Exhibit 99.1

MANAGEMENT’S DISCUSSION AND ANALYSIS

This management’s discussion and analysis (“MD&A”) of ARC Resources Ltd. (“ARC” or the “Company”) is management’s analysis of the financial performance and significant trends or external factors that may affect future performance.  It is dated November 2, 2011 and should be read in conjunction with the unaudited Condensed Consolidated Financial Statements as at and for the three and nine months ended September 30, 2011, the three and six months ended June 30, 2011, the three months ended March 31, 2011 and the MD&A and audited Consolidated Financial Statements for the year ended December 31, 2010 as well as ARC’s Annual Information Form that is filed on SEDAR at www.sedar.com.

This MD&A contains Non-GAAP measures and forward-looking statements.  Readers are cautioned that the MD&A should be read in conjunction with ARC’s disclosure under the headings “Non-GAAP Measures” and “Forward-Looking Information and Statements” included at the end of this MD&A.

ABOUT ARC RESOURCES LTD.

ARC is a dividend-paying Canadian exploration and production company with near-term growth prospects. ARC’s activities relate to the exploration, development and production of conventional oil and natural gas with an emphasis on the acquisition and development of properties with a large volume of hydrocarbons in place commonly referred to as “resource plays”.  Production from individual oil and natural gas wells naturally decline over time. In any one year, ARC approves a budget to drill new wells with the intent to first replace production declines and second to potentially increase production volumes. ARC was previously structured as a trust and converted to its present corporate structure on December 31, 2010.  ARC continues to operate as an oil and natural gas production company, hiring and developing staff with expertise specific to ARC’s oil and natural gas operations. As of the end of September 2011, ARC had approximately 520 employees with 300 professional, technical and support staff in the Calgary office and 220 individuals located across ARC’s operating areas in western Canada.

ARC is results-focused with a goal to provide superior, long-term returns to shareholders through risk-managed value creation.  ARC is disciplined in its approach to capital allocation, selecting projects that support its goal. ARC’s staff uses its expertise in the exploration for and development of oil and natural gas assets to unlock additional reserves that will lead to increased future production. The main activities that support this objective are:

1. Resource Plays - Geological evaluation, acquisition, development and, if economically viable, subsequent production from lands and producing properties with a large resource in place.  In general, these lands are amenable to drilling multi-stage fractured horizontal wells.

ARC’s most significant resource plays include the Montney natural gas and liquids development in northeast British Columbia, the Montney development at Ante Creek in northern Alberta and the Cardium formation at Pembina in central Alberta.  ARC’s 2011 budgeted capital expenditures are focused on the resource play development at Ante Creek and Pembina. Additionally, ARC owns land in the Swan Hills area which is an emerging resource play in which ARC is currently commencing evaluation activities.  Where applicable, enhanced oil recovery programs (“EOR programs”) are used to increase recovery of reserves. ARC has non-operated interests in the Weyburn and Midale units in Saskatchewan where operators have implemented CO2 injection programs to increase recoverable oil reserves.  Also, ARC has completed the injection component of a CO2 pilot program at Redwater and continues to evaluate the potential for a commercial EOR project in that area.

2. Conventional Oil & Natural Gas Production - ARC focuses on maximizing production while controlling operating costs on oil and natural gas wells located within its core producing areas in western Canada.  This may include the periodic acquisition of strategic producing and undeveloped properties to enhance current production or to provide potential future drilling locations and, if successful, additional production and reserves.  This may also include the rationalization of asset portfolios through dispositions.  Current oil production is predominantly light and medium quality.

Table 1 highlights ARC’s production volume and reserve profile for the last five years:

Table 1

	2011 YTD		2010		2009		2008		2007
Production (boe/d)		80,517		73,954		63,538		65,126		62,723
Proved plus probable reserves (mmboe)(1)(2)		n/a		487.4		379.0		321.7		286.4

(1) As determined by ARC’s independent reserve evaluator solely at year end.

(2) ARC has also disclosed contingent resources associated with interest in certain of our properties located in northeastern British Columbia in the company’s Annual Information Form as filed on SEDAR at www.sedar.com.

Total Return to Shareholders

ARC's business plan has resulted in significant operational success and contributed to a trailing five year annualized total return per share of 4.5 per cent (Table 2).

Table 2

Total Returns (1) ($ per share except for per cent)	Trailing One Year			Trailing Three Year			Trailing Five Year
Dividends per share		1.20			3.97			9.05
Capital appreciation (depreciation) per share		2.01			(0.54	)		(4.65	)
Total return per share		15.2	%		18.6	%		24.8	%
Annualized total return per share		15.2	%		5.8	%		4.5	%
S&P/TSX Exploration & Producers Index annualized total return		(16.5	)%		(5.9	)%		(1.5	)%

(1) Calculated as at September 30, 2011.

ARC provides returns to shareholders through both the potential for capital appreciation as production and reserves grow and through a monthly dividend payment to its shareholders which is currently $0.10 per share per month.  From its 1996 inception, ARC has paid out $4 billion to shareholders while financing a large percentage of its acquisitions by issuing additional shares. Going forward, ARC’s goal is to fund both its capital expenditures necessary to replace production declines and dividends, net of ARC’s Dividend Reinvestment and Optional Cash Payment Program (“DRIP”), from funds from operations.  ARC will finance growth activities through a combination of sources, including funds from operations, proceeds from property dispositions, debt issuance and equity issuance.  ARC chooses to maintain prudent debt levels and as such its net debt at September 30, 2011 was well within its objective of keeping debt in the range of one to 1.5 times annualized funds from operations and 20 per cent of total capitalization.

Per Share Metrics

ARC’s performance can be measured by its ability to grow both production and reserves per share. Table 3 details ARC’s normalized production, reserves and distributions per share, with and without dividend adjustments, for the first nine months of 2011 and over the past two years:

Table 3

Per Share	Q3 2011	YTD 2011		Full year 2010		Full year 2009
Normalized production, boe per share (1) (2)	0.31		0.29		0.30		0.27
Normalized reserves, boe per share (1) (3)	n/a		n/a		1.80		1.57
Dividends/distributions per unit	0.30		0.90		1.20		1.28
Normalized production, dividend adjusted, boe per share (4)	0.38		0.37		0.36		0.32
Normalized reserves, dividend adjusted, boe per share (4)	n/a		n/a		2.31		1.90

(1) “Normalized” indicates that all periods as presented have been adjusted to reflect a net debt to capitalization of 15 per cent. It is assumed that additional shares were issued (or repurchased) at a period end price for the reserves per share calculation and at an annual average price for the production per share calculation in order to achieve a net debt balance of 15 per cent of total capitalization each year. The normalized amounts are presented to enable comparability of per share values.

(2) Production per share represents daily average production (boe) per thousand shares and is calculated based on daily average production divided by the normalized diluted common shares.

(3) Reserves per share is calculated based on proved plus probable reserves (boe), as determined by ARC’s independent reserve evaluator solely at year-end, divided by period end shares outstanding.

(4) The dividend adjustment assumes that historic dividends paid since January 1, 2009 have been reinvested by ARC, resulting in a reduction of the number of shares outstanding and, in turn, higher normalized production per share and normalized reserves per share.

ECONOMIC ENVIRONMENT

WTI averaged US$95.52 per barrel during the first nine months of 2011, a 23 per cent increase over the 2010 average price of US$77.65 per barrel.  During the first nine months of 2011, oil supply growth has been slow in responding to resurging demand after the 2008/2009 recession in advanced economies and continued demand growth in emerging economies, while civil uprisings in the Middle East and North Africa resulted in supply disruptions and risk premiums in crude prices.  However, during the third quarter of 2011, oil prices decreased from the levels experienced during the first half of the year due to concerns that the economic recovery in advanced economies is slowing, the sovereign debt issues in Europe and the downgrading of debt in the United States.

In North American markets, natural gas production has continued at record levels due to improving drilling techniques in tight shale and silt formations.  This has resulted in an average NYMEX price of US$4.23/mmbtu for the first nine months of 2011 and an average AECO monthly price of $3.74/mcf for the same period.

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Improved oil prices and increased activity levels within the local economy has also led to a general escalation in costs to acquire materials and secure services that are necessary to execute ARC’s capital program.  These factors have also led to a tightening of the labor market in western Canada that has resulted in increased labor costs.

2011 Annual Guidance and Financial Highlights

Table 4 is a summary of ARC’s 2011 guidance and a review of 2011 YTD actual results:

Table 4

	2011 Guidance		2011 Actual YTD		% Variance
Production (boe/d)		82,000 - 83,000		80,517		(2	)
Expenses ($/boe):
Operating		9.40 - 9.70		9.81		(1	)
Transportation		1.10 - 1.20		1.20		-
General and administrative(1)		2.50 - 2.70		2.80		(4	)
Interest		1.25 - 1.40		1.35		-
Capital expenditures ($ millions)		730		531		-
Weighted average and diluted shares (millions) (2)		286		286		-

(1) The 2011 annual guidance for general and administrative cost per boe is based on a range of $1.90 - $2.05 prior to the recognition of any expense associated with ARC’s Long-term incentive plan, $0.60-$0.65 per boe associated with cash payments under ARC’s Long-term incentive plan and nil per boe associated with accrued compensation under ARC’s Long- term incentive plan.  Actual per boe costs for each of these components for the nine months ended September 30, 2011 were $1.91 per boe, $0.92 per boe offset by a recovery of $0.03 per boe, respectively.

(2) Based on weighted average shares plus the dilutive impact of shares outstanding during the period

ARC’s 2011 production guidance assumes staged growth throughout the year and accordingly is not necessarily indicative of quarterly expectations.  Actual production volumes for the nine months ended September 30, 2011 are within the lower end of the annual guidance range reflecting increased production volumes throughout 2011 from 73,880 boe per day during the first quarter to an average of 85,178 boe per day during the third quarter.  Year-to-date operating costs exceed guidance slightly due primarily to increased electricity costs, while general and administrative costs exceed guidance slightly due to higher than expected payments on ARC’s Long-term incentive program in September of 2011.

ARC believes that its 2011 production volumes will average between 82,000-83,000 boe per day, a change from the original guidance of 84,000-87,000 and a tighter range of guidance compared to the estimated range of 80,000-85,000 boe per day issued in the first quarter of 2011.  December 31, 2011 exit production is expected to be greater than 90,000 boe per day.  ARC received approval from its Board of Directors to increase its 2011 capital expenditure budget to $730 million from the previous level of $690 million.  The $40 million increase in 2011 capital expenditures is attributed to approximately $27 million of previously unbudgeted crown land purchases and the acceleration of certain oil and liquids projects that were originally planned for 2012.

The 2011 guidance provides shareholders with information on management’s expectations for results of operations.  Readers are cautioned that the 2011 guidance may not be appropriate for other purposes.

2011 THIRD QUARTER FINANCIAL AND OPERATIONAL RESULTS

Financial Highlights

Table 5

	Three months ended September 30						Nine months ended September 30
(Cdn$ millions, except per share and volume data)	2011		2010		% Change		2011		2010		% Change
Funds from operations (1)		213.5		167.7		27		617.6		486.5		27
Funds from operations per share (1) (2)		0.74		0.63		17		2.15		1.89		14
Net income (3)		120.8		90.3		34		336.0		299.0		12
Dividends per share (2)		0.30		0.30		-		0.90		0.90		-
Average daily production (boe/d) (4)		85,178		77,483		10		80,517		70,337		14

(1) This is a non-GAAP measure which may not be comparable with similar non-GAAP measures used by other entities.  Refer to the section entitled “Non-GAAP Measures” contained within this MD&A.

(2) Per share amounts (with the exception of dividends per share which are based on the number of shares outstanding at each dividend record date) are based on weighted average shares.

(3) Amount as determined under International Financial Reporting Standards, restated for the comparative period.

(4) Reported production amount is based on company interest before royalty burdens. Where applicable in this MD&A natural gas has been converted to barrels of oil equivalent (“boe”) based on 6 mcf:1 bbl. The boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of boe in isolation may be misleading.

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International Financial Reporting Standards

Beginning January 1, 2011 all Canadian publicly accountable enterprises are required to prepare their financial statements using International Financial Reporting Standards (“IFRS”).  Accordingly, ARC has prepared its unaudited Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2011 under IFRS and has restated its unaudited Consolidated Financial Statements for the three and nine months ended September 30, 2010 to comply with IFRS.  The financial information presented in this MD&A is derived directly from ARC’s financial statements and as such certain comparative information may differ from what was originally prepared by ARC using previous Canadian generally accepted accounting principles.  For further information on ARC’s transition to IFRS and a reconciliation of its affected financial information for the three and nine months ended September 30, 2010, please refer to Note 16, “Explanation of Transition to International Financial Reporting Standards” in the unaudited Condensed Consolidated Financial Statements as at and for the three and nine months ended September 30, 2011 and 2010 filed as separate documents on SEDAR at www.sedar.com.

Funds from Operations

Beginning in 2011, ARC is reporting funds from operations in total and on a per share basis.  Funds from operations is not a recognized performance measure under Canadian generally accepted accounting principles (“GAAP”) and does not have a standardized meaning prescribed by GAAP.  The term “funds from operations” is defined as net income excluding the impact of non-cash depletion, depreciation and amortization, accretion of asset retirement obligations, deferred tax expense (recovery), loss on revaluation of exchangeable shares, unrealized gains and losses on risk management contracts, unrealized gains and losses on short-term investments, non-cash lease inducement, stock-option expense, exploration and evaluation expense, unrealized gains and losses on foreign exchange and gains on disposal of petroleum and natural gas properties and is further adjusted to include the portion of unrealized gains and losses on risk management contracts that relate to January through September 2011 production.  ARC considers funds from operations to be a key measure of operating performance as it demonstrates ARC’s ability to generate the necessary funds for future growth through capital investment and to repay debt.  Management believes that such a measure provides a better assessment of ARC’s operations on a continuing basis by eliminating certain non-cash charges and charges that are nonrecurring, while respecting that certain risk management contracts that are settled on an annual basis are intended to protect prices on product sales occurring throughout the year.  From a business perspective, the most directly comparable measure of funds from operations calculated in accordance with GAAP is net income.  See the section entitled “Non-GAAP Measures” contained within this MD&A.

