,688			(205	)%	$	(14,748	)	$	19,528			(176	)%
Total gains on derivatives	$	3,152		$	14,301			(78	)%	$	4,520		$	54,870			(92	)%

For the three months ended September 30, 2011, we recognized a net realized derivative gain of $7.0 million (September 30, 2010 - $10.6 million net realized derivative gain) and for the nine months ended September 30, 2011, we recognized a net realized derivative gain of $19.3 million (September 30, 2010 - $35.3 million net realized derivative gain) on settled derivative contracts, primarily as a result of lower average natural gas prices compared to our established average hedge prices. Our net realized derivative gain has decreased during 2011 as compared to 2010 as we have 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 September 30, 2011, the fair value of the derivative contracts outstanding and to be settled was a net asset of approximately $7.9 million, a decrease of $14.7 million from the $22.6 million net asset recognized as at December 31, 2010. For the nine months ended September 30, 2011, this $14.7 million decrease was recognized in income as an unrealized derivative loss (September 30, 2010 – $19.5 million unrealized derivative gain). The valuation of the derivatives is the estimated fair value to settle the contracts as at September 30, 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 (loss) 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 2011 corresponding to when the Corporation will recognize sales from production.

Advantage Oil & Gas Ltd. - 13

Royalties

	Three months ended									Nine months ended
	September 30									September 30
	2011			2010			% change			2011			2010			% change
Royalties ($000)	$	13,515		$	10,579			28	%	$	39,632		$	36,293			9	%
per boe	$	5.13		$	4.73			8	%	$	5.30		$	5.52			(4	)%
As a percentage of petroleum and natural gas sales		15.2	%		14.5	%		0.7	%		15.1	%		14.9	%		0.2	%

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 includes 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 have increased as compared to the prior year periods due to the increase in corporate production. Royalties as a percentage of petroleum and natural gas sales have increased slightly 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 11.4% and 20.7%, respectively. Advantage’s royalty rates, that are predominately based on 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 implemented a number of drilling incentive programs with reduced royalty rates over a period of time for qualifying wells. The majority of our wells brought on production since April 1, 2009 qualify and benefit from a 5% royalty rate on the first 500 mmcf produced or one-year, whichever occurs first, and a drilling credit of $200 per metre drilled that reduces capital spending. The reduced 5% royalty rate program is a permanent incentive while the drilling credit incentives were effective for qualifying wells drilled and brought on production from April 1, 2009 to March 31, 2011. The Alberta Provincial Government also made changes in the Natural Gas Deep Drilling Program (“NGDDP”) which reduces the vertical depth requirement to 2,000 metres (from 2,500 metres). As a result, all of our Montney horizontal wells at Glacier drilled after May 1, 2010 qualify for the NGDDP which is estimated to provide an additional 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, Alberta royalty rates will continue to fluctuate based on commodity prices, individual well productivity, and our ongoing capital development plans.

Operating Expense

	Three months ended							Nine months ended
	September 30							September 30
	2011		2010		% change			2011		2010		% change
Operating expense ($000)	$	22,552	$	23,456		(4	)%	$	67,449	$	71,798		(6	)%
per boe	$	8.56	$	10.50		(18	)%	$	9.02	$	10.93		(17	)%

Total operating expense decreased 4% for the three months and 6% for the nine months ended September 30, 2011 as compared to the same periods of 2010. Operating expense per boe decreased 18% and 17% for the three and nine months ended September 30, 2011 as compared to the prior year.

Operating expense per boe realized by Advantage on a stand-alone basis was $5.89/boe. The reduction in total operating expense has been primarily due to increased production from Glacier, benefits of our ongoing optimization program and the sale of higher cost assets. We anticipate corporate operating expense will decline further as a result of increasing production at Glacier. 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. Completing our Phase IV expansion at Glacier to 140 mmcf/d throughput in 2012 is expected to further reduce operating costs at Glacier from $0.30/mcf to the $0.20/mcf to $0.25/mcf range.

Advantage Oil & Gas Ltd. - 14

Operating expense per boe realized by Longview for the current quarter was $18.47/boe. During the third quarter Longview conducted a variety of maintenance, workovers and reactivations that were delayed and commenced their 2011 Alberta capital expenditure program in July with the Saskatchewan program beginning in September. The additional well maintenance and workover activity during the quarter lead to higher operating costs. Production additions resulted in Longview exiting the third quarter producing in excess of 6,400 boe/d. Additionally, at September 30, 2011, Longview had an estimated 400 boe/d behind-pipe that will be brought on production in the fourth quarter of 2011 to offset normal declines. With some continuing well maintenance and workover activity still required, we anticipate operating costs to be $16.00/boe to $17.00/boe during the fourth quarter of 2011.

General and Administrative Expense

	Three months ended							Nine months ended
	September 30							September 30
	2011		2010		% change			2011		2010		% change
General and administrative expense
Cash expense ($000)	$	4,941	$	5,997		(18	)%	$	17,120	$	19,119		(10	)%
per boe	$	1.87	$	2.68		(30	)%	$	2.29	$	2.91		(21	)%
Non-cash expense ($000)	$	3,997	$	3,707		8	%	$	10,241	$	10,838		(6	)%
per boe	$	1.52	$	1.66		(8	)%	$	1.37	$	1.65		(17	)%
Total general and administrative expense ($000)	$	8,938	$	9,704		(8	)%	$	27,361	$	29,957		(9	)%
per boe	$	3.39	$	4.34		(22	)%	$	3.66	$	4.56		(20	)%
Employees at September 30									125		127		(2	)%

Cash general and administrative (“G&A”) expense for the nine months ended September 30, 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 primarily 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. If a share price return for a twelve-month period is positive, a restricted share grant will be calculated based on the return. If a 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. Compensation cost related to the Plans are recognized as share-based compensation expense within G&A expense over the service periods and incorporates the share grant price, the estimated number of restricted shares to vest, and certain management estimates.

For the nine months ended September 30, 2011, Advantage granted 1,443,956 restricted shares at an average grant price of $7.78 per restricted share and recognized $9.6 million of share-based compensation expense as non-cash G&A expense related to restricted shares granted to service providers. During the nine months ended September 30, 2011 Advantage issued 1,842,462 shares to service providers in accordance with the vesting provisions of the RSPIP. As at September 30, 2011, 2,487,279 restricted shares remain unvested and will vest to service providers over the next two years with a total of $7.3 million in compensation cost to be recognized over the future service periods.

For the nine months ended September 30, 2011, Longview granted 150,722 restricted shares at a grant price of $11.45 per restricted share and recognized $0.6 million of share-based compensation expense as non-cash G&A expense related to restricted shares granted to service providers. During the nine months ended September 30, 2011 Longview issued 50,236 shares to service providers in accordance with the vesting provisions of the RSPIP. As at September 30, 2011, 100,486 restricted shares remain unvested and will vest to service providers over the next two years with a total of $0.9 million in compensation cost to be recognized over the future service periods.

Advantage Oil & Gas Ltd. - 15

Depreciation Expense

	Three months ended							Nine months ended
	September 30							September 30
	2011		2010		% change			2011		2010		% change
Depreciation expense ($000)	$	40,151	$	32,460		24	%	$	111,258	$	92,085		21	%
per boe	$	15.24	$	14.53		5	%	$	14.87	$	14.01		6	%

Depreciation expense has increased for the three and nine months ended September 30, 2011 as compared to 2010 due to the increase in production and a higher average rate of depreciation per boe. The depreciation rate per boe has been impacted by our active and ongoing capital development program focused at Glacier, Alberta and an increase in property, plant and equipment associated with a higher decommissioning liability. 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.

Exploration and Evaluation Expense

	Three months ended							Nine months ended
	September 30							September 30
	2011		2010		% change			2011		2010		% change
Exploration and evaluation expense ($000)	$	129	$	-		100	%	$	1,347	$	-		100	%
per boe	$	0.05	$	-		100	%	$	0.18	$	-		100	%

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 nine months ended September 30, 2011, we expensed exploration and evaluation costs of $1.3 million related to undeveloped land that expired during the period.

Other Income

	Three months ended								Nine months ended
	September 30								September 30
($000)	2011		2010			% change			2011		2010		% change
Gain on sale of property, plant and equipment	$	1,076	$	(1,644	)		(165	)%	$	1,172	$	47,172		(98	)%
Miscellaneous income		424		19			2,132	%		559		547		2	%
	$	1,500	$	(1,625	)		(192	)%	$	1,731	$	47,719		(96	)%

Other income primarily consists of gains related to the disposition of property, plant and equipment. During the first nine months of 2010, Advantage disposed of several non-core properties and recognized a $47.2 million net gain. For the nine months ended September 30, 2011, Longview disposed of a minor non-core property for net cash proceeds of $1.0 million and recognized a $1.1 million gain.

Advantage Oil & Gas Ltd. - 16

Interest on Bank Indebtedness

	Three months ended									Nine months ended
	September 30									September 30
	2011			2010			% change			2011			2010			% change
Interest on bank indebtedness ($000)	$	2,791		$	3,277			(15	)%	$	9,341		$	9,970			(6	)%
per boe	$	1.06		$	1.47			(28	)%	$	1.25		$	1.52			(18	)%
Average effective interest rate		5.8	%		4.9	%		0.9	%		5.5	%		5.1	%		0.4	%
Bank indebtedness at September 30 ($000)										$	152,387		$	263,306			(42	)%

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. Consolidated bank indebtedness outstanding at the end of September 30, 2011 was $152.4 million consisting of $67.7 million and $84.7 million for each of the legal entities Advantage and Longview, respectively. Advantage’s consolidated Credit Facilities of $475 million at September 30, 2011 includes $275 million with Advantage and $200 million with Longview. On September 30, 2010 our bank indebtedness was much higher due to the maturity and settlement of our 6.50% convertible debentures on June 30, 2010 for $69.9 million in cash. 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

	Three months ended							Nine months ended
	September 30							September 30
	2011		2010		% change			2011		2010		% change
Interest on convertible debentures ($000)	$	2,314	$	2,348		(1	)%	$	6,876	$	9,183		(25	)%
per boe	$	0.88	$	1.05		(16	)%	$	0.92	$	1.40		(34	)%
Accretion on convertible debentures ($000)	$	854	$	822		4	%	$	2,536	$	2,439		4	%
per boe	$	0.32	$	0.37		(12	)%	$	0.34	$	0.37		(9	)%
Convertible debentures maturity value at September 30 ($000)								$	148,544	$	148,544		-	%

Interest on convertible debentures for 2011 has decreased compared to 2010 due to the maturity of the 6.50% debentures on June 30, 2010. Accretion on convertible debentures has remained relatively comparable for the periods.