Table 6 is a reconciliation of ARC’s funds from operations to net income.

Table 6

	Three months ended September 30						Nine months ended September 30
($ millions)	2011			2010			2011			2010
Net income		120.8			90.3			336.0			299.0
Adjusted for the following non-cash items:
Depletion, depreciation and amortization		158.9			100.8			331.1			270.8
Accretion of asset retirement obligation		3.3			3.1			10.1			9.2
Deferred tax expense		46.4			0.9			114.4			20.3
Unrealized gain on risk management contracts		(138.3	)		(23.8	)		(63.7	)		(114.1	)
Foreign exchange loss (gain) on revaluation of debt		31.3			(13.4	)		19.1			(11.9	)
Gain on disposal of petroleum and natural gas properties		(4.8	)		-			(92.7	)		-
Other		0.7			9.8			1.4			13.2
Unrealized losses on risk management contracts related to January through September 2011 production(1)		(4.8	)		-			(38.1	)		-
Funds from operations		213.5			167.7			617.6			486.5

(1) ARC has entered into certain commodity price risk management contracts that pertain to production periods spanning the entire calendar year but that are settled at the end of the year on an annual average benchmark commodity price.  The portion of losses associated on these contracts that relates to production periods for the three and nine months ended September 30, 2011 have been applied to reduce funds from operations in order to more appropriately reflect the funds from operations generated during the period after any effect of contracts used for economic hedging.

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Funds from operations increased by 27 per cent in the third quarter of 2011 to $213.5 million from $167.7 million generated in the third quarter of 2010.  The increase was primarily attributed to a 10 per cent increase in production volumes coupled with a 21 per cent increase in realized oil pricing as well as a $15.1 million increase in realized hedging gains.  The increases were offset by $4.8 million for unrealized losses on risk management contracts that are attributable to production in the third quarter of 2011 (nil in 2010) and a 20 per cent increase in operating costs.

For the first nine months of 2011, funds from operations increased by $131.1 million as compared to the same period in 2010.  The increase reflects the 14 per cent increase in year-to-date production volumes, a 21 per cent increase in oil pricing and an increase in realized hedging gains of $46.3 million.  This is offset by a nine per cent decrease in natural gas pricing, a 13 per cent increase in operating costs and a reduction of $38.1 million for the portion of unrealized losses on risk management contracts that are attributable to production in the first nine months of 2011 (nil in 2010).

Details of the change in funds from operations from the three and nine months ended September 30, 2010 to the three and nine months ended September 30, 2011 are included in Table 7 below.

Table 7

	Three months ended  September 30						Nine months ended September 30
	$ millions			$/Share			$ millions			$/Share
Funds from Operations - 2010(1)		167.7			0.63			486.5			1.89
Volume variance
Crude oil and liquids		(6.4	)		(0.02	)		1.6			0.01
Natural gas		18.4			0.07			72.7			0.28
Price variance
Crude oil and liquids		43.5			0.16			125.0			0.48
Natural gas		2.7			0.01			(32.3	)		(0.13	)
Realized gains on risk management contracts		15.1			0.06			46.3			0.18
Unrealized losses on risk management contracts related to January through September 2011 production(2)		(4.8	)		(0.02	)		(38.1	)		(0.15	)
Royalties		(7.7	)		(0.03	)		(9.2	)		(0.04	)
Expenses:
Transportation		(2.1	)		(0.01	)		(5.1	)		(0.02	)
Operating		(13.0	)		(0.05	)		(24.0	)		(0.09	)
General and administrative		(2.8	)		(0.01	)		(8.1	)		(0.03	)
Interest		3.0			0.01			2.3			0.01
Realized foreign exchange gain		(0.1	)		-			-			-
Diluted shares		-			(0.06	)		-			(0.24	)
Funds from Operations - 2011(1)		213.5			0.74			617.6			2.15

(1) This is a non-GAAP measure which may not be comparable with similar non-GAAP measures used by other entities.  Refer to the section entitled “Non-GAAP Measures” contained within this MD&A.

(2) ARC has entered into certain commodity price risk management contracts that pertain to production periods spanning the entire calendar year but that are settled at the end of the year on an annual average benchmark commodity price.  The portion of losses associated on these contracts that relates to production periods for the three and nine months ended September 30, 2011 have been applied to reduce funds from operations in order to more appropriately reflect the funds from operations generated during the period after any effect of contracts used for economic hedging.

2011 Funds from Operations Sensitivity

Table 8 illustrates sensitivities of pre-hedged operating items to operational and business environment changes and the resulting impact on funds from operations per share:

Table 8

				Impact on Annual Funds from Operations (5)
Business Environment (1)	Assumption			Change			$/Share
Oil price (US$ WTI/bbl) (2)(3)		90.00			1.00			0.03
Natural gas price (Cdn$ AECO/mcf) (2)(3)		3.25			0.10			0.04
Cdn$/US$ exchange rate (2)(3)(4)		1.00			0.01			0.03
Interest rate on debt (2)		5.5	%		1.0	%		0.02
Operational
Liquids production volume (bbl/d)		33,000			1.0	%		0.02
Gas production volumes (mmcf/d)		310			1.0	%		0.01
Operating expenses ($ per boe)		9.55			1.0	%		0.01
General and administrative expenses ($ per boe)		2.60			10.0	%		0.03

(1) Calculations are performed independently and may not be indicative of actual results that would occur when multiple variables change at the same time.

(2) Prices and rates are indicative of published forward prices and rates at the time of this MD&A.  The calculated impact on funds from operations would only be applicable within a limited range of these amounts.

(3) Analysis does not include the effect of hedging contracts.

(4) Includes impact of foreign exchange on crude oil prices that are presented in U.S. dollars.  This amount does not include a foreign exchange impact relating to natural gas prices as it is presented in Canadian dollars in this sensitivity.

(5) This is a non-GAAP measure which may not be comparable with similar non-GAAP measures used by other entities.  Refer to the section entitled “Non-GAAP Measures” contained within this MD&A.

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Net Income

Net income was $120.8 million ($0.42 per share) during the three months ended September 30, 2011 as compared to $90.3 million ($0.34 per share) for the same period in the prior year, an increase of 34 per cent.  During the third quarter of 2011, net income increased by $30.5 million ($0.08 per share), primarily as a result of increased revenue net of royalties of $50.5 million and increased (primarily unrealized) gains on risk management contracts of $129.6 million.  These increases were partially offset by increased deferred tax expense of $45.5 million, increased foreign exchange losses associated with the revaluation of ARC’s US dollar denominated debt of $44.8 million and increased depletion, depreciation and amortization and impairment (recovery) charges of $58.1 million.  This increase is primarily due to an impairment charge of $45.1 million that was recorded at September 30, 2011.  No such charges were recorded in the comparative period.

For the nine months ended September 30, 2011, net income was $336 million ($1.17 per share) as compared to $299 million ($1.18 per share) resulting in a year-over-year increase of $37 million (12 per cent).  Revenue after royalties increased by $157.8 million for the first nine months of 2011 as compared to the first nine months of 2010 and ARC recognized an $92.7 million gain on disposal of certain non-core properties during the first nine months of 2011 (nil in 2010). Offsetting these increases were an increase in depletion, depreciation and amortization and impairment (recovery) charges of $60.3 million and an increase in deferred tax expense of $94.1 million as well as increased operating expenses and foreign exchange losses.

Production

Production volumes averaged 85,178 boe per day in third quarter of 2011, a 10 per cent increase compared to 77,483 boe per day in the same period of 2010.  Similarly, during the first nine months of 2011, production volumes averaged 80,517 boe per day as compared to 70,337 boe per day for the same period in the prior year, a 14 per cent increase. The increase in production volumes is attributed to additional natural gas processing capacity from the Dawson Phase 1 and 2 gas plants and additional production volumes resulting from the acquisition of Storm Exploration Inc. in the third quarter of 2010. These production increases were partially offset by downtime associated with construction and tie-in activities at the Dawson gas plant and the disposition of certain non-core properties during the first quarter of 2011 as well as production disruptions during the second quarter of 2011 associated with flooding, forest fires and pipeline disruption.

Table 9

	Three months ended September 30							Nine months ended September 30
Production	2011		2010		% Change			2011		2010		% Change
Light and medium crude oil (bbl/d)		25,163		25,994		(3	)		25,832		26,367		(2	)
Heavy oil (bbl/d)		861		965		(11	)		884		948		(7	)
Condensate (bbl/d)		2,009		1,689		19			1,996		1,422		40
Natural gas (mmcf/d)		327.4		275.0		19			295.5		234.9		26
Natural gas liquids  (bbl/d)		2,584		3,001		(14	)		2,555		2,449		4
Total production (boe/d) (1)		85,178		77,483		10			80,517		70,337		14
% Natural gas production		64		59		8			61		56		9
% Crude oil and liquids production		36		41		(12	)		39		44		(11	)

(1) Reported production for a period may include minor adjustments from previous production periods.

ARC’s crude oil production consists predominantly of light and medium crude oil while heavy oil accounts for less than four per cent of the total. During the third quarter of 2011, light and medium crude oil production decreased three per cent from the third quarter of the prior year and has remained flat from the second quarter of 2011.  During the second quarter of 2011, oil production was negatively affected by flooding in southeast Saskatchewan and Manitoba and to a lesser extent, Northern Alberta.  This also had the effect of delaying the execution of capital projects in these areas resulting in delayed third quarter production growth.  Additionally, a third-party pipeline shut-in that occurred during the second quarter of 2011 continued throughout the third quarter resulting in a shut-in of approximately 450 boe per day. This loss has been offset by increased production due to drilling successes predominately at Pembina.

Year-to-date, ARC’s light and medium crude oil production is relatively unchanged from the same period in 2010 as production increases resulting from the success of ARC’s capital programs will be more fully reflected in the fourth quarter and into 2012 as new wells are tied into existing infrastructure.  To date, new wells drilled have replaced the production lost from natural decline and divestitures on non-core assets.

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Natural gas production was 327.4 mmcf per day in the third quarter of 2011, an increase of 19 per cent from the 275 mmcf per day produced in the third quarter of 2010.  ARC’s natural gas production increased to record levels due to a full quarter of production from the additional capacity from the Dawson Phase 1 and Phase 2 gas plants as well as additional production volumes resulting from the acquisition of Storm Exploration Inc. in the third quarter of 2010.

During the first nine months of 2011, ARC produced 295.5 mmcf per day of natural gas, a 26 per cent increase over the same period in the prior year.  The year-to-date increase in production is attributed to the same factors noted above but is offset by some production losses during the first quarter of 2011 associated with downtime to facilitate new construction of the second phase at Dawson in addition to the reconfiguration of electrical and computer systems of the first phase plus the disposition of certain non-core assets producing approximately 12.2 mmcf per day in January of 2011.

ARC expects that its 2011 average natural gas production will be within the range of 300-315 mmcf per day due to the increase in natural gas production at Dawson with the Phase I and II gas plants running at full capacity of 120 mmcf per day coupled with incremental production gains expected to result from new wells drilled and tied in under ARC’s 2011 capital program.

During the third quarter of 2011, ARC drilled 49 gross wells (46 net wells) on operated properties consisting of 42 gross (39 net) oil wells and seven gross (seven net) natural gas wells with a 100 per cent success rate.  A total of 22 wells were brought on production during the third quarter of 2011, with an ending inventory of 27 wells awaiting completion and tie-in in future periods. Total wells drilled in the first nine months of 2011 were 87 gross (79 net) operated oil wells and 29 gross (29 net) operated natural gas wells with a 100 per cent success rate.

ARC expects that it will drill a total of approximately 166 gross (156 net) wells on operated properties and participate in an additional 83 gross wells (10 net) to be drilled on non-operated properties in 2011.

Table 10 summarizes ARC’s production by core area for the third quarter of 2011 and 2010:

Table 10

	Three Months Ended September 30, 2011
Production	Total		Oil		Condensate		Gas		NGL
Core Area (1)	(boe/d)		(bbl/d)		(bbl/d)		(mmcf/d)		(bbl/d)
NE BC & NW AB		40,196		614		1,198		224.7		937
Northern AB		10,746		4,515		329		32.0		574
Pembina		10,206		6,247		341		18.0		622
Redwater		4,290		3,944		-		1.2		145
South AB & SW SK(2)		10,377		1,558		125		50.8		226
SE SK & MB		9,363		9,146		16		0.7		80
Total		85,178		26,024		2,009		327.4		2,584

	Three Months Ended September 30, 2010
Production	Total		Oil		Condensate		Gas		NGL
Core Area (1)	(boe/d)		(bbl/d)		(bbl/d)		(mmcf/d)		(bbl/d)
NE BC & NW AB		27,498		711		700		151.2		889
Northern AB		11,652		4,484		402		36.9		611
Pembina		9,040		5,572		255		16.0		552
Redwater		4,177		3,830		18		1.2		127
South AB & SW SK(2)		14,821		2,457		279		68.2		721
SE SK & MB		10,295		9,905		35		1.5		101
Total		77,483		26,959		1,689		275.0		3,001

(1) Provincial and directional references: AB is Alberta, BC is British Columbia, SK is Saskatchewan, MB is Manitoba, NE is northeast, NW is northwest, SE is southeast and SW is southwest.

(2) In prior years, the volumes produced in central Alberta were reported separately from SE AB and SW SK. With the disposition of the majority of the properties within central Alberta in the first quarter of 2011, production from these areas has been consolidated.

Page 7

Table 10a summarizes ARC’s production by core area for the first nine months of 2011 and 2010:

Table 10a

	Nine Months Ended September 30, 2011
Production	Total		Oil		Condensate		Gas		NGL
Core Area (1)	(boe/d)		(bbl/d)		(bbl/d)		(mmcf/d)		(bbl/d)
NE BC & NW AB		34,386		663		1,158		189.9		925
Northern AB		11,227		4,464		374		34.9		566
Pembina		10,306		6,513		320		17.4		572
Redwater		4,134		3,834		-		1.1		119
South AB & SW SK(2)		10,625		1,637		128		51.3		303
SE SK & MB		9,839		9,605		16		0.9		70
Total		80,517		26,716		1,996		295.5		2,555

	Nine Months Ended September 30, 2010
Production	Total		Oil		Condensate		Gas		NGL
Core Area (1)	(boe/d)		(bbl/d)		(bbl/d)		(mmcf/d)		(bbl/d)
NE BC & NW AB		20,233		681		523		111.3		490
Northern AB		11,187		4,555		342		34.3		571
Pembina		8,982		5,527		230		16.7		441
Redwater		4,173		3,822		17		1.2		131
South AB & SW SK(2)		15,059		2,394		283		69.9		731
SE SK & MB		10,703		10,336		27		1.5		85
Total		70,337		27,315		1,422		234.9		2,449

(1) Provincial and directional references: AB is Alberta, BC is British Columbia, SK is Saskatchewan, MB is Manitoba, NE is northeast, NW is northwest, SE is southeast and SW is southwest.