Accretion on Decommissioning Liability

	Three months ended							Nine months ended
	September 30							September 30
	2011		2010		% change			2011		2010		% change
Accretion on decommissioning liability ($000)	$	1,257	$	1,413		(11	)%	$	4,289	$	4,824		(11	)%
per boe	$	0.48	$	0.63		(24	)%	$	0.57	$	0.73		(22	)%

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 2.83% of the liability. Accretion expense has decreased slightly primarily due to a lower annualized rate of accretion associated with the continued decrease in risk-free interest rates.

Advantage Oil & Gas Ltd. - 17

Taxes

Deferred income taxes arise from differences between the accounting and tax bases of our assets and liabilities. For the nine months ended September 30, 2011, the Corporation recognized a deferred income tax expense of $0.8 million compared to $25.2 million for the same period of 2010. The deferred income tax expense decreased as compared to 2010 due to the significant reduction in income before taxes. As at September 30, 2011, the Corporation had a deferred income tax liability balance of $37.9 million compared to $40.2 million at December 31, 2010.

Net Income Attributable to Non-Controlling Interest

At September 30, 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 nine months ended September 30, 2011, Advantage recognized a $6.0 million reduction to net income related to Longview’s net income attributable to the non-controlling interests.

Net Income (Loss) and Comprehensive Income (Loss)

	Three months ended									Nine months ended
	September 30									September 30
	2011			2010			% change			2011			2010		% change
Net income (loss) and comprehensive income (loss) ($000)	$	(2,997	)	$	(660	)		354	%	$	(7,709	)	$	63,808		(112	)%
per share - basic	$	(0.02	)	$	-			-	%	$	(0.05	)	$	0.39		(113	)%
- diluted	$	(0.02	)	$	-			-	%	$	(0.05	)	$	0.39		(113	)%

Net loss and net loss per share was realized for the nine months ended September 30, 2011, a decrease as compared to the net income and net income per share for the same period of 2010 primarily due to both gains on derivatives and asset dispositions for 2010 that have not been recognized in 2011. The derivative gains recognized in 2010 included both realized and unrealized amounts. Our net realized derivative gain has decreased during 2011 as compared to 2010 as we have less natural gas production hedged for this year at lower average prices and we have generally realized losses on our crude oil hedges. The unrealized derivative gains represent the change in the fair value of the derivative contracts outstanding and to be settled. 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 (loss) as a derivative gain or loss with a corresponding derivative asset and liability recorded on the statement of financial position. As well, during the first nine months of 2010 Advantage disposed of several non-core properties and recognized a $47.2 million net gain.

Strong operating results have contributed significantly to our 2011 net income and comprehensive income. Sales, excluding hedging, for the nine months ended September 30, 2011 increased due to a 14% increase in production and a 24% increase in realized crude oil and NGLs prices, excluding hedging. However, 78% of our total production is natural gas and sales were adversely impacted by natural gas prices, excluding hedging, that decreased 10% as compared to 2010. Our major challenge continues to be the natural gas price environment that has remained weak. Operating costs have improved through increased production volumes at Glacier, divestment of higher cost non-core assets and an aggressive optimization program that continues to demonstrate positive benefits. We anticipate that corporate operating costs will further decrease as a result of increasing lower cost production from our Glacier property. Higher depreciation expense has been recognized due to the higher realized production and an increase in property, plant and equipment associated with a higher decommissioning liability.

Advantage Oil & Gas Ltd. - 18

Cash Netbacks

	Three months ended												Nine months ended
	September 30												September 30
	2011						2010						2011						2010
	$000			per boe			$000			per boe			$000			per boe			$000			per boe
Petroleum and natural gas sales	$	88,757		$	33.69		$	72,722		$	32.54		$	262,988		$	35.16		$	243,147		$	37.00
Royalties		(13,515	)		(5.13	)		(10,579	)		(4.73	)		(39,632	)		(5.30	)		(36,293	)		(5.52	)
Realized gain on derivatives		7,040			2.67			10,613			4.75			19,268			2.58			35,342			5.38
Operating expense		(22,552	)		(8.56	)		(23,456	)		(10.50	)		(67,449	)		(9.02	)		(71,798	)		(10.93	)
Operating	$	59,730		$	22.67		$	49,300		$	22.06		$	175,175		$	23.42		$	170,398		$	25.93
General and administrative (1)		(4,941	)		(1.87	)		(5,997	)		(2.68	)		(17,120	)		(2.29	)		(19,119	)		(2.91	)
Finance expense (2)		(5,105	)		(1.94	)		(5,625	)		(2.52	)		(16,217	)		(2.17	)		(19,153	)		(2.92	)
Miscellaneous income	$	424		$	0.16			19		$	0.01		$	559		$	0.07			547		$	0.08
Funds from operations and cash netbacks	$	50,108		$	19.02		$	37,697		$	16.87		$	142,397		$	19.03		$	132,673		$	20.18

(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 third quarter of 2011 increased 18% above the same period of 2010, with a 28% increase in natural gas production partially offset by decreases in both crude oil and NGLs 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 and nine months ended September 30, 2011 we realized gains on derivatives of $7.0 million and $19.3 million, respectively. Our hedging program has helped to offset the continued weak natural gas 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. 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 second quarter of 2011, our funds from operations and funds from operations per boe were 4% lower as realized crude oil and NGL prices decreased during this quarter.

Advantage Oil & Gas Ltd. - 19

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.

	Payments due by period
($ millions)	Total		2011		2012		2013		2014		2015
Building leases	$	8.2	$	0.8	$	3.4	$	2.5	$	1.5	$	-
Pipeline/transportation		39.7		2.4		12.4		11.9		10.6		2.4
Bank indebtedness (1)		152.4		-		-		152.4		-		-
Convertible debentures (2)		148.5		62.3		-		-		-		86.2
Total contractual obligations	$	348.8	$	65.5	$	15.8	$	166.8	$	12.1	$	88.6

(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 September 30, 2011, Advantage had $148.5 million convertible debentures outstanding (excluding interest payable during the various debenture terms). Each series of convertible debentures are convertible to 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 shares at Advantage’s option.

Liquidity and Capital Resources

The following table is a summary of the Corporation’s capitalization structure.

	September 30, 2011
($000, except as otherwise indicated)	Advantage		Longview		Consolidated
Bank indebtedness (non-current)	$	67,695	$	84,692	$	152,387
Working capital deficit (1)		43,166		13,914		57,080
Net debt	$	110,861	$	98,606	$	209,467
Convertible debentures maturity value (current and non-current)		148,544		-		148,544
Total debt	$	259,405	$	98,606	$	358,011
Shares outstanding		165,934,471		46,750,246
Shares closing market price ($/share)	$	3.95	$	8.97
Market capitalization (2)	$	655,441	$	419,350

(1)

Working capital deficit is a non-GAAP measure that includes trade and other receivables, prepaid expenses and deposits, and trade and other accrued liabilities.

(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 asset), 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 Oil & Gas Ltd. - 20

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 placed considerable pressure on commodity prices. Natural gas prices have remained low for several years due to the weaker economy as well as high relative inventory levels with AECO gas presently trading at approximately $3.45/mcf. However, crude oil 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 civil unrest and associated supply concerns, with WTI currently trading at approximately US$97/bbl. The outlook for the Corporation from prolonged weak commodity prices would be reductions in operating netbacks and funds from operations. Management has partially mitigated this risk through our commodity hedging program but the lower natural gas price environment has still had a significant negative impact. 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 balance funds from operations and our capital program expenditure requirements. A successful hedging program was also executed to help reduce the volatility of funds from operations. However, we are still 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.

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 September 30, 2011, Advantage had 165.9 million shares outstanding. During 2011 Advantage issued 1,842,462 shares to employees in accordance with the vesting provisions of the RSPIP. As at November 10, 2011, shares outstanding have increased to 166.3 million.

The Corporation had $148.5 million convertible debentures outstanding at September 30, 2011 that were immediately convertible to 13.0 million shares based on the applicable conversion prices (December 31, 2010 - $148.5 million outstanding and convertible to 13.0 million shares). During the nine months ended September 30, 2011, there were no conversions of debentures. As at November 10, 2011, the convertible debentures outstanding have not changed from September 30, 2011. We have $62.3 million of 7.75% and 8.00% debentures that mature in December 2011 and $86.2 million of 5.00% debentures that mature in January 2015. These obligations can be settled through the payment of cash or issuance of shares at Advantage’s option. We currently anticipate settling the debentures that mature in December 2011 with cash from our Credit Facilities.

Bank Indebtedness, Credit Facilities and Other Obligations

At September 30, 2011, Advantage had consolidated bank indebtedness outstanding of $152.4 million consisting of $67.7 million and $84.7 million for each of the legal entities Advantage and Longview, respectively. Bank indebtedness has decreased $138.3 million since December 31, 2010, primarily due the sale of a 37% non-controlling interest in Longview partially offset by capital expenditures required to complete our Phase III development program at Glacier, Alberta. Advantage’s consolidated credit facilities of $475 million at September 30, 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. As of November 10, 2011, Advantage had consolidated bank indebtedness of approximately $165 million outstanding. 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 Oil & Gas Ltd. - 21

Advantage had a consolidated working capital deficiency of $57.1 million as at September 30, 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 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. 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 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 with consideration comprised of 29,450,000 common shares of Longview representing a 63% equity ownership and $251.5 million in cash, subject to final adjustments per the purchase and sale agreement. 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 $106.7 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. Therefore, for the nine months ended September 30, 2011, Advantage recognized a $6.0 million reduction to net income related to Longview’s net income attributable to the non-controlling interests. This $6.0 million increased non-controlling interest on the statement of financial position with a decrease of $4.3 million related to dividends declared by Longview to the non-controlling interest ownership.

Capital Expenditures

	Three months ended					Nine months ended
	September 30					September 30
($000)	2011			2010		2011			2010
Drilling, completions and workovers	$	45,142		$	52,158	$	114,109		$	114,191
Well equipping and facilities		16,336			13,438		36,873			36,886
Land and seismic		646			551		1,566			2,271
Other		92			22		429			306
Expenditures on property, plant and equipment		62,216			66,169		152,977			153,654
Expenditures on exploration and evaluation assets		157			1,116		1,382			1,562
Proceeds from property disposition		(985	)		1,032		(985	)		(69,450	)

Net capital expenditures (1)	$	61,388		$	68,317	$	153,374		$	85,766

(1)	Net capital expenditures excludes changes in non-cash working capital and change in decommission 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 such as to fully capitalize on both natural gas and crude oil exploration and development opportunities. The stand-alone capital program for Advantage is focused primarily on developing a significant natural gas resource play at Glacier, Alberta while Longview has a capital program focused on oil or oil with liquids rich solution gas projects.

Advantage Oil & Gas Ltd. - 22

Advantage on a legal entity basis spent a net $123.7 million on property, plant and equipment for the nine months ended September 30, 2011, including $105.3 million at Glacier, $4.0 million in Saskatchewan, $3.7 million at Brazeau, $3.0 million at Nevis, $2.0 million at Westerose and the remaining balance at other areas. Capital spending projects at Saskatchewan, Brazeau, Nevis and Westerose were accelerated during early 2011 and 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 included the drilling of 28 net (28 gross) horizontal wells 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 drill a sufficient number of wells to fill our plant; 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 which includes drilling 30 wells (100% working interest) was delayed by approximately 1½ months while conditions improved. Advantage has three drilling rigs contracted and drilled 7 wells during the third quarter of 2011 with 3 wells drilling at September 30, 2011 and subsequently rig released. Completion of our Phase IV wells has begun and the fourth quarter of 2011 and first quarter of 2012 will be very active with finishing our drilling and completion program. In October 2011, we successfully commissioned the acid gas injection system which is now capable of injecting 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 in the second quarter of 2012. Current Glacier throughput is approximately 100 mmcf/d. These projects represent significant milestones towards achieving our Glacier Phase IV development and will provide additional flexibility for future production growth. Additional plant downtime will be required to accommodate future equipment installations to expand our Glacier gas plant processing capacity to 140 mmcf/d.

Longview’s 2011 capital budget is 100% focused on oil or oil with liquids rich solution gas projects. The majority of our 2011 capital program will be completed through 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 September 30, 2011, Longview spent a net $29.3 million which included $9.7 million at Nevis, $7.4 million at Pembina, $4.3 million at Westerose, $3.5 million at Steelman, and $1.4 million at Skaro with the remaining spending for miscellaneous projects. Longview had two to three rigs contracted throughout much of the third quarter with two of the rigs targeting Alberta prospects and the additional rig targeting the Midale formation in southeast Saskatchewan. As of September 30, 2011, Longview had drilled 11.5 net (15 gross) oil wells and had two rigs continuing to complete their capital program. During the third quarter Longview also conducted a variety of maintenance, workovers and reactivations that had been delayed by approximately one quarter due to wet weather conditions. This increased activity during the quarter significantly impacted production whereby Longview exited the third quarter producing in excess of 6,400 boe/d. Additionally, at September 30, 2011, Longview had an estimated 400 boe/d behind-pipe that will be brought on production in the fourth quarter of 2011 to offset normal declines.

Advantage Oil & Gas Ltd. - 23

Sources and Uses of Funds

The following table summarizes the various funding requirements during the periods ended September 30, 2011 and 2010 and the sources of funding to meet those requirements:

	Nine months ended
	September 30
($000)	2011		2010
Sources of funds
Proceeds from change in ownership of Longview	$	160,757	$	-
Funds from operations		142,397		132,673
Property dispositions		985		69,450
Increase in bank indebtedness		-		13,043
Change in non-cash working capital and other		-		33,383
	$	304,139	$	248,549
Uses of funds
Expenditures on property, plant and equipment	$	141,664	$	155,316
Decrease in bank indebtedness		138,270		-
Interest paid		15,152		15,972
Dividends paid by Longview		3,455		-
Expenditures on decommissioning liability		2,574		4,464
Change in non-cash working capital and other		1,574		-
Expenditures on exploration and evaluation assets		1,382		1,562
Reduction of capital lease obligations		68		1,308
Convertible debenture maturities		-		69,927
	$	304,139	$	248,549

Advantage Oil & Gas Ltd. - 24

Quarterly Performance

($000, except as otherwise	2011								2010										2009 (1)
indicated)	Q3			Q2		Q1			Q4			Q3			Q2		Q1		Q4
Daily production
Natural gas (mcf/d)		134,353			136,986		111,145			106,125			104,714			107,821		87,346		84,466
Crude oil and NGLs (bbls/d)		6,246			5,919		6,251			6,620			6,835			7,395		7,975		8,488
Total (boe/d)		28,638			28,750		24,775			24,308			24,287			25,365		22,533		22,566
Average prices
Natural gas ($/mcf)
Excluding hedging	$	3.62		$	3.77	$	3.72		$	3.49		$	3.51		$	3.81	$	5.26	$	4.28
Including hedging	$	4.16		$	4.29	$	4.55		$	4.81		$	4.80		$	5.58	$	6.87	$	6.90
AECO daily index	$	3.66		$	3.88	$	3.78		$	3.63		$	3.53		$	3.89	$	4.95	$	4.49
Crude oil and NGLs ($/bbl)
Excluding hedging	$	76.56		$	88.27	$	75.41		$	69.19		$	61.84		$	64.66	$	67.23	$	63.04
Including hedging	$	77.33		$	86.21	$	72.82		$	64.14		$	59.01		$	61.80	$	62.42	$	57.85
WTI ($US/bbl)	$	89.81		$	102.55	$	94.25		$	85.18		$	76.21		$	77.98	$	78.79	$	76.17
Total sales including realized hedging	$	95,797		$	99,971	$	86,488		$	86,012		$	83,335		$	96,377	$	98,777	$	98,782
Net income (loss)	$	(2,997	)	$	997	$	(5,709	)	$	(22,888	)	$	(659	)	$	31,379	$	33,089	$	(14,213	)
per share - basic	$	(0.02	)	$	0.01	$	(0.03	)	$	(0.14	)	$	-		$	0.19	$	0.20	$	(0.09	)
- diluted	$	(0.02	)	$	0.01	$	(0.03	)	$	(0.14	)	$	-		$	0.19	$	0.20	$	(0.09	)
Funds from operations	$	50,108		$	52,041	$	40,248		$	40,629		$	37,698		$	45,291	$	49,685	$	50,083

(1)	The financial and operating data for 2009 was prepared in accordance with the previous Canadian generally accepted accounting principles.

The table above highlights the Corporation’s performance for the third quarter of 2011 and also for the preceding seven quarters. Production in the fourth quarter of 2009 increased 3% from the prior quarter due to new production additions which was partially offset by some natural declines and cold weather conditions that typically cause production interruptions. In addition, an extended third party facility outage at our Lookout Butte property that began in 2008, resulting in 1,100 boe/d of reduced production continuing through much of 2009, was completed and our production came back on in November 2009. 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 additional asset dispositions during the end of the second quarter of 2010 representing approximately 1,700 boe/d that resulted in lower production. The full impact of these dispositions resulted in a decrease in production for the third quarter of 2010 with our production remaining consistent during the fourth quarter of 2010. 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 financial results, particularly sales and funds from operations have been negatively impacted as commodity prices decreased. During the much of 2010 and throughout 2011, natural gas prices have remained low, which has decreased our corresponding sales and funds from operations. However, sales and funds from operations increased considerably in the second quarter of 2011 due to the higher production and improved realized crude oil and NGLs prices. Advantage has recognized net losses during 2009 through 2011 primary driven by weak commodity prices, particularly natural gas. Partially offsetting the net losses experienced during these periods has been the continuing reduction in costs including royalties and operating expenses.

Advantage Oil & Gas Ltd. - 25

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 net income, comprehensive income and the borrowing bases of the Corporation.

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 24 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.

Advantage Oil & Gas Ltd. - 26

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 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 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.

Advantage Oil & Gas Ltd. - 27

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.

·	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.

IFRS 9 Financial Instruments: Classification and Measurement

IFRS 9 was issued in November 2009. This standard is the first step in the process to replace IAS 39 Financial Instruments: Recognition and Measurement. IFRS 9 introduces new requirements for classifying and measuring assets and liabilities, which may affect the Corporation’s accounting for its financial assets. The standard is not applicable until January 1, 2013 but is available for early adoption. However, in August 2011, the International Accounting Standards Board issued an exposure draft which proposed changing the effective date to annual periods beginning on or after January 1, 2015. The Corporation is continuing to monitor the status of this exposure draft.

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. The 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. The standard is not applicable until January 1, 2013.

Advantage Oil & Gas Ltd. - 28

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. The 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. The standard is not applicable until January 1, 2013.

i) Internal Controls

In accordance with the Corporations approach to certification of internal controls required under Canadian Securities Administrators’ National instrument 52-109 and SOX 302 and 404, all entity level, information technology, disclosures and business process controls will require updating and testing to reflect changes arising from our conversion to IFRS. Upon review with internal audit, we have determined there to be minimal updating of processes, controls and documentation required which is in progress.

Disclosure Controls and Internal Controls over Financial Reporting

Disclosure controls and procedures have been designed to provide reasonable assurance that information required to be disclosed by the Corporation is recorded, processed, summarized and reported within the time periods specified under the Canadian securities law.

Advantage’s Chief Executive Officer and Chief Financial Officer are responsible for establishing and maintaining internal controls over financial reporting (“ICFR”). They have, as at the quarter ended September 30, 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 ICFR is the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations.

Advantage’s Chief Executive Officer and Chief Financial Officer are required to disclose any change in the internal controls over financial reporting 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 period ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

It should be noted that a control system, including Advantage’s disclosure and internal controls and procedures, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

Advantage Oil & Gas Ltd. - 29

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 290 meters in the Upper, Middle and Lower Montney formations. During our first three phases of development, a total of 60 net Montney horizontal wells (51.3 net Upper Montney and 8.7 net Lower Montney) were drilled on our 80 net section land block which offers significant opportunity to further delineate and develop each of the Montney layers. Following our review of drilling results to date, Advantage believes our Montney well inventory could be between 900 and 1,150 horizontal wells.

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 drill a sufficient number of wells to fill our plant; and ii) further evaluate the Middle and Lower Montney formations. In conjunction with the anticipated production increase at Glacier, Advantage stand-alone production is forecast to grow 24% to a June 30, 2012 exit rate of approximately 29,000 boe/d at which time Glacier will represent approximately 80% of total production.

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 which includes drilling 30 wells (100% working interest) was delayed by approximately 1½ months while conditions improved. Advantage has three drilling rigs contracted and drilled 7 wells during the third quarter of 2011 with 3 wells drilling at September 30, 2011 and subsequently rig released. Completion of our Phase IV wells has begun and the fourth quarter of 2011 and first quarter of 2012 will be very active with finishing our drilling and completion program. In October 2011, we successfully commissioned the acid gas injection system which is now capable of injecting 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 in the second quarter of 2012. Current Glacier throughput is approximately 100 mmcf/d. These projects represent significant milestones towards achieving our Glacier Phase IV development and will provide additional flexibility for future production growth. Additional plant downtime will be required to accommodate future equipment installations to expand our Glacier gas plant processing capacity to 140 mmcf/d.