(2) In prior years, the volumes produced in central Alberta were reported separately from SE AB and SW SK.  With the disposition of the majority of the properties within central Alberta in the first quarter of 2011, production from these areas has been consolidated.

Sales of crude oil, natural gas and natural gas liquids

Sales of crude oil, natural gas and natural gas liquids were $351.8 million in the third quarter of 2011, an increase of $58.2 million (20 per cent) over third quarter 2010 sales of $293.6 million, reflecting increased production volumes contributing an additional $29.2 million and increased pricing contributing $29 million.

Year to date, sales of crude oil, natural gas and natural gas liquids were $1,051.4 million, an increase of $167 million (19 per cent) over sales of $884.4 million for the same period in the prior year, reflecting increased production volumes that contributed to additional sales of $128 million and increased pricing that contributed an additional $39 million to sales.

A breakdown of sales by product is outlined in Table 11:

Table 11

Sales by product ($ millions)	Three months ended September 30						Nine months ended September 30
	2011		2010		% Change		2011		2010		% Change
Oil		205.8		176.1		17		644.0		545.0		18
Condensate		17.2		11.4		51		51.4		29.8		72
Natural gas		116.9		95.9		22		321.8		281.4		14
NGL		11.4		9.8		16		32.5		26.7		22
Total sales of crude oil, natural gas and natural gas liquids		351.3		293.2		20		1,049.7		882.9		19
Other		0.5		0.4		25		1.7		1.5		13
Total sales		351.8		293.6		20		1,051.4		884.4		19

Page 8

Commodity Prices Prior to Hedging

Table 12

	Three months ended September 30							Nine months ended September 30
	2011		2010		% Change			2011		2010		% Change
Average Benchmark Prices
AECO natural gas ($/mcf) (1)		3.72		3.72		-			3.74		4.30		(13	)
WTI oil (US$/bbl) (2)		89.81		76.21		18			95.52		77.65		23
Cdn$ / US$ exchange rate		0.98		1.04		(6	)		0.98		1.04		(6	)
WTI oil (Cdn$/bbl)		87.91		79.19		11			93.31		80.39		16
ARC Realized Prices Prior to Hedging
Oil ($/bbl)		85.97		71.07		21			88.31		73.10		21
Condensate ($/bbl)		92.85		73.51		26			94.17		76.88		22
Natural gas ($/mcf)		3.88		3.79		2			3.99		4.39		(9	)
NGL ($/bbl)		47.90		35.41		35			46.56		39.86		17
Total commodity price before hedging ($/boe)		44.83		41.14		9			47.75		45.98		4
Other ($/boe)		0.06		0.05		20			0.08		0.08		-
Total sales before hedging($/boe)		44.89		41.19		9			47.83		46.06		4

(1) Represents the AECO Monthly (7a) index.

(2) WTI represents posting price of West Texas Intermediate oil.

Prior to hedging activities, ARC’s weighted average commodity price was $44.83 per boe in the third quarter of 2011, an increase of nine per cent as compared to $41.14 per boe in the third quarter of 2010.  This increase reflects a 21 per cent increase in ARC’s realized price of crude oil while ARC’s realized natural gas price increased two per cent.  During the third quarter of 2011 ARC’s production was composed of 36 per cent crude oil and liquids and 64 per cent of natural gas, resulting in crude oil and liquids contributing 67 per cent of total sales and natural gas contributing 33 per cent as compared to the third quarter of 2010, where ARC’s production was composed of 41 per cent crude oil and liquids and 59 per cent natural gas and still resulted in crude oil and liquids contributing 67 per cent of total sales value and natural gas contributing 33 per cent.

Year to date, ARC’s weighted average commodity price before the impact of any hedging activities was $47.75 per boe, a four per cent increase over the first nine months of 2010.  This moderate increase reflects a 21 per cent increase in the average realized price of oil offset by a nine per cent decrease in the year-over-year average price of natural gas combined with a shift to increased natural gas production as a percentage of total production volumes.

Oil prices remained strong through the third quarter of 2011, with WTI increasing 18 per cent from the third quarter of 2010 compared to the third quarter of 2011.  The balance between supply and demand remains tight as world oil demand continues to grow and geopolitical factors continue to cause general concern over world supply.  ARC’s realized oil prices slightly exceeded the gain in WTI due to narrowed differentials relative to the same period in 2010.  The narrowed differentials reflect a premium to WTI that has been placed on Canadian light sweet crude oil throughout 2011 in response to local supply and demand factors.  The realized price for ARC’s oil, before hedging, was $85.97 per barrel, a 21 per cent increase over the third quarter 2010 realized price of $71.07 per barrel.

ARC’s average realized oil price for the first nine months of 2011 of $88.31 per barrel is a 21 per cent increase over the same period of the prior year and reflects the 23 per cent increase in WTI with modest change to the to the value of the Canadian dollar relative to the US dollar.

AECO monthly posted natural gas prices, the benchmark from which ARC derives the majority of its gas sales, were unchanged from the third quarter of 2010 to the third quarter of 2011 at $3.72 per mcf. ARC’s realized natural gas price, before hedging, increased by two per cent to $3.88 per mcf compared to $3.79 per mcf in the third quarter of 2010. Despite sustained cold weather in North America, increasing demand during the 2010/2011 heating season, gas prices continue to be depressed due to record production levels in the US with little recovery expected in the fourth quarter of 2011.  ARC’s realized gas price is based on its natural gas sales portfolio comprising sales priced at the AECO monthly index, the AECO daily spot market, eastern and midwest United States markets and a portion to aggregators.

During the first nine months of 2011 ARC’s average realized natural gas price of $3.99 per mcf decreased by nine per cent over the same period of the prior year and reflects the 13 per cent decrease in the average AECO monthly posting for the first nine months of 2011 as compared to the first nine months of 2010.

Page 9

Risk Management and Hedging Activities

ARC maintains a risk management program to reduce the volatility of revenues, increase the certainty of funds from operations, and to protect acquisition and development economics.  ARC limits the amount of total forecast production that can be hedged to a maximum of 55 per cent over the next two years with the remaining 45 per cent of production being sold at market prices.  In addition, ARC’s hedging policy allows, with approval of the Board, further hedging on volumes associated with new production arising from specific capital projects and acquisitions.

Given the significant contribution that ARC’s production of crude oil and natural gas liquids currently adds to its total sales value, ARC’s management recognizes a significant risk associated with an unanticipated reduction in crude oil pricing affecting ARC’s total funds from operations.  Accordingly, it has hedged approximately 60 and 50 per cent of its total gross crude oil and natural gas liquids production for the balance of 2011 and throughout 2012, respectively, through the use of a variety of crude oil risk management contracts.

Gains and losses on risk management contracts comprise both realized gains and losses representing the portion of risk management contracts that have settled during the period and unrealized gains or losses that represent the change in the mark-to-market position of those contracts throughout the period.  The majority of ARC’s risk management contracts do not meet the accounting requirements to be considered an effective hedge, though ARC considers all risk management contracts to be effective economic hedges of its physical commodity sales transactions. Accordingly, gains and losses on such contracts are shown as a separate line item in the Condensed Consolidated Statements of Income.

During the third quarter of 2011, ARC recorded a gain of $178.7 million on its risk management contracts, comprising a realized gain of $40.4 million and an unrealized gain of $138.3 million. The realized gains are mainly attributed to positive cash settlements related to natural gas swap and natural gas basis swap contracts totaling $26.8 million.  Additionally, ARC realized gains of $10.4 million during the third quarter on crude oil contracts, almost entirely related to the unwinding of positions previously contracted for volumes in 2012 resulting in ARC realizing a $10.7 million gain in the third quarter.  The unrealized gain is primarily attributed to various crude oil contracts having an average ceiling price of approximately US$90 per barrel that had previously been marked-to-market at an average forward price of approximately US$99 per barrel at June 30, 2011.  At September 30, 2011, the average WTI forward price for the relevant time period was reduced to approximately US$81 per barrel, resulting in changing what had been an estimated future loss into an estimated future gain.  Offsetting the unrealized gain recorded during the third quarter of 2011 is a loss of approximately $4.8 million related to the estimated portion of unrealized losses on annually settled crude oil contracts that relate to the third quarter of 2011.  Unlike the majority of ARC’s risk management contracts that are settled monthly, these annually settled contracts which relate to production throughout 2011 will be cash-settled in their entirety in January 2012 against the 2011 calendar year average WTI benchmark price.

Year to date, ARC has recognized a gain on its risk management contracts of $155.4 million comprising a realized gain of $91.7 million and an unrealized gain of $63.7 million.  The realized gains are mainly attributed to positive cash settlements related to natural gas swap and natural gas basis swap contracts totaling $91.8 million.  The unrealized gains are primarily attributed to various crude oil contracts having an average ceiling price of approximately US$90 per barrel that had an average forward price of approximately US$81 per barrel at September 30, 2011.  Offsetting within the unrealized gain recorded during the first nine months of 2011 is an unrealized loss of approximately $38.1 million related to the expected portion of losses on annually settled crude oil contracts that relate to production during the first nine months of 2011.

Table 13 summarizes the total gain on risk management contracts for the third quarter of 2011 compared to the same period in 2010:

Table 13

Risk Management Contracts ($ millions)	Crude Oil & Liquids			Natural Gas			Foreign Currency		Power		Interest		Q3 2011 Total			Q3 2010 Total
Realized gain on contracts (1)		10.4			26.8			0.9		2.3		-		40.4			25.3
Unrealized gain (loss) on contracts related to future production periods (2)		145.2			(5.0	)		2.8		0.1		-		143.1			23.8
Unrealized loss on contracts related January through September 2011 production(3)		(4.8	)		-			-		-		-		(4.8	)		-
Gain on risk management contracts		150.8			21.8			3.7		2.4		-		178.7			49.1

(1) Realized cash gains and losses represent actual cash settlements or receipts under the respective contracts.

(2) The unrealized gain (loss) on contracts represents the change in fair value of the contracts during the period.

(3) The unrealized loss on contracts related to prior production periods relates to the estimated gains and losses attributable to the three months ended September 30 on contracts that relate to a calendar year of production and are settled on an annual basis.

Page 10

Table 13a summarizes the total (loss) gain on risk management contracts for the first nine months of 2011 compared to the same period in 2010:

Table 13a

Risk Management Contracts ($ millions)	Crude Oil & Liquids			Natural Gas			Foreign Currency		Power		Interest		YTD 2011 Total			YTD 2010 Total
Realized gain on contracts (1)		10.6			74.9			1.0		4.3		0.9		91.7			45.4
Unrealized gain (loss) on contracts related to future production periods (2)		130.8			(37.5	)		1.5		6.9		0.1		101.8			114.1
Unrealized loss on contracts related to January through September 2011 production(3)		(38.1	)		-			-		-		-		(38.1	)		-
Gain on risk management contracts		103.3			37.4			2.5		11.2		1.0		155.4			159.5

(1) Realized cash gains and losses represent actual cash settlements or receipts under the respective contracts.

(2) The unrealized gain (loss) on contracts represents the change in fair value of the contracts during the period.

(3) The unrealized loss on contracts related to prior production periods relates to the estimated gains and losses attributable to the nine months ended September 30 on contracts that relate to a calendar year of production but are settled on an annual basis.

Looking forward, ARC has protected its selling price on natural gas by hedging 169 mmcf per day at an average floor price of $5.45 per mcf for the remainder of 2011 and approximately 77 mmcf per day at an average floor price of $4.65 per mcf for 2012.  Additionally, ARC has protected 20,000 barrels of oil per day for 2011 at a floor price of US$83.91 per barrel, has protected the price of 16,000 barrels of oil per day for 2012 and 2,000 barrels of oil per day for 2013 at a floor price of US$90 for each year.  Of the total production volumes hedged, contracts on approximately 43 mmcf per day of natural gas have been executed in respect of volumes associated with specified capital projects and a further 57 mmcf per day have been executed in the form of puts which have the effect of guaranteeing a minimum sales price to ARC while keeping these volumes exposed to any potential commodity price upside.

The following table is a summary of ARC’s risk management contracts for crude oil and natural gas as at September 30, 2011.

Table 14

Summary of Hedge Positions(1) As at September 30, 2011
	October - December 2011		2012		2013
Crude Oil (2)	US$/bbl	bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day
Bought Call	-	-	115.00	9,000	-	-
Sold Call	88.91	20,000	90.00	16,000	110.00	2,000
Bought Put	83.91	20,000	90.00	16,000	90.00	2,000
Sold Put	60.43	12,000	63.93	14,000	-	-
Natural Gas (3)	C$/mcf	mcf/day	C$/mcf	mcf/day	C$/mcf	mcf/day
Sold Call	5.64	149,749	4.65	76,680	-	-
Bought Put	5.45	168,911	4.65	76,680	-	-

(1) The prices and volumes noted above represent averages for several contracts and the average price for the portfolio of options listed above does not have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes.

(2) For 2011 and 2012, all put positions settle against the monthly average WTI price, providing protection against monthly volatility.  As disclosed in Note 11 of the Condensed Consolidated Financial Statements, calls have been sold against either the monthly average or the annual average WTI price.  In the case of settlements, ARC will only have a negative settlement if prices average above the strike price for an entire year providing ARC with greater potential upside price participation for individual months.  Volumes are based on a full year.  Refer to Note 11 of the Condensed Consolidated Financial Statements for a complete list of ARC’s annual settled calls.