Advantage’s budget reinforces our pure play natural gas resource focus which is predicated on investing in economic growth and additional reserve and resource identification, while maintaining a strong balance sheet in the context of prevailing economic conditions. Our go forward capital program will be funded primarily out of cash flow, our undrawn credit facilities and potential divestments of conventional assets. Drilling results at our cornerstone Glacier property have demonstrated that our Montney development is among the top tier natural gas resource developments in North America. The attractive cost structure at Glacier which includes low operating costs and low royalty rates combined with a multi-decade drilling inventory provides a strong foundation to drive future development beyond current production. We have begun the initial evaluation of future growth phases to increase Glacier throughput to the 175 to 200 mmcf/d range. We will continue with a technically focused and financially disciplined approach to create value from our Glacier property.

Advantage Oil & Gas Ltd. - 30

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 have since demonstrated strong financial and operating results with funds from operations supported by high crude oil prices and increasing production. Longview’s 2011 capital budget of $50 to $60 million is 100% focused on oil or oil with liquids rich solution gas projects and includes drilling 23.0 net (31 gross) wells. The majority of Longview’s 2011 capital program will be completed through the third and fourth quarters of 2011 due to the wet ground conditions that hampered activities in the spring and summer. Longview had two to three rigs contracted throughout much of the third quarter with two of the rigs targeting Alberta prospects and the additional rig targeting the Midale formation in southeast Saskatchewan. As of September 30, 2011, Longview had drilled 11.5 net (15 gross) oil wells and had two rigs continuing to complete their capital program. During the third quarter Longview also conducted a variety of maintenance, workovers and reactivations that had been delayed by approximately one quarter due to wet weather conditions. This increased activity during the quarter significantly impacted production whereby Longview exited the third quarter producing in excess of 6,400 boe/d. Additionally, at September 30, 2011, Longview had an estimated 400 boe/d behind-pipe that will be brought on production in the fourth quarter of 2011 to offset normal declines. With some continuing well maintenance and workover activity still required, we anticipate operating costs to be $16.00/boe to $17.00/boe during the fourth quarter of 2011. Longview is focused on successfully executing their 2011 capital program, focusing on operational and cost efficiencies to increase returns and produce stable cash flows with a conservative financial structure.

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 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.

November 10, 2011

Advantage Oil & Gas Ltd. - 31

Consolidated Financial Statements

Consolidated Statement of Financial Position

(thousands of Canadian dollars) (unaudited)	Notes	September 30, 2011			December 31, 2010			January 1, 2010
					(note 24)			(note 24)
ASSETS
Current assets
Trade and other receivables	7	$	34,391		$	42,276		$	54,531
Prepaid expenses and deposits			7,452			6,488			9,936
Derivative asset	6		7,865			25,157			30,829
Total current assets			49,708			73,921			95,296

Non-current assets
Derivative asset			-			-			323
Exploration and evaluation assets	8		8,205			8,262			6,923
Property, plant and equipment	9		1,985,102			1,883,762			1,824,699
Total non-current assets			1,993,307			1,892,024			1,831,945

Total assets		$	2,043,015		$	1,965,945		$	1,927,241

LIABILITIES
Current liabilities
Trade and other accrued liabilities		$	98,923		$	112,457		$	113,062
Capital lease obligations			-			759			1,375
Convertible debentures	12		62,246			62,013			69,927
Derivative liability	6		-			2,367			12,755
Total current liabilities			161,169			177,596			197,119

Non-current liabilities
Derivative liability			-			177			1,165
Capital lease obligations			-			-			759
Bank indebtedness	11		151,826			288,852			247,784
Convertible debentures	12		75,114			72,811			131,561
Decommissioning liability	13		233,185			172,130			169,665
Deferred income tax liability	21		37,934			40,231			22,115
Other liability	14		1,146			1,835			3,431
Total non-current liabilities			499,205			576,036			576,480

Total liabilities			660,374			753,632			773,599

SHAREHOLDERS' EQUITY
Share capital	15		2,212,010			2,199,491			2,190,409
Convertible debentures equity component	12		8,348			8,348			8,348
Contributed surplus	5		71,380			14,783			6,114
Deficit			(1,018,018	)		(1,010,309	)		(1,051,229	)
Total shareholders' equity attributable to Advantage shareholders			1,273,720			1,212,313			1,153,642
Non-controlling interest			108,921			-			-
Total shareholders' equity			1,382,641			1,212,313			1,153,642
Total liabilities and shareholders' equity		$	2,043,015		$	1,965,945		$	1,927,241

Commitments (note 23)

See accompanying Notes to the Interim Consolidated Financial Statements

Advantage Oil & Gas Ltd. - 32

Consolidated Statement of Comprehensive Income (Loss)

		Three months ended						Nine months ended
(thousands of Canadian dollars, except for per share amounts) (unaudited)	Notes	September 30, 2011			September 30, 2010			September 30, 2011			September 30, 2010
					(note 24)						(note 24)

Petroleum and natural gas sales		$	88,757		$	72,722		$	262,988		$	243,147
Less: royalties			(13,515	)		(10,579	)		(39,632	)		(36,293	)
Petroleum and natural gas revenue			75,242			62,143			223,356			206,854

Operating expense			(22,552	)		(23,456	)		(67,449	)		(71,798	)
General and administrative expense	18		(8,938	)		(9,704	)		(27,361	)		(29,957	)
Depreciation expense	9		(40,151	)		(32,460	)		(111,258	)		(92,085	)
Exploration and evaluation expense	8		(129	)		-			(1,347	)		-
Gains on derivatives	6		3,152			14,301			4,520			54,870
Other income (expense)	19		1,500			(1,625	)		1,731			47,719
Operating income before finance, taxes and non-controlling interest			8,124			9,199			22,192			115,603
Finance expense	20		(7,239	)		(7,909	)		(23,122	)		(26,577	)

Income (loss) before taxes and non-controlling interest			885			1,290			(930	)		89,026
Income tax expense	21		(1,237	)		(1,950	)		(787	)		(25,218	)

Net income (loss) and comprehensive income (loss) before non-controlling interest			(352	)		(660	)		(1,717	)		63,808
Net income attributable to non-controlling interest			(2,645	)		-			(5,992	)		-
Net income (loss) and comprehensive income (loss) attributable to Advantage shareholders		$	(2,997	)	$	(660	)	$	(7,709	)	$	63,808

Net income (loss) per share attributable to Advantage shareholders	17
Basic		$	(0.02	)	$	(0.00	)	$	(0.05	)	$	0.39
Diluted		$	(0.02	)	$	(0.00	)	$	(0.05	)	$	0.39

See accompanying Notes to the Interim Consolidated Financial Statements

Advantage Oil & Gas Ltd. - 33

Consolidated Statement of Changes in Shareholders' Equity

(thousands of Canadian dollars) (unaudited)	Notes	Share capital		Convertible debentures equity component		Contributed surplus			Deficit			Total shareholders' equity attributable to Advantage shareholders			Non-controlling interest			Total shareholders' equity
Balance, January 1, 2011		$	2,199,491	$	8,348	$	14,783		$	(1,010,309	)	$	1,212,313		$	-		$	1,212,313
Share based compensation	16		12,519		-		(571	)		-			11,948			-			11,948
Common control transaction and change in ownership interest	5		-		-		57,168			-			57,168			106,674			163,842
Change in ownership interest, share based compensation			-		-		-			-			-			575			575
Net income (loss) and comprehensive income (loss)			-		-		-			(7,709	)		(7,709	)		5,992			(1,717	)
Dividends declared by Longview ($0.25 per Longview share)			-		-		-			-			-			(4,320	)		(4,320	)
Balance, September 30, 2011		$	2,212,010	$	8,348	$	71,380		$	(1,018,018	)	$	1,273,720		$	108,921		$	1,382,641

Balance, January 1, 2010	24	$	2,190,409	$	8,348	$	6,114		$	(1,051,229	)	$	1,153,642		$	-		$	1,153,642
Share based compensation	16		6,287		-		8,259			-			14,546			-			14,546
Net income and comprehensive income			-		-		-			63,808			63,808			-			63,808
Balance, September 30, 2010		$	2,196,696	$	8,348	$	14,373		$	(987,421	)	$	1,231,996		$	-		$	1,231,996

See accompanying Notes to the Interim Consolidated Financial Statements

Advantage Oil & Gas Ltd. - 34

Consolidated Statement of Cash Flows		Three months ended						Nine months ended
(thousands of Canadian dollars) (unaudited)	Notes	September 30, 2011			September 30, 2010			September 30, 2011			September 30, 2010
					(note 24)						(note 24)
Operating Activities
Operating income before finance, taxes and non-controlling interest		$	8,124		$	9,199		$	22,192		$	115,603
Add (deduct) items not requiring cash:
Share based compensation	16		3,997			3,707			10,241			10,838
Depreciation expense	9		40,151			32,460			111,258			92,085
Exploration and evaluation expense	8		129			-			1,347			-
Unrealized loss (gain) on derivatives	6		3,888			(3,688	)		14,748			(19,528	)
Gain on sale of property, plant and equipment	19		(1,076	)		1,644			(1,172	)		(47,172	)
Expenditures on decommissioning liability	13		(1,029	)		(2,603	)		(2,574	)		(4,464	)
Changes in non-cash working capital	22		9,841			12,962			(17,791	)		14,540
Cash provided by operating activities			64,025			53,681			138,249			161,902

Financing Activities
Proceeds from Longview financing	5		(53	)		-			160,757			-
Increase (decrease) in bank indebtedness	11		(30,222	)		(10,224	)		(138,270	)		13,043
Convertible debenture maturities	12		-			-			-			(69,927	)
Dividends paid by Longview			(2,593	)		-			(3,455	)		-
Reduction of capital lease obligations			-			(617	)		(68	)		(1,308	)
Convertible debenture issue costs			-			-			-			(310	)
Interest paid			(4,642	)		(5,855	)		(15,152	)		(15,972	)
Cash provided by (used in) financing activities			(37,510	)		(16,696	)		3,812			(74,474	)

Investing Activities
Expenditures on property, plant and equipment	9		(27,343	)		(34,837	)		(141,664	)		(155,316	)
Expenditures on exploration and evaluation assets	8		(157	)		(1,116	)		(1,382	)		(1,562	)
Property dispositions			985			(1,032	)		985			69,450
Cash used in investing activities			(26,515	)		(36,985	)		(142,061	)		(87,428	)
Net change in cash			-			-			-			-
Cash, beginning of period			-			-			-			-
Cash, end of period		$	-		$	-		$	-		$	-

See accompanying Notes to the Interim Consolidated Financial Statements

Advantage Oil & Gas Ltd. - 35

Notes to The Interim Consolidated Financial Statements

September 30, 2011 (unaudited)

All tabular amounts are in thousands of Canadian dollars except as otherwise indicated.