(3) The natural gas price shown translates all NYMEX positions to an AECO equivalent price respecting offsetting basis positions and the period end foreign exchange rate.  The equivalent NYMEX price hedged would approximate a floor of US$5.73 per mmbtu and a ceiling of US$5.92 per mmbtu for 2011.  ARC has a fixed price of US$5.00 per mmbtu for 2012.

Page 11

To accurately analyze ARC’s hedge position, contracts need to be modeled separately as using average prices and volumes may be misleading.   The following provides examples of how Table 14 can be interpreted for approximate values (all in US dollars) at September 30, 2011:

• If the market price exceeds $88.91 per barrel, ARC will receive $88.91 per barrel on 20,000 barrels per day.

• If the market price is between $83.91 per barrel and $88.91 per barrel, ARC will receive the market price on 20,000 barrels per day.

• If the market price is between $60.43 per barrel and $83.91 per barrel, ARC will receive $83.91 per barrel on 20,000 barrels per day.

• If the market price is below $60.43 per barrel, ARC will receive $83.91 per barrel less the difference between $60.43 per barrel and the market price on 20,000 barrels per day.  For example, if the market price is at $55 per barrel, ARC will receive $78.42 on 12,000 barrels per day and $83.91 on 8,000 barrels per day.

The net fair value of ARC’s risk management contracts at September 30, 2011 was $88.1 million, representing the expected market price to buy out ARC’s contracts at the balance sheet date, which may differ from what will eventually be realized.

Operating Netbacks

ARC’s operating netback, before hedging, was $26.62 per boe in the third quarter of 2011 and $29.77 per boe year to date as compared to $24.30 per boe and $27.38 per boe, respectively, in the same periods of 2010.

ARC’s third quarter and year-to-date 2011 netbacks after including realized hedging gains and losses, were $30.75 per boe and $31.93 per boe, respectively, representing increases of 12 and eight per cent as compared to the same periods in 2010. These netbacks after hedging include realized gains recorded on ARC’s crude oil and natural gas risk management contracts as well as unrealized losses on risk management contracts that relate to January through September 2011 production in the case of annually settled risk management contracts.

The components of operating netbacks for the third quarter are summarized in Table 15:

Table 15

Netbacks ($ per boe)	Crude Oil ($/bbl)			Heavy Oil ($/bbl)			Condensate ($/bbl)			Natural Gas ($/mcf)			NGL ($/bbl)			Q3 2011 Total ($/boe)			Q3 2010 Total ($/boe)
Average sales price		86.66			65.87			92.85			3.88			47.90			44.83			41.14
Other		-			-			-			-			-			0.06			0.05
Total sales		86.66			65.87			92.85			3.88			47.90			44.89			41.19
Royalties		(14.99	)		(8.60	)		(26.59	)		(0.36	)		(13.72	)		(6.90	)		(6.51	)
Transportation		(0.75	)		(1.79	)		(0.18	)		(0.26	)		(0.39	)		(1.24	)		(1.07	)
Operating costs (1)		(16.83	)		(18.72	)		(8.26	)		(1.16	)		(11.38	)		(10.13	)		(9.31	)
Netback prior to hedging		54.09			36.76			57.82			2.10			22.41			26.62			24.30
Hedging gain (2)		2.42			-			-			0.89			-			4.13			3.09
Netback after hedging		56.51			36.76			57.82			2.99			22.41			30.75			27.39

(1) Operating expenses are composed of direct costs incurred to operate oil and gas wells. A number of assumptions have been made in allocating these costs between crude oil, heavy oil, condensate, natural gas and natural gas liquids production.

(2) Hedging gain includes realized cash gain on risk management contracts and unrealized loss on risk management contracts related to July through September 2011 production.  Foreign exchange, power and interest risk management contracts are excluded from the netback calculation.

The components of operating netbacks for the first nine months are summarized in Table 15a:

Table 15a

Netbacks ($ per boe)	Crude Oil ($/bbl)			Heavy Oil ($/bbl)			Condensate ($/bbl)			Natural Gas ($/mcf)			NGL ($/bbl)			YTD 2011 Total ($/boe)			YTD 2010 Total ($/boe)
Average sales price		88.90			70.94			94.17			3.99			46.56			47.75			45.98
Other		-			-			-			-			-			0.08			0.08
Total sales		88.90			70.94			94.17			3.99			46.56			47.83			46.06
Royalties		(15.43	)		(8.44	)		(25.37	)		(0.27	)		(12.34	)		(7.05	)		(7.59	)
Transportation		(0.56	)		(1.80	)		(0.28	)		(0.27	)		(0.39	)		(1.20	)		(1.11	)
Operating costs (1)		(15.82	)		(15.71	)		(5.29	)		(1.12	)		(10.95	)		(9.81	)		(9.98	)
Netback prior to hedging		57.09			44.99			63.23			2.33			22.88			29.77			27.38
Hedging gain (loss)  (2)		(3.90	)		-			-			0.93			-			2.16			2.07
Netback after hedging		53.19			44.99			63.23			3.26			22.88			31.93			29.45

(1) Operating expenses are composed of direct costs incurred to operate oil and gas wells. A number of assumptions have been made in allocating these costs between oil, heavy oil, condensate, natural gas and natural gas liquids production.

(2) Hedging gain includes realized cash gain on risk management contracts and unrealized loss on risk management contracts related to January through September 2011 production.  Foreign exchange, power and interest contracts are excluded from the net back calculation.

Page 12

Royalties as a percentage of pre-hedged commodity product sales decreased from 15.8 per cent ($6.51 per boe) in the third quarter of 2010 to 15.4 per cent ($6.90 per boe) in the third quarter of 2011 and from 16.5 per cent ($7.59 per boe) in the first nine months of 2010 to 14.7 per cent ($7.05 per boe) during the first nine months of 2011.  The decrease in the royalty rate is primarily due to the change in production profile, with higher natural gas production, lower natural gas prices and changes implemented to the Alberta and British Columbia provincial royalty regimes.

The following table shows ARC’s expected royalty rate for the remainder of 2011 and for 2012 and ranges from 13.5 per cent to 16 per cent depending on the commodity prices and the production profile of wells eligible for reduced royalty rates applicable under the Alberta and British Columbia provincial royalty regime changes.

Table 16

							Future Estimated Corporate Royalty Rate
Edmonton posted oil (Cdn$/bbl) (1)	$	70.00		$	70.00		$	80.00		$	80.00		$	90.00		$	90.00		$	80.00	(4)
AECO natural gas (Cdn$/GJ) (1)	$	3.50		$	4.50		$	3.50		$	4.50		$	3.50		$	4.50		$	4.00	(4)
Corporate Royalty Rate (2)(3)		13.5	%		14.5	%		14.5	%		15.2	%		15.4	%		16.0	%		15.0	% (4)

(1) Canadian dollar denominated prices before quality differentials.

(2) Estimated corporate royalty rates based on guidelines that are subject to change.

(3) Corporate royalty rate includes Crown, Freehold and Gross Override royalties for all of ARC’s operating jurisdictions.

(4) At the 2012 Budget commodity prices of WTI US$80.00 per barrel and $4.00 per GJ, the royalty rate will be approximately 15 per cent.

Operating costs increased to $10.13 per boe in the third quarter of 2011 compared to $9.31 per boe in the third quarter of 2010.  This increase is primarily attributed to increased electricity costs incurred in the third quarter where Alberta power costs averaged approximately $95 per mega watt hour as compared to approximately $36 per mega watt hour during the third quarter of 2010.  For the year-to-date, operating costs decreased $0.17 per boe from $9.98 per boe for the nine months ended September 30, 2010 to $9.81 per boe for the nine months ended September 30, 2011.   This decrease reflects increased production volumes in the current year and a greater weighting of lower cost properties in 2011 as compared to 2010.  Transportation costs were $1.24 per boe during the third quarter of 2011 ($1.20 per boe year-to-date) as compared to $1.07 per boe in the third quarter of the prior year ($1.11 per boe year to date).  ARC’s transportation expense is affected by various factors including service disruptions by third party service providers resulting in ARC requiring alternate transport for its product to reach its point of sale.

General and Administrative (“G&A”) Expenses and Long-Term Incentive Compensation

G&A, prior to any long-term incentive compensation expense and net of overhead recoveries on operated properties, decreased by 11 per cent to $12.3 million in the third quarter of 2011 from $14 million in the third quarter of 2010.  Third quarter 2011 G&A expenses were slightly lower as compared to the third quarter of 2010 due to increased operating recoveries from ARC’s partners offset by modestly increased compensation costs associated with increased staffing levels.

For the nine months ended September 30, 2011 ARC’s G&A prior to any long-term incentive compensation expense and net of overhead recoveries on operated properties was $42 million, a $2.1 million decrease from the first nine months of 2010.  This decrease is also a result of increased operating recoveries offset somewhat by moderately increased staffing costs.

Table 17 is a breakdown of G&A and incentive compensation expense:

Table 17

	Three months ended September 30									Nine months ended September 30
G&A and Incentive Compensation Expense ($ millions except per boe)	2011			2010			% Change			2011			2010			% Change
G&A expenses		19.2			18.0			7			59.3			55.7			6
Operating recoveries		(6.9	)		(4.0	)		73			(17.3	)		(11.6	)		49
G&A expenses before Long-Term Incentive Plans		12.3			14.0			(12	)		42.0			44.1			(5	)
G&A - Long-Term Incentive Plans		7.3			5.2			40			19.5			12.8			52
Total G&A and incentive compensation expense		19.6			19.2			2			61.5			56.9			8
Total G&A and incentive compensation expense per boe		2.50			2.69			(7	)		2.80			2.96			(5	)

Page 13

Long-Term Incentive Plans - Restricted Share Unit & Performance Share Unit Plan, Stock Option Plan, and Deferred Share Unit Plan

Restricted Share Unit (“RSU”) and Performance Share Unit (“PSU”) Plan

The RSU & PSU Plan is designed to offer each eligible employee and officer (the “plan participants”) cash compensation in relation to the value of a specified number of underlying share units. The RSU & PSU Plan consists of RSUs for which the number of units is fixed and will vest over a period of three years and PSUs for which the number of units is variable and will vest at the end of three years.

Upon vesting, the plan participant is entitled to receive a cash payment based on the fair value of the underlying share units plus accrued dividends. The cash compensation issued upon vesting of the PSUs is dependent upon the total return performance of ARC compared to its peers. Total return is calculated as a sum of the change in the market price of the common shares in the period plus the amount of dividends in the period. A performance multiplier is applied to the PSUs based on the percentile rank of ARC’s total shareholder return compared to its peers. The performance multiplier ranges from zero, if ARC’s performance ranks in the bottom quartile, to two for top quartile performance.

ARC recorded additional general and administrative expenses of $7.3 million during the third quarter of 2011 ($19.5 million year to date) in accordance with these plans, as compared to $5.2 million during the third quarter of 2010 ($12.8 million year to date). The increase reflects an increased number of employees that are eligible to receive long-term incentive rewards as well as an increased performance multiplier resulting in a larger total amount of PSUs expected to be issued at vesting.  During the first nine months of 2011, ARC made cash payments of $28.1 million in respect of the RSU & PSU Plan.  Of these payments, $20.3 million were in respect of amounts recorded to general and administrative expenses ($20.6 million in the first nine months of 2010), $7.8 million were in respect of amounts recorded to operating expenses and capitalized as property, plant and equipment and exploration and evaluation assets ($8.0 million for the first nine months of 2010).  These amounts have been accrued in prior periods.

Table 18 shows the changes to the RSU & PSU Plan during the first nine months of 2011:

Table 18

RSU & PSU Plan (number of units, thousands)	RSUs			PSUs			Total RSUs and PSUs
Balance, beginning of period		1,017			1,301			2,318
Granted		376			520			896
Distributed		(474	)		(304	)		(778	)
Forfeited		(55	)		(51	)		(106	)
Balance, end of period (1)		864			1,466			2,330

(1) Based on underlying units before performance multiplier.

The liability associated with the RSUs and PSUs granted is recognized in the statement of income over the vesting period while being adjusted each period for changes in the underlying share price, accrued dividends and the number of PSUs expected to be issued on vesting. In periods where substantial share price fluctuation occurs, ARC’s G&A expense is subject to significant volatility.

Due to the variability in the future payments under the plan, ARC estimates that between $20.6 million and $91.6 million will be paid out in 2012 through 2014 based on the current share price, accrued dividends and ARC’s market performance relative to its peers.  Table 19 is a summary of the range of future expected payments under the RSU & PSU Plan based on variability of the performance multiplier and units outstanding under the RSU & PSU Plan as at September 30, 2011:

Page 14

Table 19

Value of RSU & PSU Plan as at September 30, 2011	Performance multiplier
(units thousands and $ millions except per unit)		-	1.0	2.0
Estimated units to vest
RSUs		864	864	864
PSUs		-	1,466	2,932
Total units (1)		864	2,330	3,796
Share price (2)		22.56	22.56	22.56
Value of RSU & PSU Plan upon vesting (3)		20.6	56.1	91.6
2012		11.4	25.1	39.0
2013		6.4	16.5	26.5
2014		2.8	14.5	26.1

(1) Includes additional estimated units to be issued under the RSU & PSU Plan for accrued dividends.

(2) Values will fluctuate over the vesting period based on the volatility of the underlying share price. Assumes a future share price of $22.56.

(3) Upon vesting, a cash payment is made for the value of the share units, equivalent to the current market price of the underlying common shares plus accrued dividends. Payments are made on vesting dates in March and September of each year.

Share Option Plan

Effective January 1, 2011, ARC implemented a share option plan, as approved by shareholders at the special meeting of shareholders held December 15, 2010.  Share options are granted to officers, certain employees and certain consultants of ARC, vesting evenly on the fourth and fifth anniversary of their respective grant dates and have a maximum term of seven years.  The option holder has the right to exercise the options at the original exercise price or at a reduced exercise price, equal to the exercise price at grant date less all dividends paid subsequent to the grant date and prior to the exercise date.

On March 24, 2011, 430,990 share options were granted under this plan with an exercise price of $27.11 per share and are subject to a reduction in exercise price equal to the amount of dividends declared between the period of the grant date and the date the option vests. Compensation expense of $0.3 million has been recorded in 2011 and is included within G&A expenses. During the first nine months of 2011, 10,083 of the options granted were forfeited resulting in an ending balance of 420,907 share options outstanding.