Business and structure of Advantage

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.

Basis of preparation

(a)

Statement of compliance

These interim consolidated financial statements are a component of Advantage’s first annual audited consolidated financial statements to be prepared and issued under International Financial Reporting Standards (“IFRS”) for the year ended December 31, 2011, with a transition date to IFRS of January 1, 2010. As a result, the comparative figures for 2010 and Advantage’s financial position as at January 1, 2010 have been restated from Canadian Generally Accepted Accounting Principles (“Previous GAAP”) to IFRS. The reconciliations to IFRS from Previous GAAP are summarized in note 24 and discloses 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 24, 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 interim consolidated financial statements of Advantage have been prepared by management in accordance with IAS 34 – Interim Financial Reporting and are in accordance with IFRS 1 – First-time Adoption of IFRS, as they are part of the year ending December 31, 2011, the fiscal period of the Corporation’s first IFRS financial statements.

The policies applied in these condensed interim consolidated financial statements are based on IFRS effective for the year ended December 31, 2011, as issued and outstanding as of November 10, 2011, the date the Board of Directors approved the statements. Any changes to IFRS that occur subsequent to November 10, 2011 will be reflected in the Corporation’s future interim and annual consolidated financial statements and could result in restatement of these interim consolidated financial statements, including the transition adjustments recognized on change-over to IFRS.

The interim consolidated financial statements should be read in conjunction with the Corporation’s Previous GAAP annual financial statements for the year ended December 31, 2010. Note 24 discloses IFRS information for the year ended December 31, 2010 that is material to an understanding of these interim consolidated financial statements.

(b)

Basis of measurement

The consolidated financial statements have been prepared on the historical cost basis, except for derivative instruments, which are measured at fair value.

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.

Advantage Oil & Gas Ltd. - 36

2. Basis of preparation (continued)

(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.

Significant accounting policies

The accounting policies set out below have been applied consistently to all years presented in these consolidated 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 and comprehensive income.

(iii)

Jointly controlled assets

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

The Corporation’s financial instruments consist of financial assets, financial liabilities, and non-financial derivatives. 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 other financial liabilities. 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 other financial liabilities are recognized at amortized cost using the effective interest method and impairment losses are recorded in income when incurred. With all new financial instruments, an election is available that allows entities to classify any financial instrument as fair value through profit or loss. Only those financial assets and liabilities that must be classified as fair value through profit or loss are classified as such by the Corporation.

Advantage Oil & Gas Ltd. - 37

Significant accounting policies (continued)

(c)

Financial instruments (continued)

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 inthe consolidated statement of comprehensive income 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.

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

The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation, and for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

Exploration and evaluation costs

Pre-license costs are recognized in the statement of comprehensive income as incurred.

All exploratory costs incurred subsequent to acquiring the right to explore for oil and natural gas are capitalized. 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.

Exploration and evaluation costs initially are capitalized as either tangible or intangible exploration or evaluation assets according to the nature of the assets acquired. The costs are accumulated in cost centers by well, field or exploration area pending determination of technical feasibility and commercial viability.

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. For purposes of impairment testing, exploration and evaluation assets are allocated to cash-generating units.

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. A review of each exploration license or field is carried out, at least annually, to ascertain whether proved and probable reserves have been discovered. 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. If the well or exploration project did not encounter potentially economic oil and gas quantities, the costs are expensed and reported in exploration and evaluation expense in the period incurred.

Advantage Oil & Gas Ltd. - 38

Significant accounting policies (continued)

(d)

Property, plant and equipment and exploration and evaluation assets (continued)

(i)

Recognition and measurement (continued)

Development and production costs

Items of property, plant and equipment, which include oil and gas development and production assets, are measured at cost (including directly attributable general and administrative costs) 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 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).

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.

(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 comprehensive income 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.

Proved and probable reserves are estimated using independent reserve engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon:

a reasonable assessment of the future economics of such production;

a reasonable expectation that there is a market for all or substantially all the expected oil and natural gas production; and

evidence that the necessary production, transmission and transportation facilities are available or can be made available.

Advantage Oil & Gas Ltd. - 39

Significant accounting policies (continued)

(d)

Property, plant and equipment and exploration and evaluation assets (continued)

(iii)

Depreciation (continued)

Reserves may only be considered proved and probable if producibility is supported by either actual production or conclusive formation tests. The area of reservoir considered proved and probable includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, or both, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geophysical, geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of oil and natural gas controls the lower proved limit of the reservoir.

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are only included in the proved and probable classification when successful testing by a pilot project, the operation of an installed program in the reservoir, or other reasonable evidence (such as, experience of the same techniques on similar reservoirs or reservoir simulation studies) provides support for the engineering analysis on which the project or program was based.

The Corporation records furniture and equipment at cost and provides depreciation on the declining balance method at a rate of 20% per annum which is designed to amortize the cost of the assets over their estimated useful lives. Depreciation methods, useful lives and residual values are reviewed at each reporting date.

(e)

Asset swaps

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 comprehensive income.

For exchanges or parts of exchanges that involve only exploration and evaluation assets (if applicable), the exchange is accounted for at carrying value.

(f)

Impairment

(i)

Financial assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.

Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

All impairment losses are recognized in income.

An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in comprehensive income.

Advantage Oil & Gas Ltd. - 40

Significant accounting policies (continued)

(f)

Impairment (continued)

(ii)

Non-financial assets

The carrying amounts of the Corporation’s non-financial assets, other than exploration and evaluation assets and deferred income tax assets, 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 goodwill and other intangible assets that have indefinite lives or that are not yet available for use, an impairment test is completed each year. Exploration and evaluation assets are assessed for impairment when they are reclassified to property, plant and equipment, as oil and natural gas interests, and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.

For the purpose of impairment testing, 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”). 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.

Any goodwill acquired in a business combination, for the purpose of impairment testing, is allocated to the CGU’s that are expected to benefit from the synergies of the combination. Exploration and evaluation assets are allocated to related CGU’s when they are assessed for impairment, both at the time of any triggering facts and circumstances as well as upon their eventual reclassification to producing assets (oil and natural gas interests in property, plant and equipment).

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in income. Impairment losses recognized in respect of CGU’s are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the unit (group of units) on a pro rata basis.

An impairment loss in respect of goodwill is not reversed. In respect of other assets, 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 or amortization, 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. Decommissioning liabilities are not recognized for future operating losses.

Advantage Oil & Gas Ltd. - 41

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 the Corporation. The restricted share grants generally vest one-third immediately on grant date, with the remaining two-thirds vesting evenly on the following two yearly anniversary dates. Compensation cost related to the Plan is recognized as compensation expense within general and administrative expense over the service period and incorporates the share grant price, 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 oil 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. With respect to the latter, the entity is acting as a collection agent on behalf of others.

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 borrowings and capital leases, and accretion of the discount on the decommissioning liability and convertible debentures.

(l)

Borrowing costs capitalized

Borrowing costs incurred for the construction of qualifying assets are capitalized during the period of time that is required to complete and prepare the assets for their intended use or sale. The Corporation considers a qualifying asset to be any significant construction project expected to take more than twelve months to complete. The capitalization rate used to determine the amount of borrowing costs to be capitalized is the weighted average interest rate applicable to the Corporation’s outstanding general and specific borrowings during the period.

Advantage Oil & Gas Ltd. - 42

Significant accounting policies (continued)

(m)

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.

The Corporation offsets deferred income tax assets and deferred income tax liabilities relating to the same taxable entity and same tax jurisdiction.

(n)

Net income per share

Basic net income per share is calculated by dividing the net income attributable to common shareholders of the Corporation by the weighted average number of common shares outstanding during the period. Diluted net income per share is determined by adjusting the net income 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.

Advantage Oil & Gas Ltd. - 43

Significant accounting policies (continued)

(o)

New standards and interpretations not yet adopted

IFRS 9 Financial Instruments: Classification and Measurement

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. - 44

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 9 – impairment;

Note 6, 12 – valuation of convertible debentures;

Note 13 – measurement of decommissioning liability;

Note 16 – measurement of share based compensation; and

Note 21 – measurement of deferred income tax.

Judgements

In the process of applying the Corporation’s accounting policies, management has made the following judgements, 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 are in close proximity to existing or established development and production properties (either of the Corporation or another industry participant), 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 are classified as exploration and evaluation assets.

(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, the latter having an impact on the proportion of the gross reserves which are attributable to provincial governments under respective royalty frameworks. 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. - 45

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. This would generally result from significant changes in any of the factors or assumptions used in estimating reserves. These factors could include:

Changes in proved plus probable reserves.

The effect on proved plus probable reserves of differences between actual commodity prices and commodity price assumptions.

The effect on proved plus probable reserves of differences between the estimated and actual future costs to develop the proved and probable reserves of any properties not developed at the time reserves are estimated.

The effect on proved plus probable reserves of differences between estimated and actual royalties paid in future periods.

The effect on proved plus probable reserves of differences between actual and estimated future costs associated with well site and facility abandonment.

Unforeseen operational issues.

(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 clearly indicate 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, including the discount rate applied.

(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.

Advantage Oil & Gas Ltd. - 46

Significant accounting judgments, estimates and assumptions (continued)

(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.

Common-Control Transaction

Advantage sold certain oil-weighted assets to Longview for total consideration of $545.9 million, comprised of 29,450,000 common shares of Longview representing a 63% equity ownership and $251.5 million in cash, subject to final adjustments per the purchase and sale agreement. 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 $57.2 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 September 30, 2011, Advantage held 63% of Longview’s issued and outstanding shares.

Advantage Oil & Gas Ltd. - 47

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 other liabilities and similarly measured at amortized cost. As at September 30, 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 other liabilities and measured 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 September 30, 2011, the estimated fair value of the total outstanding convertible debenture obligation was $139.5 million (December 31, 2010 - $153.2 million). The fair value of the liability component of convertible debentures was determined based on a discounted cash flow model assuming no future conversions and continuation of current interest and principal payments as well as taking into consideration the current public trading activity of such debentures. The Corporation applied discount rates of between 4% and 9% considering current available market information, assumed credit adjustments, and various terms to maturity.

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.

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.

Advantage Oil & Gas Ltd. - 48

Financial risk management (continued)

Advantage has an established strategy to manage the risk associated with changes in commodity prices by entering into non-financial derivatives, which are recorded at fair value as derivative assets and liabilities with gains and losses recognized through comprehensive income. As the fair value of the contracts varies with commodity prices, they give rise to financial assets and liabilities. The fair values of the derivatives are determined by a Level 2 valuation model, where pricing inputs other than quoted prices in an active market are used. These 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 and foreign exchange rates as compared to the valuation assumptions.