Deferred Share Unit Plan (“DSU Plan”)

Effective January 1, 2011, ARC shareholders approved a DSU Plan for its non-employee directors under which each director receives a minimum of 55 per cent of their total annual remuneration in the form of deferred share units (“DSUs”).  Each DSU fully vests on the date of grant but is settled in cash only when the director has ceased to be a member of the Board of Directors of the Corporation.   For the three and nine months ended September 30, 2011, compensation expense of $0.3 million and $1.1 million, respectively, was recorded in relation to the DSU Plan (nil in 2010).

Interest and financing charges

Interest and financing charges decreased to $10.6 million in the third quarter of 2011 ($29.7 million year to date) from $13.6 million in the third quarter of 2010 ($32.0 million year to date) reflecting overall decreased debt levels.

At September 30, 2011, ARC had $682.3 million of long-term debt outstanding, including a current portion of $35.4 million of senior note principal that is due for repayment within the next twelve months.  Of the total debt balance, $456.4 million is fixed at a weighted average interest rate of 5.86 per cent while the remaining $225.9 million incurs a floating interest rate based on current market rates plus a current credit spread of 160 basis points.    On September 26, 2011, ARC entered into a new credit facility which had the effect of reducing its credit spread from 200 basis points to its current credit spread (see “Capitalization, Financial Resources and Liquidity”). Approximately 63 per cent (US$411.4 million) of ARC’s debt outstanding is denominated in US dollars.

Foreign Exchange Gains and Losses

ARC recorded a foreign exchange loss of $31.3 million in the third quarter of 2011 compared to a gain of $13.5 million in the third quarter 2010. Year to date, ARC recorded a foreign exchange loss of $19.3 million as compared to a gain of $11.7 million for the same period in the prior year.  During the first nine months of 2011, the US dollar relative to the Canadian dollar increased in value from a rate of 0.9946 to 0.9540, thereby increasing the Canadian dollar equivalent value of ARC’s US dollar denominated debt during the period by approximately $19.1 million which was most significantly affected in the third quarter of 2011.  In addition, ARC recorded $0.2 million realized foreign exchange losses arising from US denominated transactions such as interest payments, debt repayments and hedging settlements that were recorded during the first nine months of 2011.

Page 15

Table 20 shows the various components of foreign exchange gains and losses:

Table 20

	Three months ended September 30								Nine months ended September 30
Foreign Exchange Gains/Losses ($ millions)	2011			2010		% Change			2011			2010			% Change
Unrealized (loss) gain on US denominated debt		(31.3	)		13.5		(332	)		(21.0	)		(16.3	)		29
Realized gain on US denominated debt		-			-		-			2.1			28.3			(93	)
Realized loss on US denominated transactions		-			-		-			(0.2	)		(0.3	)		(33	)
Total foreign exchange (loss) gain		(31.3	)		13.5		(332	)		(19.3	)		11.7			(265	)

Taxes

During the third quarter of 2011, a deferred income tax expense of $46.4 million was recorded compared to $0.9 million in the third quarter of 2010.  A deferred tax expense of $114.4 million was recorded for the first nine months of 2011 as compared to $20.3 million for the first nine months of 2010.  The third quarter 2011 expense is primarily related to temporary differences arising from the book basis of ARC’s property, plant and equipment relative to its tax basis, the deferral of ARC’s partnership income and the increase in value of ARC’s risk management contracts which is not subject to tax until the contract positions are settled.

The corporate income tax rate applicable to 2011 is 26.5 per cent, however, ARC and its subsidiaries did not pay any material cash income taxes for the first nine months of 2011. Up until December 31, 2010, ARC’s structure was such that both current income tax and deferred tax liabilities were passed onto its unitholders by means of royalty payments made between ARC and the Trust.  With the conversion from a trust structure to a traditional corporate structure completed on December 31, 2010, ARC is subject to deferred income taxes in 2011 and beyond. Current taxes payable by ARC will be subject to normal corporate tax rates. Taxable income as a corporation will vary depending on total income and expenses and with changes to commodity prices, costs, claims for both accumulated tax pools and tax pools associated with current year expenditures.  As ARC has accumulated $2.6 billion of income tax pools for federal tax purposes, taxable income will be reduced or potentially eliminated for the initial period post-conversion.

On October 3, 2011 the finance minister tabled a notice of ways and means motion to implement tax measures outlined in the 2011 budget (Bill C-13) which included the proposal to eliminate the ability of a corporation to defer income as a result of timing differences in the year-end of the corporation and of any partnership of which it is a member.  Bill C-13 has been through its second reading and has now been referred to the standing committee on finance and is expected to be passed into law in the near future.

ARC’s oil and natural gas properties are directly owned and operated by ARC Resources General Partnership which has a January 31 year end.  Using the current forward commodity price outlook, a modeled future production volume forecast and current tax legislation including the expected loss of its deferral of its partnership income, ARC expects to be in a cash tax-paying position in 2012.

The income tax pools (detailed in Table 21) are deductible at various rates and annual deductions associated with the initial tax pools will decline over time.

Table 21

Income Tax Pool type ($ millions)	September 30, 2011	Annual deductibility
Canadian Oil and Gas Property Expense	873.6	10% declining balance
Canadian Development Expense	621.2	30% declining balance
Canadian Exploration Expense	101.2	100%
Undepreciated Capital Cost	664.8	Primarily 25% declining balance
Non-Capital Losses	254.2	100%
Research and Experimental   Expenditures	28.7	100%
Other	21.2	Various rates, 7% declining balance to 20%
Total Federal Tax Pools	2,564.9
Additional Alberta Tax Pools	177.6	Various rates, 25% declining balance to 100%

Page 16

Depletion, Depreciation and Amortization Expense and Impairment Charges

In accordance with IFRS, ARC records depletion, depreciation and amortization (“DD&A”) expense on its property, plant and equipment over the assets’ individual useful lives employing the declining balance method using proved plus probable reserves and associated estimated future development capital required for its oil and natural gas assets and a straight-line method for its corporate administrative assets.   Assets in the exploration and evaluation (“E&E”) phase are not amortized.  During the three and nine months ended September 30, 2011, ARC recorded $158.9 million and $331.1 million of DD&A expense, respectively, as compared to DD&A expense of $100.8 million and $270.8 million for the three and nine months ended September 30, 2010.

Under IFRS, impairments are recognized when an asset’s or group of assets’ carrying values exceed their recoverable amount defined as the higher of the value in use or fair value less cost to sell.  Any asset impairment that is recorded is recoverable to its original value less any associated DD&A should there be indicators that the recoverable amount of the asset has increased in value since the time of recording the initial impairment.  At September 30, 2011, an impairment charge of $45.1 million was recognized on the southern Alberta and southwest Saskatchewan district.  This district had previously recorded impairment charges of $30.7 million and subsequently recovered the impairment, net of associated DD&A, during the first quarter of 2011 as a result of improved forward commodity pricing.

A breakdown of the DD&A rate is summarized in Table 22:

Table 22

	Three months ended September 30						Nine months ended September 30
DD&A Rate ($ millions except per boe amounts)	2011		2010		% Change		2011		2010		% Change
Depletion of oil and gas assets		112.3		99.7		13		310.3		268.9		15
Depreciation of fixed assets		1.5		1.1		36		4.2		1.9		121
Impairment charges (net of recoveries)		45.1		-		100		16.6		-		100
Total DD&A and impairment		158.9		100.8		58		331.1		270.8		22
DD&A rate per boe, before impairment		14.52		14.14		3		14.31		14.10		1
DD&A rate per boe		20.28		14.14		43		15.06		14.10		7

Capital Expenditures, Acquisitions and Dispositions

Capital expenditures, excluding acquisitions and dispositions, totaled $229.3 million in the third quarter of 2011 as compared to $159.5 million during the third quarter of 2010.  This total included development and production additions to property, plant and equipment of $207 million (2010 - $130.3 million) and additions to exploration and evaluation assets of $22.3 million (2010 - $29.2 million).  Property, plant and equipment expenditures include drilling and completions, geological, geophysical, facilities expenditures and undeveloped land purchases in our development assets.  Exploration and evaluation expenditures include drilling and completions, geological and geophysical expenditures and undeveloped land purchases in areas that have been determined by management to be in the exploration and evaluation stage.

During the third quarter of 2011, $107.5 million was spent on ARC’s resource plays, including $73.7 million for development of the Montney resource play in northeast British Columbia, $7.9 million on undeveloped lands for the Montney resource play, $14.6 million for the Cardium resource play in Alberta and $9.4 million on undeveloped lands in the Cardium resource play area.  Of the amount remaining, $103.4 million was spent on ARC’s conventional oil and gas properties, $9.3 million spent on conventional land purchases, $5.5 million on ARC’s enhanced oil recovery initiatives and $3.6 million on corporate capital including information technology expenditures.

Page 17

A breakdown of capital expenditures and net acquisitions is shown in Tables 23 and 23a:

Table 23

	Three Months Ended September 30
	2011						2010
Capital Expenditures ($ millions)	E&E		PP&E		Total		E&E		PP&E			Total			% Change
Geological and geophysical		1.3		7.8		9.1		0.7		(0.5	)		0.2			4450
Drilling and completions		4.3		137.7		142.0		0.2		95.8			96.0			48
Plant and facilities		0.1		50.5		50.6		-		32.1			32.1			58
Undeveloped land purchased at crown land sales		16.6		10.0		26.6		28.3		0.3			28.6			(7	)
Other		-		1.0		1.0		-		2.6			2.6			(62	)
Total capital expenditures		22.3		207.0		229.3		29.2		130.3			159.5			44
Acquisitions (1)		-		8.6		8.6		-		1.4			1.4			514
Dispositions (2)		-		-		-		-		(3.5	)		(3.5	)		(100	)
Corporate acquisition		-		-		-		-		652.1			652.1			(100	)
Total capital expenditures and net acquisitions		22.3		215.6		237.9		29.2		780.3			809.5			(71	)

(1) Value is net of post-closing adjustments.

(2) Represents proceeds from divestitures.

For the nine months ended September 30, 2011, capital expenditures, excluding acquisitions and dispositions, totaled $531 million as compared to $431.8 million during the same period of 2010.  This total includes development and production additions to property, plant and equipment of $449.3 million (2010 - $380.7 million) and additions to exploration and evaluation assets of $81.7 million (2010 - $51.1 million).  Of the total year to date spending, $254.5 million was spent on ARC’s resource plays, including $192.5 million for development of the Montney resource play in northeast British Columbia, $12.9 million on undeveloped lands for the Montney resource play, $36.3 million for the Cardium resource play in Alberta and $9.4 million on undeveloped lands in the Cardium resource play area. Of the amount remaining, $203.9 million was spent on ARC’s conventional oil and gas properties, $49.2 million spent on conventional land purchases, $16.6 million on ARC’s enhanced oil recovery initiatives and $6.9 million on corporate capital including information technology expenditures.

Table 23a

	NIne Months Ended September 30
	2011								2010
Capital Expenditures ($ millions)	E&E		PP&E			Total			E&E		PP&E			Total			% Change
Geological and geophysical		5.5		15.5			21.0			2.6		7.8			10.4			102
Drilling and completions		22.0		287.3			309.3			4.5		253.6			258.1			20
Plant and facilities				126.4			126.4			-		88.5			88.5			43
Undeveloped land purchased at crown land sales		54.2		17.2			71.4			44.0		10.0			54.0			32
Other		-		2.9			2.9			-		20.8			20.8			(86	)
Total capital expenditures		81.7		449.3			531.0			51.1		380.7			431.8			23
Acquisitions (1)		13.3		20.8			34.1			-		7.7			7.7			343
Dispositions (2)		-		(170.0	)		(170.0	)		-		(3.5	)		(3.5	)		4757
Corporate acquisitions				-			-			-		652.1			652.1			(100	)
Total capital expenditures and net acquisitions		95.0		300.1			395.1			51.1		1,037.0			1,088.1			(64	)

(1) Value is net of post-closing adjustments.

(2) Represents proceeds from divestitures.

On a regular basis, ARC evaluates its asset portfolio to ensure that all assets still fit our business strategy and may sell assets that do not meet our retention guidelines.  During the first quarter of 2011, ARC disposed of non-core assets in central Alberta that produced approximately 3,400 boe per day (60 per cent gas and 40 per cent liquids) for proceeds of $170 million.  A gain on sale was recorded in relation to this transaction of $74.9 million reflecting the difference between the proceeds of sale and the carrying cost of the assets sold.  Also during the first quarter, ARC entered into a swap agreement with another oil and natural gas producer to dispose of interests in certain undeveloped lands in northeast British Columbia in exchange for additional undeveloped land in the same area adjacent to areas that ARC is currently active in. A gain on sale of approximately $13 million was recorded on this transaction. During the second quarter, ARC entered into a swap agreement with another oil and natural gas producer to dispose of interests in certain resource properties in northwest Alberta in exchange for resource properties in Northern Alberta.  This transaction closed in the third quarter and a gain on sale of $4.8 million was recorded.

Page 18

ARC initially funds its capital expenditures with funds from operations that are available subsequent to current period expenditures on site restoration and reclamation, net reclamation fund contributions and dividends declared in the current period.  Further funding is obtained by proceeds from DRIP with the remaining funding supplied by its credit facilities.   Approximately 66 per cent of the $229.3 million capital program in the third quarter of 2011 was financed with funds from operations and proceeds from DRIP as compared to 67 per cent in the third quarter of 2010.

Table 24

Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
	Three Months Ended September 30, 2011									Three Months Ended September 30, 2010
	Capital Expenditures			Net Acquisitions			Total Expenditures			Capital Expenditures			Net Acquisitions			Total Expenditures
Expenditures		229.3			8.6			237.9			159.5			650.0			809.5
Funds from operations(1)		54	%		-			52	%		53	%		-			53	%
Proceeds from DRIP		12	%		-			11	%		12	%		-			12	%
Debt (excess funding)		34	%		100	%		37	%		35	%		100	%		35	%
		100	%		100	%		100	%		100	%		100	%		100	%

(1) This is a non-GAAP measure which may not be comparable with similar non-GAAP measures used by other entities.  Refer to the section entitled “Non-GAAP Measures” contained within this MD&A.

Table 24a

Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
	Nine Months Ended September 30, 2011									Nine Months Ended September 30, 2010
	Capital Expenditures			Net Acquisitions			Total Expenditures			Capital Expenditures			Net Acquisitions			Total Expenditures
Expenditures		531.0			(135.9	)		395.1			431.8			656.3			1,088.1
Funds from operations(1)		67	%		-			67	%		58	%		-			58	%
Proceeds from DRIP		15	%		-			15	%		12	%		-			12	%
Debt (excess funding)		18	%		100	%		18	%		30	%		100	%		30	%
		100	%		100	%		100	%		100	%		100	%		100	%

(1) This is a non-GAAP measure which may not be comparable with similar non-GAAP measures used by other entities.  Refer to the section entitled “Non-GAAP Measures” contained within this MD&A.

Asset Retirement Obligations and Reclamation Fund

At September 30, 2011, ARC has recorded asset retirement obligations (“ARO”) of $478.5 million ($381.7 million at December 31, 2010) for the future abandonment and reclamation of ARC’s properties. The estimated ARO includes assumptions in respect of actual costs to abandon wells or reclaim the property, the time frame in which such costs will be incurred as well as annual inflation factors in order to calculate the undiscounted total future liability. The future liability has been discounted at a liability-specific risk-free interest rate of 2.77 per cent (3.52 per cent at December 31, 2010).

An accretion charge of $10.1 million and $9.2 million for the nine months ended September 30, 2011 and 2010, respectively, has been recognized in the Condensed Consolidated Statement of Income to reflect the increase in the ARO liability associated with the passage of time.

Actual spending under ARC’s abandonment and reclamation program for the three and nine months ended September 30, 2011 was $1.6 million and $5.0 million, respectively.

ARC established a restricted reclamation fund to finance obligations specifically associated with its Redwater property in 2005.  Minimum contributions to this fund will be approximately $81 million over the next 45 years.  The balance of this fund totaled $25.6 million at September 30, 2011, compared to $25 million at December 31, 2010.  Under the terms of ARC’s investment policy, reclamation fund investments and excess cash can only be invested in Canadian or US Government securities, investment grade corporate bonds, or investment grade short-term money market securities.

Environmental stewardship is a core value at ARC and abandonment and reclamation activities continue to be made in a prudent, responsible manner with the oversight of the Health, Safety and Environment Committee of the Board. Ongoing abandonment expenditures for all of ARC’s assets including contributions to the Redwater reclamation fund are funded entirely out of funds from operations.

Page 19

Capitalization, Financial Resources and Liquidity

A breakdown of ARC’s capital structure as at September 30, 2011 and December 31, 2010 is outlined in Table 25:

Table 25

Capital Structure and Liquidity ($ millions except per cent and ratio amounts)	September 30, 2011			December 31, 2010
Long-term debt(1)		682.3			803.5
Working capital deficit (2)		149.7			69.1
Unrealized loss on risk management contracts relating to January through September 2011 production (3)		38.1			-
Net debt obligations (4)		870.1			872.6
Market value of common shares (5)		6,490.5			7,226.6
Total capitalization (6)		7,360.6			8,099.2
Net debt as a percentage of total capitalization		11.8	%		10.8	%
Net debt to YTD annualized funds from operations(7)		1.1			1.3

(1) Includes a current portion of long-term debt of $35.4 million and $15.7 million at September 30, 2011 and December 31, 2010, respectively.

(2) Working capital deficit is calculated as current liabilities less the current assets as they appear on the Condensed Consolidated Balance Sheets, and excludes current unrealized amounts pertaining to risk management contracts, assets held for sale, asset retirement obligations contained within liabilities directly associated with assets held for sale and liabilities associated with exchangeable shares.

(3) Relates to unrealized losses relating to hedged volumes for the first nine months of 2011 pursuant to annual settled call contracts.

(4) Net debt is a non-GAAP measure and therefore it may not be comparable with the calculation of similar measures for other entities.   Refer to the section entitled “Non-GAAP Measures” contained within this MD&A.

(5) Calculated using the total common shares outstanding at September 30, 2011 multiplied by the closing share price of $22.56 at September 30, 2011 (closing trust unit price of $25.41 at December 31, 2010).

(6) Total capitalization as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Total capitalization is not intended to represent the total funds from equity and debt received by ARC.  Refer to the section entitled “Non-GAAP Measures” contained within this MD&A.

(7) This is a non-GAAP measure which may not be comparable with similar non-GAAP measures used by other entities.  Refer to the section entitled “Non-GAAP Measures” contained within this MD&A.

At September 30, 2011, ARC had total credit facilities of $1.6 billion with net debt of $870.1 million currently drawn resulting in unused credit net of debt drawn and working capital deficit available of approximately $725 million.  ARC’s long-term debt balance includes a current portion of $35.4 million at September 30, 2011 ($15.7 million at December 31, 2010) reflecting principal payments that are due to be paid within the next twelve months.  ARC intends to refinance these obligations by drawing on its syndicated credit facility at the time the payments are due.

Costs of borrowing under the syndicated credit facility comprise two items: first, the underlying interest rate on Bankers’ Acceptances and Prime Loans (CDN dollar loans) or LIBOR Loans and US Base Rate Loans (US denominated borrowings) and second, ARC’s credit spread.  The credit spread to ARC from the beginning of 2009 to July 2010 ranged between 60 and 70 basis points on all Bankers’ Acceptances and LIBOR Loans. No Prime Loans or

US Base Rate Loans were drawn during this period.  Effective August 2010, under the new bank credit facilities, the credit spread increased to 225 basis points for the remainder of 2010. Effective April 1, 2011, ARC’s credit spread was 200 basis points. On September 26, 2011, ARC extended its credit facility an additional two years to August 3, 2015 and reduced its current credit spread to 160 basis points.  Future credit spreads to ARC may range from 160 to 325 basis points for Bankers’ Acceptances and LIBOR loans depending on ARC’s ratio of debt to net income before non-cash items and interest expense. In addition to paying interest on the outstanding debt under the revolving syndicated credit facility, ARC is charged a standby fee for the amount of the undrawn facility. This standby fee has ranged from 12.5 to 15 basis points from the beginning of 2009 to July 2010, from August 2010 to September 26, 2011 and now ranges from 32 to 65 basis points under the renewed facility. These spreads are adjusted on the first day of the third month after each quarter-end date except in the case of the fourth quarter where the spreads are adjusted on the first day of the fourth month following the end of the relevant fiscal year.

ARC’s debt agreements contain a number of covenants all of which were met as at September 30, 2011. These agreements are available at www.sedar.com.  The major financial covenants are described below:

• Long-term debt and letters of credit not to exceed three times annualized net income before non-cash items and interest expense;

• Long-term debt, letters of credit, and subordinated debt not to exceed four times annualized net income before non-cash items and interest expense; and

• Long-term debt and letters of credit not to exceed 50 per cent of the book value of Shareholders’ equity and long-term debt, letters of credit and subordinated debt.

Page 20

ARC’s long-term strategy is to keep debt at less than two times funds from operations and under 20 per cent of total capitalization. This strategy resulted in manageable debt to cash flow levels throughout 2011 and 2010 and has positioned ARC to remain well below the debt covenant levels.

ARC typically uses three markets to raise capital: equity, bank debt and long-term notes.  Long-term notes are issued to large institutional investors normally with an average term of five to 12 years. The cost of this debt is based upon two factors: the current rate of long-term government bonds and ARC’s credit spread. ARC’s average interest rate on its outstanding long-term notes is currently 5.86 per cent.

ARC finances its 2011 capital program with funds from operations, proceeds from the DRIP and existing credit capacity. If ARC undertakes any major acquisitions, management would expect to finance the transactions with a combination of debt, proceeds from property dispositions and equity in a cost effective manner.

Shareholders’ Equity

At September 30, 2011, there were 287.7 million shares issued, an increase of 3.3 million shares over the balance of shares issued at December 31, 2010, entirely attributable to shares issued to participants in the DRIP.

Shareholders electing to reinvest dividends or make optional cash payments to acquire shares from treasury under the DRIP may do so at a five per cent discount to the prevailing market price with no additional fees or commissions. During the first nine months of 2011, ARC raised proceeds of $78.7 million and issued 3.3 million common shares pursuant to the DRIP at an average price of $23.62 per share.

During the first quarter of 2011, ARC issued its first grant of 430,990 options under its share option plan to certain officers and employees of the Corporation.  These options vest in equal parts on the fourth and fifth anniversaries of the grant date, respectively, and had a weighted average exercise price of $27.11 per share.  The granting of these options did not add any additional common shares to the diluted weighted average common share balance at the three and nine months ended September 30, 2011 as they were anti-dilutive.

Dividends

In the third quarter of 2011, ARC declared dividends totaling $86.2 million ($0.30 per share) compared to $80.3 million ($0.30 per share) during the third quarter of 2010.

As a dividend-paying corporation, ARC typically declares monthly dividends to its shareholders.  ARC continually assesses dividend levels in light of commodity prices, capital expenditure programs and production volumes, to ensure that dividends are in line with the long-term strategy and objectives of ARC as per the following guidelines:

• To maintain a dividend policy that, in normal times, in the opinion of management and the Board of Directors, is sustainable for a minimum period of six months after factoring in the impact of current commodity prices on cash flows. ARC’s objective is to normalize the effect of volatility of commodity prices rather than to pass that volatility onto shareholders in the form of fluctuating monthly dividends.

• To ensure that ARC’s financial flexibility is maintained by a review of ARC’s level of debt to equity and debt to funds from operations. The use of funds from operations and proceeds from equity offerings to fund capital development activities reduces the need to use debt to finance these expenditures.

The actual amount of future monthly dividends is proposed by management and is subject to the approval and discretion of the Board of Directors. The Board reviews future dividends in conjunction with their review of quarterly financial and operating results.  Dividends are taxable to the shareholder irrespective of whether payment is received in cash or shares via the DRIP.

Please refer to ARC’s website at www.arcresources.com for details of the monthly dividend amounts and dividend dates for 2011.

Environmental Initiatives Impacting ARC

There are no new material environmental initiatives impacting ARC at this time.

Contractual Obligations and Commitments

ARC has contractual obligations in the normal course of operations including purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, lease rental obligations and employee agreements. These obligations are of a recurring, consistent nature and impact ARC’s cash flows in an ongoing manner. ARC also has contractual obligations and commitments that are of a less routine nature as disclosed in Table 26.

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Table 26

	Payments Due by Period
($ millions)	1 year		2-3 years		4-5 years		Beyond 5 years		Total
Debt repayments (1)		46.0		82.5		311.0		242.8		682.3
Interest payments (2)		26.3		45.3		34.6		45.5		151.7
Reclamation fund contributions (3)		4.4		7.9		6.8		58.3		77.4
Purchase commitments		45.6		30.1		11.3		6.1		93.1
Transportation commitments(4)		17.7		45.5		27.1		0.5		90.8
Operating leases		10.8		18.2		16.0		63.2		108.2
Risk management contract premiums (5)		1.6		0.2		-		-		1.8
Total contractual obligations		152.4		229.7		406.8		416.4		1,205.3

(1) Long-term and short-term debt.

(2) Fixed interest payments on senior notes.

(3) Contribution commitments to a restricted reclamation fund associated with the Redwater property.

(4) Fixed payments for transporting production from the Dawson gas plant.

(5) Fixed premiums to be paid in future periods on certain commodity risk management contracts.

In addition to the above risk management contract premiums, ARC has commitments related to its risk management program (see Note 11 of the unaudited Condensed Consolidated Financial Statements). As the premiums are part of the underlying risk management contract, they have been recorded at fair market value at September 30, 2011 on the balance sheet as part of risk management contracts.

ARC enters into commitments for capital expenditures in advance of the expenditures being made. At any given point in time, it is estimated that ARC has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the capital in a future period. ARC’s 2011capital budget of $730 million was approved by the Board of Directors. The remaining portion of this commitment, as at September 30, 2011, has not been disclosed in the commitment table (Table 26) as it is of a routine nature and is part of normal course of operations for active oil and gas companies.

ARC is involved in litigation and claims arising in the normal course of operations. Management is of the opinion that pending litigation will not have a material adverse impact on ARC’s financial position or results of operations and therefore the commitment table (Table 26) does not include any commitments for outstanding litigation and claims.

ARC has certain sales contracts with aggregators whereby the price received by ARC is dependent upon the contracts entered into by the aggregator. This commitment has not been disclosed in the commitment table (Table 26) as it is of a routine nature and is part of normal course of operations.

Off Balance Sheet Arrangements

ARC has certain lease agreements, all of which are reflected in the Contractual Obligations and Commitments table (Table 26), which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases on the balance sheet as of September 30, 2011.

Critical Accounting Estimates

ARC has continuously refined and documented its management and internal reporting systems to ensure that accurate, timely, internal and external information is gathered and disseminated.

ARC’s financial and operating results incorporate certain estimates including:

• estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received;

• estimated capital expenditures on projects that are in progress;

• estimated depletion, depreciation and amortization charges that are based on estimates of oil and gas reserves that ARC expects to recover in the future;

• estimated fair values of derivative contracts that are subject to fluctuation depending upon the underlying commodity prices and foreign exchange rates;

• estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures

• estimated future recoverable value of property, plant and equipment and goodwill and any associated impairment charges or recoveries.

• estimated compensation expense under ARC’s PSU plan that is based on an adjustment to the final number of PSU awards that eventually vest based on a performance multiplier; and

• estimated deferred income tax assets and liabilities based on current tax interpretations, regulations and legislation that is subject to change.

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ARC has hired individuals and consultants who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates.

ARC’s leadership team’s mandate includes ongoing development of procedures, standards and systems to allow ARC staff to make the best decisions possible and ensuring those decisions are in compliance with ARC’s environmental, health and safety policies.

ASSESSMENT OF BUSINESS RISKS

The ARC management team is focused on long-term strategic planning and has identified the key risks, uncertainties and opportunities associated with ARC’s business that can impact the financial results.  They include, but are not limited to:

• the continuation of low natural gas prices

• volatility of oil and natural gas prices

• refinancing and debt service

• counterparty risk

• variations in interest rates and foreign exchange rates

• reserve and resource estimates

• changes in income tax legislation

• acquisitions

• environmental concerns and impact on enhanced oil recovery projects

• operational matters

• depletion of reserves and maintenance of dividend; and

• project risks.