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.

(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:

	September 30, 2011		December 31, 2010		January 1, 2010
Trade and other receivables	$	34,391	$	42,276	$	54,531
Deposits		2,739		2,936		6,108
Derivative asset		7,865		25,157		31,152
	$	44,995	$	70,369	$	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 national 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 September 30, 2011, $1.3 million or 3.8% 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 that the entire balance is collectible, and in some instances we have the ability to mitigate risk through withholding production or offsetting payables with the same parties. Management has provided for an allowance for doubtful accounts of $0.3 million at September 30, 2011 (December 31, 2010 - $0.2 million).

The Corporation’s most significant customer, a Canadian oil and natural gas marketer, accounts for $12.7 million of the trade and other receivables at September 30, 2011 (December 31, 2010 - $12.1 million).

Advantage Oil & Gas Ltd. - 49

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, and derivative liabilities are primarily due within one year of the balance sheet 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 credit facility agreements for $475 million. 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 credit facilities constitutes a revolving facility for a 364 day term which are extendible annually for a further 364 day revolving period at the option of the syndicate. If not extended, the revolving credit facilities are converted to one year term facilities with the principal payable at the end of such one year terms. 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 several series of convertible debentures outstanding that mature from 2011 to 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 September 30, 2011 are as follows:

		Less than one year		One to three years		Four to five years		Thereafter		Total
Trade and other accrued liabilities		$	98,923	$	-	$	-	$	-	$	98,923
Other liability			1,146		-		-		-		1,146
Bank indebtedness	- principal		-		152,387		-		-		152,387
	- interest		8,422		6,121		-		-		14,543
Convertible debentures	- principal		62,294		-		86,250		-		148,544
	- interest		6,746		8,625		2,156		-		17,527
		$	177,531	$	167,133	$	88,406	$	-	$	433,070

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.

Advantage Oil & Gas Ltd. - 50

Financial risk management (continued)

(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% increase in the forward natural gas prices used to calculate the fair value of the natural gas derivatives at September 30, 2011 could decrease earnings by approximately $0.5 million for the nine months ended September 30, 2011. As well, an increase of 10% in the forward crude oil prices used to calculate the fair value of the crude oil derivatives at September 30, 2011 could decrease earnings by $0.5 million for the nine months ended September 30, 2011. A similar increase in the currency rate assumption underlying the derivatives fair value does not materially decrease earnings.

As at September 30, 2011, the Corporation had the following derivatives in place:

Description of Derivative	Term	Volume	Average Price
Natural gas - AECO
Fixed price	January 2011 to December 2011	9,478 mcf/d	Cdn$6.24/mcf
Fixed price	January 2011 to December 2011	9,478 mcf/d	Cdn$6.24/mcf
Fixed price	January 2011 to December 2011	9,478 mcf/d	Cdn$6.26/mcf

Crude oil – WTI
Fixed price	January 2011 to December 2011	1,500 bbls/d	Cdn $91.05/bbl

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	April 2010 to January 2011	18,956 mcf/d	Cdn$7.25/mcf
Fixed price	January 2011 to December 2011	9,478 mcf/d	Cdn$6.24/mcf
Fixed price	January 2011 to December 2011	9,478 mcf/d	Cdn$6.24/mcf
Fixed price	January 2011 to December 2011	9,478 mcf/d	Cdn$6.26/mcf

Crude oil – WTI
Fixed price	April 2010 to January 2011	2,000 bbls/d	Cdn$69.50/bbl
Fixed price	January 2011 to December 2011	1,500 bbls/d	Cdn $91.05/bbl

As at September 30, 2011, the fair value of the derivatives outstanding resulted in an asset of approximately $7.9 million (December 31, 2010 – $25.2 million) and a liability of $Nil (December 31, 2010 – $2.5 million).

For the nine months ended September 30, 2011, $4.5 million was recognized in net loss as a derivative gain (September 30, 2010 - $54.9 million derivative gain). The table below summarizes the realized and unrealized gains (losses) on derivatives.

Advantage Oil & Gas Ltd. - 51

Financial risk management (continued)

(c)

Price and currency risk (continued)

	Three months ended					Nine months ended
	September 30, 2011			September 30, 2010		September 30, 2011			September 30, 2010
Realized gains on deriviatives	$	7,040		$	10,613	$	19,268		$	35,342
Unrealized gains (losses) on derivatives		(3,888	)		3,688		(14,748	)		19,528
	$	3,152		$	14,301	$	4,520		$	54,870

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 100 basis points higher throughout the nine months ended September 30, 2011, net loss would have increased by $1.8 million (September 30, 2010 - $1.4 million) based on the average debt balance outstanding during the period.

(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 September 30, 2011, December 31, 2010 and January 1, 2010 is as follows:

($000, except as otherwise indicated)	September 30, 2011		December 31, 2010		January 1, 2010
Bank indebtedness (non-current)	$	152,387	$	290,657	$	250,262
Working capital deficit (1)		57,080		64,452		49,970
Net debt	$	209,467	$	355,109	$	300,232
Shares outstanding		165,934,471		164,092,009		162,745,528
Share closing market price ($/share)		3.95		6.76		6.90
Market capitalization (2)		655,441		1,109,262		1,122,944
Convertible debentures maturity value (current and non-current)		148,544		148,544		218,471
Capital lease obligations (non-current)		-		-		759
Total capitalization	$	1,013,452	$	1,612,915	$	1,642,406

(1) Working capital deficit is a non-IFRS measure that includes trade and other receivables, prepaid expenses and deposits, trade and other accrued liabilities, and the current portion of capital lease obligations.

(2) Market capitalization is a non-IFRS measure calculated by multiplying shares outstanding by the closing market share price on the applicable date.

Advantage Oil & Gas Ltd. - 52

Financial risk management (continued)

(e)

Capital management (continued)

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.

The Corporation’s capital management objectives, policies and processes have remained unchanged during the nine months ended September 30, 2011.

Trade and other receivables

	September 30, 2011		December 31, 2010		January 1, 2010
Trade receivables	$	27,942	$	30,997	$	31,608
Receivables from joint venture partners		5,261		6,296		13,719
Other		1,188		4,983		9,204
	$	34,391	$	42,276	$	54,531

Exploration and evaluation assets

Balance at January 1, 2010	$	6,923
Additions		2,091
Exploration and evaluation expense		(752	)
Balance at December 31, 2010	$	8,262
Additions		1,382
Transferred to property, plant and equipment		(92	)
Exploration and evaluation expense		(1,347	)
Balance at September 30, 2011	$	8,205

Advantage Oil & Gas Ltd. - 53

Property, plant and equipment

	Oil & gas			Furniture and
Cost	properties			equipment		Total
Balance at January 1, 2010	$	1,821,078		$	3,621	$	1,824,699
Additions		221,280			403		221,683
Change in decomissioning liability		37,073			-		37,073
Disposals		(60,482	)		-		(60,482	)
Balance at December 31, 2010	$	2,018,949		$	4,024	$	2,022,973
Additions		152,548			429		152,977
Change in decomissioning liability		59,710			-		59,710
Disposals		(184	)		-		(184	)
Transferred from exploration and evaluation assets		92			-		92
Balance at September 30, 2011	$	2,231,115		$	4,453	$	2,235,568

	Oil & gas			Furniture and
Accumulated depreciation and impairment losses	properties			equipment		Total
Balance at January 1, 2010	$	-		$	-	$	-
Depreciation		123,360			1,232		124,592
Impairment loss		17,500			-		17,500
Disposals		(2,881	)		-		(2,881	)
Balance at December 31, 2010	$	137,979		$	1,232	$	139,211
Depreciation		110,774			484		111,258
Disposals		(3	)		-		(3	)
Balance at September 30, 2011	$	248,750		$	1,716	$	250,466

	Oil & gas			Furniture and
Net book value	properties			equipment		Total
At January 1, 2010	$	1,821,078		$	3,621	$	1,824,699
At December 31, 2010	$	1,880,970		$	2,792	$	1,883,762
At September 30, 2011	$	1,982,365		$	2,737	$	1,985,102

During the period ended December 31, 2010, Advantage recognized an impairment loss of $17.5 million. The loss relates to a cash generating unit which incurred a decline in recoverable amount based on a fair value less costs to sell determination. For the nine months ended September 30, 2011, no impairment losses were recorded (September 30, 2010 - $Nil).

During the nine months ended September 30, 2011, Advantage capitalized general and administrative expenditures directly related to development activities of $5.8 million (September 30, 2010 - $7.0 million).

Advantage included future development costs of $1.5 billion (December 31, 2010 – $1.5 billion) in property, plant and equipment costs subject to depreciation.

Advantage Oil & Gas Ltd. - 54

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 September 30, 2011, amounts due from Longview totaled $0.1 million (December 31, 2010 - $Nil). Advantage charged Longview $2.3 million during the nine months ended September 30, 2011 under the TSA. Dividends declared and payable from Longview to Advantage during the nine months ended September 30, 2011 totaled $7.4 million. 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.

11.

Bank indebtedness

	September 30, 2011			December 31, 2010			January 1, 2010
Revolving credit facility	$	152,387		$	290,657		$	250,262
Discount on Bankers Acceptances and other fees		(561	)		(1,805	)		(2,478	)
Balance, end of period	$	151,826		$	288,852		$	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 September 30, 2011 and December 31, 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 nine months ended September 30, 2011, the average effective interest rate on the outstanding amounts under the facility was approximately 5.5% (September 30, 2010 – 5.1%). Advantage also has issued letters of credit totaling $8.8 million at September 30, 2011 (September 30, 2010 – $9.6 million).

Advantage Oil & Gas Ltd. - 55

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	AAV.DBE		AAV.DBD			AAV.DBG		AAV.DBH
Issue date	May 18, 2005		Sep. 15, 2004			Nov. 13, 2006		Dec. 31, 2009
Maturity date	June 30, 2010		Dec. 1, 2011			Dec. 31, 2011		Jan. 30, 2015
Conversion price	$	24.96	$	21.00		$	20.33	$	8.60

Liability component	$	69,952	$	50,000		$	41,445	$	73,019
Equity component		-		-			-		13,231

Gross proceeds		69,952		50,000			41,445		86,250
Issuance costs		-		(2,190	)		-		(3,735	)

Net proceeds	$	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		Redemption
Debenture	Redemption Periods	Price

7.75%	After December 1, 2009 and before December 1, 2011	$	1,000
8.00%	After December 31, 2010 and before December 31, 2011	$	1,025
5.00%	After January 31, 2013 and on or before January 30, 2015	$	1,000
	Provided that Current Market Price exceeds 125% of Conversion Price

Advantage Oil & Gas Ltd. - 56

12.