Internal Control over Financial Reporting

ARC is required to comply with National Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings”, otherwise referred to as Canadian Sarbanes Oxley (“C-Sox”).  The certification of interim filings for the interim period ended September 30, 2011 requires that ARC disclose in the interim MD&A any changes in ARC’s internal control over financial reporting that occurred during the period that has materially affected, or is reasonably likely to materially affect ARC’s internal control over financial reporting.  ARC confirms that no such changes were made to its internal controls over financial reporting during the first nine months of 2011.

FINANCIAL REPORTING UPDATE

Transition to IFRS

ARC has prepared its unaudited Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2011 under IFRS and has restated its unaudited Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2010 to comply with IFRS.  The financial information presented in this MD&A is derived directly from ARC’s financial statements and as such certain comparative information may differ from what was originally prepared by ARC using Canadian GAAP.  The financial information contained within this MD&A that relates to periods prior to January 1, 2010 has been prepared under previous Canadian GAAP and has not been re-presented.

ARC’s Condensed Consolidated Financial Statements as at and for the periods ended September 30, 2011 and 2010 have been prepared in accordance with IAS 34 - Interim Financial Reporting and IFRS 1 - First-time Adoption of International Financial Reporting Standards under IFRS as issued by the International Accounting Standards Board.  A summary of the significant accounting policies that ARC has adopted in the transition from Canadian GAAP to IFRS is presented below.

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Opening IFRS Balance Sheet

Most adjustments required on transition to IFRS have been made retrospectively against opening retained earnings as of January 1, 2010, based on standards applicable at that time.  IFRS 1 provides entities adopting IFRS for the first time with certain optional exemptions and mandatory exceptions to the general requirement for full retrospective application of IFRS. Management has analyzed the various accounting policy choices available under IFRS 1 and has applied the following IFRS 1 exemptions in its IFRS opening balance sheet:

• Property, Plant and Equipment (“PP&E”) - ARC has applied the exemption provided under IFRS 1 to set its deemed cost of its oil and natural gas PP&E on the date of transition to IFRS to be equal to the carrying value of these assets under Canadian GAAP at January 1, 2010.  The total carrying value of ARC’s PP&E was allocated among seven cash generating units (“CGUs”) based on their respective proved plus probable reserve values at January 1, 2010.  These CGUs are aligned with the major geographic regions in which ARC operates and are subject to change as a result of significant acquisition or disposition activity.  In early 2011, upon completion of a disposition of certain non-core assets, ARC reduced its number of CGUs to six.

• Business Combinations - IFRS 1 provides an optional exemption to the requirement to retrospectively restate any business combinations that have previously been recorded under Canadian GAAP.  Accordingly, ARC has not recorded any adjustments to retrospectively restate any of its business combinations that have occurred prior to January 1, 2010.

• Leases - IFRS 1 provides an exemption from the requirements of IFRIC 4 - Determining Whether an Arrangement contains a lease in that it does not require an entity to reassess contracts

Accounting Policies

The following is a listing of key areas where ARC’s accounting policies differ under IFRS from previous Canadian GAAP:

• Re-classification of Exploration and Evaluation (“E&E”) expenditures from PP&E - Upon transition to IFRS, ARC reclassified all assets that it determined to be in the E&E stage from PP&E to a separate line item on the Consolidated Balance Sheets. E&E assets consist of the carrying value of certain undeveloped land that relates to exploration properties and associated capital expenditures leading to the establishment of reserves that are technically feasible and commercially viable. E&E assets are not amortized and must be assessed for impairment when indicators suggest the possibility of impairment as well as upon transition to PP&E.

• Calculation of depletion expense for PP&E assets - Upon transition to IFRS, ARC has chosen to calculate depletion using a reserve base of proved plus probable reserves, as compared to the Canadian GAAP requirement to base depletion expense on proved reserves only.  ARC made this accounting policy selection on the basis that proved plus probable reserves is thought to be more reflective of the expected useful life of the underlying asset than proved reserves alone. ARC has determined that its total DD&A expense has been reduced by $50.7 million for the nine months ended September 30, 2010 and $42.5 million for the year ended December 31, 2010, respectively, as a result of applying this new accounting policy.

• Impairment of PP&E assets - Canadian GAAP historically used a two-step approach to impairment testing;  first comparing asset carrying values with undiscounted future cash flows to determine whether an impairment exists, and then measuring impairment by comparing asset carrying values to their fair value (which is calculated using discounted cash flows).  Under Canadian GAAP, ARC included all its petroleum and natural gas assets in one impairment test.

IFRS requires a one-step approach for testing and measuring impairment, with asset carrying values compared directly with the higher of fair value less costs to sell and value in use.  Under IFRS, impairment of PP&E is calculated at the CGU level.

As required by IFRS 1, impairment tests were performed at January 1, 2010 without identifying any impairment.  Impairment tests were also conducted at each reporting period end throughout 2010.  At December 31, 2010, an impairment charge of $30.7 million was recognized to reduce the carrying value of assets contained within ARC’s Southern Alberta Southwest Saskatchewan CGU to their fair value less cost to sell.  No such impairment would be recognized under Canadian GAAP and accordingly, 2010 net income was reduced under IFRS by the amount of this adjustment.

IFRS requires that if an impairment is recognized, and circumstances change in the future such that that impairment may be reversed, the entity must recover that impairment to the point of the original carrying value less accumulated depletion and depreciation that would have accrued since the recognition of impairment.  Canadian GAAP does not permit the reversal of impairment charges on assets once recorded.

Assets held for sale and disposals of PP&E - IFRS requires that when a long-term asset is available for immediate sale in its present condition and use and the sale is highly probable it be separately classified on the balance sheet as an asset held for sale and presented at the lower of carrying amount and fair value less cost to sell.  For entities such as ARC that previously followed the full cost accounting guideline under Canadian GAAP, no such presentation was required.  IFRS also requires that liabilities directly associated with assets segregated as held for sale be presented separately as current liabilities on the Consolidated Balance Sheet.

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Upon disposal of assets held for sale, a gain or loss is recorded in the Consolidated Income Statement equal to the difference between the selling price of the asset (or group of assets) less associated selling costs and the asset’s carrying value.  For entities that previously followed full cost accounting under Canadian GAAP, no gain or loss was recorded on disposals of assets unless the disposal altered the depletion rate of the reporting segment by 20 per cent or more.

• ARO - Under IFRS, ARC is required to revalue its entire liability for asset retirement costs at each balance sheet date using a current liability-specific discount rate.  Under Canadian GAAP, obligations are discounted using a credit-adjusted risk-free rate and, once recorded, the ARO is not adjusted for future changes in discount rates. At January 1, 2010 ARC’s total of its ARO was increased $148.2 million to $298.1 million as the liability was revalued to reflect the estimated risk-free rate of interest at that time of 4.08 per cent.  As a result of this change, ARC’s deferred tax liability was decreased by $36.9 million and the net offset was recorded as a reduction to deficit. ARC’s net income was decreased by $1.9 million for the nine months ended September 30, 2010 and by $2.7 million for the year ended December 31, 2010 as a result of an increased amount of accretion charged on its ARO under IFRS.

• Exchangeable shares - Under IFRS, ARC’s exchangeable shares met the criteria to be considered a puttable financial instrument and were classified as a current financial liability. They have been recorded on the Consolidated Balance Sheet at their fair value with any changes being recorded in the Consolidated Income Statement. At January 1, 2010, ARC’s current liability associated with exchangeable shares under IFRS was $47.2 million.  Under Canadian GAAP, exchangeable shares were classified as non-controlling interest and measured using the equity method.  At December 31, 2010, all exchangeable shares were exchanged for common shares of ARC and the associated value was recognized in shareholders’ equity.

• Deferred taxes - Under IFRS, entities that are subject to different tax rates on distributed and undistributed income must calculate deferred taxes using the undistributed profits rate, which is the higher of the two.  Canadian GAAP requires each individual tax rate to be applied to distributed and undistributed profits, respectively.  As a result of using the undistributed profits rate, ARC recorded a reduction in its deferred tax liability of $29.6 million upon transition to IFRS, with the offset recorded as a reduction to deficit.

Note 16 of ARC’s Consolidated Financial Statements as at and for the period ended September 30, 2011 and 2010 filed on SEDAR at www.sedar.com provides a reconciliation of the differences recorded in the financial statements between Canadian GAAP and IFRS upon transition, as at September 30, 2010, as at December 31, 2010 as well as for the three and nine months ended September 30, 2010 and the year ended December 31, 2010.

Non-GAAP Measures

Management uses certain key performance indicators (“KPIs”) and industry benchmarks such as funds from operations, operating netbacks (“netbacks”), total capitalization, finding, development and acquisition costs, recycle ratio, reserve life index, normalized reserves per share and production per share, normalized dividend adjusted reserves per share and production per share, net asset value and total returns to analyze financial and operating performance. Management feels that these KPIs and benchmarks are key measures of profitability for ARC and provide investors with information that is commonly used by other oil and gas companies. These KPIs and benchmarks as presented do not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures for other entities.

Funds from Operations

Funds from operations is not a recognized performance measure under GAAP and does not have a standardized meaning prescribed by GAAP.  The term “funds from operations” is defined as net income excluding the impact of non-cash depletion, depreciation and amortization, accretion of asset retirement obligations, deferred tax expense (recovery), loss on revaluation of exchangeable shares, unrealized gains and losses on risk management contracts, unrealized gains and losses on short term investment, non-cash lease inducement, unrealized gains and losses on foreign exchange and gains on disposal of petroleum and natural gas properties and is further adjusted to include the portion of unrealized gains and losses on risk management contracts that relate to January through September 2011 production.  ARC considers funds from operations to be a key measure of operating performance as it demonstrates ARC’s ability to generate the necessary funds to fund future growth through capital investment and to repay debt.  Management believes that such a measure provides a better assessment of ARC’s operations on a continuing basis by eliminating certain non-cash charges and charges that are nonrecurring, while respecting that certain risk management contracts that are settled on an annual basis are intended to protect prices on product sales occurring throughout the year.  From a business perspective, the most directly comparable measure of funds from operations calculated in accordance with GAAP is net income.  Table 27 is a reconciliation of ARC’s funds from operations to net income.

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Table 27

	Three months ended September 30						Nine months ended September 30
($ millions)	2011			2010			2011			2010
Net income		120.8			90.3			336.0			299.0
Adjusted for the following non-cash items:
Depletion, depreciation and amortization		158.9			100.8			331.1			270.8
Accretion of asset retirement obligation		3.3			3.1			10.1			9.2
Deferred tax expense		46.4			0.9			114.4			20.3
Unrealized gain on risk management contracts		(138.3	)		(23.8	)		(63.7	)		(114.1	)
Foreign exchange loss (gain) on revaluation of debt		31.3			(13.4	)		19.1			(11.9	)
Gain on disposal of petroleum and natural gas properties		(4.8	)		-			(92.7	)		-
Other		0.7			9.8			1.4			13.2
Unrealized losses on risk management contracts related to January through September 2011 production(1)		(4.8	)		-			(38.1	)		-
Funds from operations		213.5			167.7			617.6			486.5

(1) ARC has entered into certain commodity price risk management contracts that pertain to production periods spanning the entire calendar year but that are settled at the end of the year on an annual average benchmark commodity price.  The portion of losses associated on these contracts that relates to production periods for the three and nine months ended September 30, 2011 have been applied to reduce funds from operations in order to more appropriately reflect the funds from operations generated during the period after any effect of contracts used for economic hedging.

Net Debt

Net debt is not a recognized performance measure under GAAP and does not have a standardized meaning prescribed by GAAP.  Net debt is defined as long-term debt plus working capital deficit plus unrealized losses on risk management contracts related to January through September production.  Working capital deficit is calculated as current liabilities less the current assets as they appear on the Condensed Consolidated Balance Sheets, and excludes current unrealized amounts pertaining to risk management contracts, assets held for sale, asset retirement obligations contained within liabilities directly associated with assets held for sale and liabilities associated with exchangeable shares.

Forward-looking Information and Statements

This MD&A contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this MD&A contains forward-looking information and statements pertaining to the following: all of the matters under the heading "2011 Annual Guidance and Financial Highlights" which contains guidance for 2011, the future expenditure plans and strategy for 2011 and expected production and operations under the heading "Production", the expected provincial royalty rates for 2011 and 2012 under various commodity pricing outlooks for 2011 and 2012 under the heading "Operating Netbacks", the estimated future payments under the RSU & PSU Plan under the heading “Long-term Incentive Plans - Restricted Share Units & Performance Share Units Plan, Stock Option Plan, and Deferred Share Unit Plan”, the estimate of ARC as to when it expects to be in a material cash tax-paying position under the heading “Taxes”, the information relating to financing the 2011 capital expenditures under the heading: "Capitalization, Financial Resources and Liquidity", ARC’s estimates of normal course obligations under the heading “Contractual Obligations and Commitments”, and a number of other matters, including the amount of future asset retirement obligations; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; and future development, exploration, acquisition and development activities (including drilling plans) and related capital expenditures.

The forward-looking information and statements contained in this MD&A reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its planned expenditures. ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

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The forward-looking information and statements included in this MD&A are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this MD&A and in ARC's Annual Information Form).