Convertible debentures (continued)

The balance of debentures outstanding at September 30, 2011 and changes in the liability and equity components during the period ended September 30, 2011 and year ended December 31, 2010 are as follows:

	6.50%			7.75%
Trading symbol	AAV.DBE			AAV.DBD
Debentures outstanding	$	-		$	46,766
Liability component:
Balance at January 1, 2010	$	69,927		$	46,176
Accretion of discount		-			309
Matured		(69,927	)		-
Balance at December 31, 2010		-			46,485
Accretion of discount		-			233
Balance at September 30, 2011	$	-		$	46,718

	8.00%			5.00%		Total
Trading symbol	AAV.DBG			AAV.DBH
Debentures outstanding	$	15,528		$	86,250	$	148,544
Liability component:
Balance at January 1, 2010	$	15,528		$	69,857	$	201,488
Accretion of discount		-			2,954		3,263
Matured		-			-		(69,927	)
Balance at December 31, 2010		15,528			72,811		134,824
Accretion of discount		-			2,303		2,536
Balance at September 30, 2011	$	15,528		$	75,114	$	137,360

Equity component:
Balance at January 1, 2010	$	-		$	8,348	$	8,348
Balance at December 31, 2010	$	-		$	8,348	$	8,348
Balance at September 30, 2011	$	-		$	8,348	$	8,348

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 nine months ended September 30, 2011.

Advantage Oil & Gas Ltd. - 57

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 2011 and 2071. A risk-free rate of 2.83% (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:

	Nine months ended			Year ended
	September 30, 2011			December 31, 2010
Balance, beginning of period	$	172,130		$	169,665
Accretion expense		4,289			6,094
Liabilities incurred		2,631			3,331
Change in estimates		8,861			6,601
Effect of change in risk-free rate		48,218			27,141
Property dispositions		(370	)		(34,427	)
Liabilities settled		(2,574	)		(6,275	)
Balance, end of period	$	233,185		$	172,130

14.

Other liability

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.

A reconcilation of the other liability is as follows:

	Nine months ended			Year ended
	September 30, 2011			December 31, 2010
Balance, beginning of period	$	1,835		$	3,431
Accretion expense		80			199
Reduction of liability by subleasing space		-			(538	)
Liability settled		(769	)		(1,257	)
Balance, end of period	$	1,146		$	1,835

15.

Share capital

(a)

Authorized

The Corporation is authorized to issue an unlimited number of shares without nominal or par value.

(b)

Issued

	Number of Shares		Amount
Balance at January 1, 2010		162,745,528	$	2,190,409
Share based compensation		1,346,481		9,082
Balance at December 31, 2010		164,092,009	$	2,199,491
Share based compensation		1,842,462		12,519
Balance at September 30, 2011		165,934,471	$	2,212,010

Advantage Oil & Gas Ltd. - 58

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 the Corporation. 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. 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 evenly on the following two yearly anniversary dates. 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 summarizes information about restricted shares outstanding at September 30, 2011:

	Restricted										Restricted		Weighted
	Shares		Restricted		Restricted			Restricted			Shares		average fair
	Outstanding		Shares		Shares			Shares			Outstanding		value at
Date Granted	December 31, 2010		Granted		Vested			Forfeited			September 30, 2011		grant date
January 15, 2009		181,483		-		(181,483	)		-			-	$	5.49
September 2, 2009		702,595		-		(347,105	)		(10,381	)		345,109	$	5.80
October 15, 2009		371,648		-		(1,068	)		(5,500	)		365,080	$	7.51
January 12, 2010		504,846		-		(253,146	)		(3,719	)		247,981	$	7.27
April 12, 2010		640,967		-		(318,722	)		(7,334	)		314,911	$	6.97
July 12, 2010		524,329				(259,504	)		(7,261	)		257,564	$	6.53
January 12, 2011		-		67,343		(22,575	)		(722	)		44,046	$	6.95
April 11, 2011		-		816,579		(272,203	)		(3,994	)		540,382	$	8.28
July 11, 2011		-		560,034		(186,656	)		(1,172	)		372,206	$	7.15
Total		2,925,868		1,443,956		(1,842,462	)		(40,083	)		2,487,279

Advantage Oil & Gas Ltd. - 59

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:

	Three months ended						Nine months ended
	September 30, 2011			September 30, 2010			September 30, 2011			September 30, 2010
Net income (loss) attributable to Advantage shareholders
Basic	$	(2,997	)	$	(660	)	$	(7,709	)	$	63,808
RSPIP		-			-			-			-
Convertible debentures		-			-			-			-
Diluted	$	(2,997	)	$	(660	)	$	(7,709	)	$	63,808
Weighted average shares outstanding
Basic		165,647,020			163,536,868			165,074,955			163,275,757
RSPIP		-			-			-			1,052,184
Convertible debentures		-			-			-			-
Diluted		165,647,020			163,536,868			165,074,955			164,327,941

The calculation of diluted net income (loss) per share for the three and nine months ended September 30, 2011 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 three and nine months ended September 30, 2011 was 13,019,819 shares for both periods (three and nine months ended September 30, 2010 – 13,019,819 and 14,867,004 shares, respectively). As at September 30, 2011, the total convertible debentures outstanding were immediately convertible to 13,019,819 shares (September 30, 2010 – 13,019,819 shares).

Restricted shares have been excluded from the calculation of diluted net income (loss) per share for the three and nine months ended September 30, 2011, as the impacts would have been anti-dilutive. Total weighted average shares issuable in exchange for the restricted shares and excluded from the diluted net income (loss) per share calculation for the three and nine months ended September 30, 2011 was 1,305,154 and 1,451,231 shares, respectively (three months ended September 30, 2010 – 1,417,495 shares).

Advantage Oil & Gas Ltd. - 60

18.

General and administrative expense (“G&A”)

	Three months ended						Nine months ended
	September 30, 2011			September 30, 2010			September 30, 2011			September 30, 2010
Salaries and benefits	$	5,079		$	4,822		$	15,553		$	15,088
Share based compensation (note 15,16)		4,890			5,917			12,542			16,633
Office rent		514			748			1,747			2,152
Other		388			558			3,336			3,041
Total G&A		10,871			12,045			33,178			36,914
Capitalized (note 9)		(1,933	)		(2,341	)		(5,817	)		(6,957	)
Net G&A	$	8,938		$	9,704		$	27,361		$	29,957

19.

Other income (expense)

	Three months ended					Nine months ended
	September 30, 2011		September 30, 2010			September 30, 2011		September 30, 2010
Gain on sale of property, plant and equipment	$	1,076	$	(1,644	)	$	1,172	$	47,172
Miscellaneous income		424		19			559		547
Total other income	$	1,500	$	(1,625	)	$	1,731	$	47,719

20.

Finance expense

	Three months ended				Nine months ended
	September 30, 2011		September 30, 2010		September 30, 2011		September 30, 2010
Interest on bank indebtedness	$	2,791	$	3,277	$	9,341	$	9,970
Interest on convertible debentures		2,314		2,348		6,876		9,183
Accretion on convertible debentures		854		822		2,536		2,439
Accretion of decomissioning liability		1,257		1,413		4,289		4,824
Accretion of other liability		23		49		80		161
Total finance expense	$	7,239	$	7,909	$	23,122	$	26,577

21.

Income tax expense

Income tax expense is recognized based on management’s best estimate of the weighted average annual income tax rate expected for the full financial year. The estimated average annual rate used for the nine months ended September 30, 2011 was 26.56% (September 30, 2010 – 28.50%).

Advantage Oil & Gas Ltd. - 61

22.

Supplemented cash flow information

Changes in non-cash working capital is comprised of:

	Nine months ended
	September 30, 2011			September 30, 2010
Source(use) of cash:
Trade and other receivables	$	7,885		$	18,748
Prepaid expenses and deposits		(964	)		3,386
Trade and other accrued liabilities		(13,534	)		(9,544	)
	$	(6,613	)	$	12,590

Related to operating activities	$	(17,791	)	$	14,540
Related to financing activities		2,145			2,261
Related to investing activities		9,033			(4,211	)
	$	(6,613	)	$	12,590

23.

Operating leases

Advantage has several lease commitments relating to office buildings and transportation. The estimated remaining annual minimum operating lease payments are as follows, of which $1.1 million is recognized in other liability (note 14):

2011	$	3,297
2012		15,726
2013		14,392
2014		12,016
2015		2,458
	$	47,889

Advantage Oil & Gas Ltd. - 62

24.

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 Canadian generally accepted accounting principles (“Previous GAAP”). These financial statements, for the interim period ended September 30, 2011, are prepared in accordance with International Financial Reporting Standards (“IFRS”) in conjunction with the Corporation’s first annual audited Consolidated Financial Statements to be issued as at and for the year ended December 31, 2011. 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:

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. - 63

24.

Transition to IFRS (continued)

Reconciliation of consolidated statement of financial position at the date of IFRS transition, January 1, 2010.

					Effect of
		Previous			Transition			IFRS
(thousands of Canadian dollars) (unaudited)	Notes	GAAP			to IFRS			Reclassifications			IFRS

ASSETS
Current assets
Trade and other receivables		$	54,531		$	-		$	-		$	54,531
Prepaid expenses and deposits			9,936			-			-			9,936
Derivative asset			30,829			-			-			30,829
Total current assets			95,296			-			-			95,296

Non-current assets
Derivative asset			323			-			-			323
Exploration and evaluation assets	2		-			-			6,923			6,923
Property, plant and equipment	2		1,831,622			-			(6,923	)		1,824,699
Total non-current assets			1,831,945			-			-			1,831,945

Total assets		$	1,927,241		$	-		$	-		$	1,927,241

LIABILITIES
Current liabilities
Trade and other accrued liabilities	6	$	111,901		$	-		$	1,161		$	113,062
Capital lease obligations			1,375			-			-			1,375
Convertible debentures	4		69,553			374			-			69,927
Derivative liability			12,755			-			-			12,755
Deferred income tax liability	5		4,704			-			(4,704	)		-
Total current liabilities			200,288			374			(3,543	)		197,119

Non-current liabilities
Derivative liability			1,165			-			-			1,165
Capital lease obligations			759			-			-			759
Bank indebtedness			247,784			-			-			247,784
Convertible debentures	4		130,658			903			-			131,561
Decommissioning liability	3		68,555			101,110			-			169,665
Deferred income tax liability	5		38,796			(21,385	)		4,704			22,115
Other liability			3,431			-			-			3,431
Total non-current liabilities			491,148			80,628			4,704			576,480

Total liabilities			691,436			81,002			1,161			773,599

SHAREHOLDERS' EQUITY
Share capital			2,190,409			-			-			2,190,409
Convertible debentures equity component	4		18,867			(10,519	)		-			8,348
Contributed surplus	6		7,275			-			(1,161	)		6,114
Deficit			(980,746	)		(70,483	)		-			(1,051,229	)
Total shareholders' equity			1,235,805			(81,002	)		(1,161	)		1,153,642
Total liabilities and shareholders' equity		$	1,927,241		$	-		$	-		$	1,927,241

Advantage Oil & Gas Ltd. - 64

24.

Transition to IFRS (continued)

Reconciliation of consolidated statement of financial position at the end of the comparative interim period, September 30, 2010.

					Effect of
		Previous			Transition			IFRS
(thousands of Canadian dollars)(unaudited)	Notes	GAAP			to IFRS			Reclassifications			IFRS

ASSETS
Current assets
Trade and other receivables		$	35,783		$	-		$	-		$	35,783
Prepaid expenses and deposits			6,550			-			-			6,550
Derivative asset			34,537			-			-			34,537
Total current assets			76,870			-			-			76,870

Non-current assets
Derivative asset			5,276			-			-			5,276
Exploration and evaluation assets	2		-			-			8,485			8,485
Property, plant and equipment	1,2,3		1,743,430			101,179			(8,485	)		1,836,124
Total non-current assets			1,748,706			101,179			-			1,849,885

Total assets		$	1,825,576		$	101,179		$	-		$	1,926,755

LIABILITIES
Current liabilities
Trade and other accrued liabilities		$	103,518		$	-		$	-		$	103,518
Capital lease obligations			826			-			-			826
Derivative liability			3,053			-			-			3,053
Deferred income tax liability	5		8,320			-			(8,320	)		-
Total current liabilities			115,717			-			(8,320	)		107,397

Non-current liabilities
Bank indebtedness			261,254			-			-			261,254
Convertible debentures	4		133,442			558			-			134,000
Decommissioning liability	3		57,430			84,730			-			142,160
Deferred income tax liability	5		31,967			7,046			8,320			47,333
Other liability			2,615			-			-			2,615
Total non-current liabilities			486,708			92,334			8,320			587,362

Total liabilities			602,425			92,334			-			694,759

SHAREHOLDERS' EQUITY
Share capital			2,196,696			-			-			2,196,696
Convertible debentures equity component	4		15,896			(7,548	)		-			8,348
Contributed surplus	4		17,344			(2,971	)		-			14,373
Deficit			(1,006,785	)		19,364			-			(987,421	)
Total shareholders' equity			1,223,151			8,845			-			1,231,996
Total liabilities and shareholders' equity		$	1,825,576		$	101,179		$	-		$	1,926,755

Advantage Oil & Gas Ltd. - 65

24.

Transition to IFRS (continued)

Reconciliation of consolidated statement of comprehensive income for the three months ended September 30, 2010:

					Effect of
		Previous			Transition			IFRS
(thousands of Canadian dollars)(unaudited)	Notes	GAAP			to IFRS			Reclassifications			IFRS

Petroleum and natural gas sales		$	72,722		$	-		$	-		$	72,722
Less: royalties	8		(10,272	)		-			(307	)		(10,579	)
Petroleum and natural gas revenue			62,450			-			(307	)		62,143

Operating expense	1c		(22,812	)		(644	)		-			(23,456	)
General and administrative expense	1c		(9,576	)		(128	)		-			(9,704	)
Depreciation expense	1,7		(58,122	)		24,618			1,044			(32,460	)
Gains on derivatives			14,301			-			-			14,301
Other expense	1a		-			(1,625	)		-			(1,625	)
Operating income (loss) before finance and taxes			(13,759	)		22,221			737			9,199

Finance expense	3, 4, 7		(6,612	)		(253	)		(1,044	)		(7,909	)
Income (loss) before taxes			(20,371	)		21,968			(307	)		1,290
Income tax recovery (expense)	5, 8		3,456			(5,713	)		307			(1,950	)
Net income (loss) and comprehensive income (loss)		$	(16,915	)	$	16,255		$	-		$	(660	)
Net income (loss) per share
Basic		$	(0.10	)							$	(0.00	)
Diluted		$	(0.10	)							$	(0.00	)

Reconciliation of consolidated statement of comprehensive income for the nine months ended September 30, 2010:

					Effect of
		Previous			Transition			IFRS
(thousands of Canadian dollars)(unaudited)	Notes	GAAP			to IFRS			Reclassifications			IFRS

Petroleum and natural gas sales		$	243,147		$	-		$	-		$	243,147
Less: royalties	8		(35,327	)		-			(966	)		(36,293	)
Petroleum and natural gas revenue			207,820			-			(966	)		206,854

Operating expense	1c		(70,088	)		(1,710	)		-			(71,798	)
General and administrative expense	1c		(29,398	)		(559	)		-			(29,957	)
Depreciation expense	1, 7		(169,018	)		73,468			3,465			(92,085	)
Gains on derivatives			54,870			-			-			54,870
Other income	1a		-			47,719			-			47,719
Operating income (loss) before finance and taxes			(5,814	)		118,918			2,499			115,603

Finance expense	3, 4, 7		(22,472	)		(640	)		(3,465	)		(26,577	)
Income (loss) before taxes			(28,286	)		118,278			(966	)		89,026
Income tax recovery (expense)	5, 8		2,247			(28,431	)		966			(25,218	)
Net income (loss) and comprehensive income (loss)		$	(26,039	)	$	89,847		$	-		$	63,808
Net income (loss) per share
Basic		$	(0.16	)							$	0.39
Diluted		$	(0.16	)							$	0.39

Advantage Oil & Gas Ltd. - 66

24.

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.

					Effect of
		Previous			Transition			IFRS
(thousands of Canadian dollars)(unaudited)	Notes	GAAP			to IFRS			Reclassifiications			IFRS

ASSETS
Current assets
Trade and other receivables		$	42,276		$	-		$	-		$	42,276
Prepaid expenses and deposits			6,488			-			-			6,488
Derivative asset			25,157			-			-			25,157
Total current assets			73,921			-			-			73,921

Non-current assets
Exploration and evaluation assets	2		-			-			8,262			8,262
Property, plant and equipment	1, 2, 3		1,768,650			123,374			(8,262	)		1,883,762
Total non-current assets			1,768,650			123,374			-			1,892,024

Total assets		$	1,842,571		$	123,374		$	-		$	1,965,945

LIABILITIES
Current liabilities
Trade and other accrued liabilities		$	112,457		$	-		$	-		$	112,457
Capital lease obligations			759			-			-			759
Convertible debentures	4		61,570			443			-			62,013
Derivative liability			2,367			-			-			2,367
Deferred income tax liability	5		5,876			-			(5,876	)		-
Total current liabilities			183,029			443			(5,876	)		177,596

Non-current liabilities
Derivative liability			177			-			-			177
Bank indebtedness			288,852			-			-			288,852
Convertible debentures			72,811			-			-			72,811
Decommissioning liability	3		58,281			113,849			-			172,130
Deferred income tax liability	5		29,399			4,956			5,876			40,231
Other liability			1,835			-			-			1,835
Total non-current liabilities			451,355			118,805			5,876			576,036

Total liabilities			634,384			119,248			-			753,632

SHAREHOLDERS' EQUITY
Share capital			2,199,491			-			-			2,199,491
Convertible debentures equity component	4		15,896			(7,548	)		-			8,348
Contributed surplus	4		17,754			(2,971	)		-			14,783
Deficit			(1,024,954	)		14,645			-			(1,010,309	)
Total shareholders' equity			1,208,187			4,126			-			1,212,313
Total liabilities and shareholders' equity		$	1,842,571		$	123,374		$	-		$	1,965,945

Advantage Oil & Gas Ltd. - 67

24.

Transition to IFRS (continued)

Reconciliation of consolidated statement of comprehensive income for the year ended December 31, 2010:

					Effect of
		Previous			Transition			IFRS
(thousands of Canadian dollars)(unaudited)	Notes	GAAP			to IFRS			Reclassifications			IFRS

Petroleum and natural gas sales		$	319,368		$	-		$	-		$	319,368
Less: royalties	8		(44,640	)		-			(1,314	)		(45,954	)
Petroleum and natural gas revenue			274,728			-			(1,314	)		273,414

Operating expense	1c		(93,875	)		(1,733	)		-			(95,608	)
General and administrative expense	1c		(37,578	)		(615	)		-			(38,193	)
Depreciation expense	1, 7		(215,780	)		86,695			4,493			(124,592	)
Impairment loss	1d		-			(17,500	)		-			(17,500	)
Exploration and evaluation expense	2		-			(752	)		-			(752	)
Gains on derivatives			50,514			-			-			50,514
Other income	1a		-			46,142			-			46,142
Operating income (loss) before finance and taxes			(21,991	)		112,237			3,179			93,425

Finance expense	3, 4, 7		(29,128	)		(767	)		(4,493	)		(34,388	)
Income (loss) before taxes			(51,119	)		111,470			(1,314	)		59,037
Income tax recovery (expense)	5, 8		6,911			(26,342	)		1,314			(18,117	)
Net income (loss) and comprehensive income (loss)		$	(44,208	)	$	85,128		$	-		$	40,920
Net income (loss) per share
Basic		$	(0.27	)							$	0.25
Diluted		$	(0.27	)							$	0.25

Property, Plant and Equipment

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.

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.

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.

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. - 68

24.

Transition to IFRS (continued)

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.

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.

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.

Deferred income tax liability:

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.

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.

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.

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.

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. - 69

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

bbls - barrels

bbls/d - barrels per day

boe - barrels of oil equivalent (6 mcf = 1 bbl)

boe/d - barrels of oil equivalent per day

mcf - thousand cubic feet

mcf/d - thousand cubic feet per day

mmcf - million cubic feet

mmcf/d - million cubic feet per day

bcf - billion cubic feet

tcf - trillion cubic feet

gj - gigajoules

NGLs - natural gas liquids

WTI - West Texas Intermediate

Corporate Office

700, 400 – 3 Avenue SW

Calgary, Alberta T2P 4H2

(403) 718-8000

Toll free: 1-866-393-0393

Email: ir@advantageog.com

Visit our website at www.advantageog.com

Toronto Stock Exchange Trading Symbols

Shares: AAV

7.75% Convertible Debentures: AAV.DBD

8.00% Convertible Debentures: AAV.DBG

5.00% Convertible Debentures: AAV.DBH

New York Stock Exchange Trading Symbol

Shares: AAV

Advantage Oil & Gas Ltd. - 70