The forward-looking information and statements contained in this MD&A speak only as of the date of this MD&A, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

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(Cdn $ millions, except per share amounts)	2011						2010							2009
FINANCIAL		Q3	Q2		Q1			Q4		Q3		Q2	Q1		Q4
Sales of crude oil, natural gas and natural gas   liquids		351.8	374.9		324.7			329.3		293.6		276.7	314.1		278.6
Per share (1)		1.23	1.31		1.14			1.16		1.10		1.09	1.25		1.17
Funds from operations (2)		213.5	210.1		194.1			180.4		167.9		151.0	167.9		151.4
Per share (1)		0.74	0.73		0.68			0.63		0.63		0.60	0.67		0.63
Net income (loss)		120.8	150.1		65.2			(86.9	)	90.5		58.8	149.8		66.2
Per share (1)		0.42	0.52		0.23			(0.31	)	0.34		0.23	0.60		0.28
Dividends		86.2	85.8		85.5			82.8		80.3		75.3	75.0		70.9
Per unit (1)		0.30	0.30		0.30			0.30		0.30		0.30	0.30		0.30
Total assets		5,313.3	5,053.4		5,019.9			5,060.1		5,092.2		4,154.8	4,035.1		3,914.5
Total liabilities		2,043.4	1,844.6		1,902.5			1,947.7		2,031.6		1,575.3	1,455.7		1,540.1
Net debt outstanding (3)		870.1	744.8		731.9			872.7		867.3		728.8	678.3		902.4
Weighted average shares (4)		287.1	286.0		284.9			283.7		268.0		253.2	251.8		238.5
Shares outstanding, end of period		287.7	286.5		285.4			284.4		283.1		253.6	252.8		239.0
CAPITAL EXPENDITURES
Geological and geophysical		9.1	5.2		6.7			5.6		0.2		3.6	6.6		2.9
Land		26.6	34.5		10.4			6.9		28.6		21.5	3.9		2.0
Drilling and completions		142.0	69.8		98.6			100.4		96.0		84.9	77.2		66.1
Plant and facilities		50.6	35.2		40.6			42.9		32.1		26.9	29.5		35.3
Other		1.0	(0.2	)	0.9			3.3		2.6		7.1	11.1		11.0
Total capital expenditures		229.3	144.5		157.2			159.1		159.5		144.0	128.3		117.3
Property acquisitions (dispositions), net		8.6	13.6		(157.3	)		0.8		(2.1	)	-	6.3		1.1
Corporate acquisitions (5)		-	-		-			-		652.1		-	-		178.9
Total capital expenditures and net acquisitions		237.9	158.1		(0.1	)		159.9		809.5		144.0	134.6		297.3
OPERATING
Production
Crude oil (bbl/d)		26,024	26,038		28,108			27,417		26,959		27,354	27,640		27,415
Condensate (bbl/d)		2,009	2,105		1,872			2,197		1,689		1,325	1,246		1,210
Natural gas (mmcf/d)		327.4	311.8		246.4			311.5		275.0		211.2	217.9		189.0
Natural gas liquids (bbl/d)		2,584	2,250		2,834			3,158		3,001		2,330	2,006		2,387
Total (boe per day 6:1)		85,178	82,367		73,880			84,686		77,483		66,208	67,207		62,520
Average prices
Crude oil ($/bbl)		85.97	97.11		82.27			76.08		71.07		71.98	76.26		72.61
Condensate ($/bbl)		92.85	100.57		88.34			78.38		73.51		78.33	80.00		72.37
Natural gas ($/mcf)		3.88	4.05		4.05			3.83		3.79		4.12	5.42		4.58
Natural gas liquids ($/bbl)		47.90	48.40		43.83			38.89		35.41		38.62	48.02		32.81
Oil equivalent ($/boe)		44.83	49.94		48.75			42.18		41.14		45.82	51.85		48.35
TRADING STATISTICS
(Cdn$) based on intra-day trading
High		26.23	27.00		28.67			26.05		21.11		22.89	22.78		22.10
Low		19.81	23.41		23.66			20.42		18.77		18.80	19.71		18.15
Close		22.56	25.01		26.35			25.41		20.55		19.73	20.50		19.94
Average daily volume (thousands)		1,108	998		1,636			1,299		1,160		1,043	1,287		963

QUARTERLY HISTORICAL REVIEW

(1) Upon conversion to a corporation, ARC trust units were exchanged for common shares.  In all cases, the term per share can be interpreted as per unit prior to December 31, 2010.  Per share amounts (with the exception of dividends) are based on diluted shares.

(2) This is a non-GAAP measure which may not be comparable with similar non-GAAP measures used by other entities.  Refer to the section entitled “Non-GAAP Measures” contained within this MD&A.

(3) Net debt is a non-GAAP measure and therefore it may not be comparable with the calculation of similar measures for other entities.   Refer to the section entitled “Non-GAAP Measures” contained within this MD&A.

(4) Diluted common shares.

(5) Represents total consideration for corporate acquisitions including fees but prior to working capital, asset retirement obligation and future income tax liability assumed on acquisition.

(6) The financial information above that has been derived from ARC’s unaudited financial statements has been prepared under IFRS for all periods throughout 2011 and 2010.  Information relating to 2009 has been prepared under previous Canadian GAAP.

Page 28

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)

As at

(Cdn$ millions)	September 30, 2011			December 31, 2010			January 1, 2010
ASSETS
Current assets
Cash and cash equivalents (Note 6)	$	0.5		$	2.0		$	-
Accounts receivable		144.2			160.5			115.9
Prepaid expenses		16.4			12.0			18.2
Risk management contracts (Note 11)		66.5			66.8			5.9
Short-term investment		3.2			3.5			-
Assets held for sale (Note 8)		4.5			123.9			-
		235.3			368.7			140.0
Reclamation funds		25.6			25.0			33.2
Risk management contracts  (Note 11)		27.0			0.6			3.2
Property, plant and equipment (Note 8)		4,607.8			4,343.2			3,550.4
Intangible exploration and evaluation assets (Note 7)		169.4			74.4			23.0
Goodwill (Note 7)		248.2			248.2			157.6
Total assets	$	5,313.3		$	5,060.1		$	3,907.4
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	$	284.9		$	211.7		$	166.7
Current portion of long-term debt (Note 9)		35.4			15.7			27.0
Dividends payable		28.8			27.7			23.7
Risk management contracts (Note 11)		5.4			22.0			12.9
Exchangeable shares		-			-			47.2
Liabilities directly associated with assets held for sale		1.9			18.0			-
		356.4			295.1			277.5
Risk management contracts (Note 11)		-			20.9			1.0
Long-term debt (Note 9)		646.9			787.8			819.1
Long-term incentive compensation liability (Note 13)		15.7			26.6			10.9
Other deferred liabilities		22.1			25.0			-
Asset retirement obligations (Note 10)		478.5			381.7			298.1
Deferred taxes		523.8			410.6			255.1
Total liabilities		2,043.4			1,947.7			1,661.7
COMMITMENTS AND CONTINGENCIES (Note 14)
SHAREHOLDERS’ EQUITY
Shareholders’ capital (Note 12)		3,191.2			3,112.5			2,898.3
Contributed surplus		0.3			-			-
Retained earnings (deficit)		78.5			-			(652.0	)
Accumulated other comprehensive loss		(0.1	)		(0.1	)		(0.6	)
Total shareholders’ equity		3,269.9			3,112.4			2,245.7
Total liabilities and shareholders’ equity	$	5,313.3		$	5,060.1		$	3,907.4

See accompanying notes to the Condensed Consolidated Financial Statements

Page 29

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (unaudited)

For the three and nine months ended September 30

	Three Months Ended September 30						Nine Months Ended September 30
(Cdn$ millions, except per share amounts)	2011			2010			2011			2010
Sales of crude oil, natural gas and natural gas liquids	$	351.8		$	293.6		$	1,051.4		$	884.4
Royalties		(54.1	)		(46.4	)		(155.0	)		(145.8	)
REVENUE		297.7			247.2			896.4			738.6
Gain on risk management contracts (Note 11)		178.7			49.1			155.4			159.5
		476.4			296.3			1,051.8			898.1
EXPENSES
Transportation		9.7			7.6			26.4			21.3
Operating		79.4			66.4			215.7			191.7
General and administrative		19.6			19.2			61.5			56.9
Interest and financing charges		10.6			13.6			29.7			32.0
Accretion of asset retirement obligation (Note 10)		3.3			3.1			10.1			9.2
Depletion, depreciation and amortization and impairment (recovery) (Note 8)		158.9			100.8			331.1			270.8
Loss (gain)  on foreign exchange		31.3			(13.5	)		19.3			(11.7	)
Loss on revaluation of exchangeable shares		-			8.7			-			9.4
Loss (gain) on short-term investments		1.2			(0.9	)		0.3			(0.9	)
Gain on disposal of petroleum and natural gas properties (Note 8)		(4.8	)		-			(92.7	)		-
		309.2			205.0			601.4			578.7
Capital and other taxes		-			0.1			-			0.1
Deferred tax expense		46.4			0.9			114.4			20.3
Net income	$	120.8		$	90.3		$	336.0		$	299.0
Net income per share (Note 12)
Basic	$	0.42		$	0.34		$	1.17		$	1.18
Diluted	$	0.42		$	0.34		$	1.17		$	1.16

See accompanying notes to the Condensed Consolidated Financial Statements

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
For the three and nine months ended September 30
	Three Months Ended September 30						Nine Months Ended September 30
(Cdn$ millions)	2011			2010			2011		2010
Net income	$	120.8		$	90.3		$	336.0	$	299.0
Other comprehensive income, net of tax
Losses on financial instruments designated as cash flow hedges		-			(0.4	)		-		-
Gains on financial instruments designated as cash flow hedges		-			0.3			-		0.3
Net unrealized gains on available-for-sale reclamation funds’ investments		(0.1	)		0.1			-		0.2
Other comprehensive income		(0.1	)		-			-		0.5
Comprehensive income	$	120.7		$	90.3		$	336.0	$	299.5

See accompanying notes to the Condensed Consolidated Financial Statements

Page 30

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (unaudited)

For the nine months ended September 30

(Cdn$ millions)

	Shareholders’ Capital			Contributed Surplus		(Deficit) Retained Earnings			Accumulated other comprehensive income (loss)			Total Shareholders’ Equity
January 1, 2010	$	2,898.3		$	-	$	(652.0	)	$	(0.6	)	$	2,245.7
Equity offering		252.3			-		-			-			252.3
Issued on acquisition		449.2			-		-			-			449.2
Issued on conversion of exchangeable shares		2.6			-		-			-			2.6
Units issued pursuant to the
distribution reinvestment program		50.6			-		-			-			50.6
Trust unit issue costs(1)		(8.6	)		-		-			-			(8.6	)
Comprehensive income		-			-		299.0			0.5			299.5
Distributions declared		-			-		(230.6	)		-			(230.6	)
September 30, 2010	$	3,644.4		$	-	$	(583.6	)	$	(0.1	)	$	3,060.7
December 31, 2010	$	3,112.5		$	-	$	-		$	(0.1	)	$	3,112.4
Shares issued pursuant to the
dividend reinvestment program		78.7			-		-			-			78.7
Share options granted		-			0.3		-			-			0.3
Comprehensive income		-			-		336.0			-			336.0
Dividends declared		-			-		(257.5	)		-			(257.5	)
September 30, 2011	$	3,191.2		$	0.3	$	78.5		$	(0.1	)	$	3,269.9

(1)   Amount is net of deferred tax of $4.0 million.

See accompanying notes to the Condensed Consolidated Financial Statements

Page 31

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

For the three and nine months ended September 30

	Three Months Ended							Nine Months Ended
	September 30							September 30
(Cdn$ millions)	2011				2010			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	120.8		$	90.3		$	336.0			$	299.0
Add items not involving cash:
Unrealized gain on risk management contracts (Note 11)			(138.3	)		(23.8	)		(63.7	)			(114.1	)
Accretion of asset retirement obligation (Note 10)			3.3			3.1			10.1				9.2
Depletion, depreciation and amortization and impairment (recovery) (Note 8)			158.9			100.8			331.1				270.8
Loss (gain) on foreign exchange			31.3			(13.4	)		19.1				(11.9	)
Gain on disposal of petroleum and natural gas properties  (Note 8)			(4.8	)		-			(92.7	)			-
Deferred tax expense			46.4			0.9			114.4				20.3
Other (Note 15)			0.7			9.8			1.4				13.2
Net change in other liabilities (Note 15)			(5.1	)		(1.4	)		(13.7	)			(4.5	)
Change in non-cash working capital (Note 15)			2.4			4.4			31.2				11.3
			215.6			170.7			673.2				493.3
CASH FLOW FROM FINANCING ACTIVITIES
Issue (repayment) of long-term debt under revolving credit facilities, net			41.0			34.8			(133.8	)			(286.5	)
Issue of Senior Notes			-			-			-				210.4
Repayment of Senior Notes			-			-			(6.6	)			(65.8	)
Issue of shares			0.4			0.5			1.3				241.2
Cash dividends paid			(60.0	)		(59.0	)		(179.1	)			(177.6	)
			(18.6	)		(23.7	)		(318.2	)			(78.3	)
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of petroleum and natural gas properties			(8.5	)		(1.5	)		(34.8	)			(7.8	)
Disposals of petroleum and natural gas properties			-			3.5			168.8				3.5
Property, plant and equipment development expenditures (Note 8)			(208.5	)		(131.1	)		(439.1	)			(382.1	)
Exploration and evaluation expenditures (Note 7)			(22.3	)		(29.3	)		(95.0	)			(51.2	)
Net reclamation fund (contributions) withdrawals			(1.3	)		(1.2	)		(0.6	)			0.2
Change in non-cash working capital (Note 15)			41.9			12.6			44.2				22.7
			(198.7	)		(147.0	)		(356.5	)			(414.7	)
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS			(1.7	)		-			(1.5	)			0.3
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			2.2			0.3			2.0				-
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	0.5		$	0.3		$	0.5			$	0.3

The following amounts are included in Cash Flows From Operating Activities:
Income taxes paid in cash	$	-	$	-	$	1.7	$	-
Interest paid in cash	$	2.1	$	2.4	$	14.8	$	11.0

See accompanying notes to the Condensed Consolidated Financial Statements

Page 32

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

September 30, 2011 and 2010

(all tabular amounts in Cdn$ millions, except per share amounts)

1.  STRUCTURE OF THE BUSINESS

The principal undertakings of ARC Resources Ltd., its predecessor ARC Energy Trust and its subsidiaries (collectively the “Company” or “ARC”) are to carry on the business of acquiring, developing and holding interests in petroleum and natural gas properties and assets.

On December 31, 2010, ARC Energy Trust (the “Trust”) effectively completed its conversion from an income trust to a corporation pursuant to the Plan of Arrangement (the “Arrangement”).  In these and future financial statements ARC will refer to common shares, shareholders and dividends which were formerly referred to as trust units, unitholders and distributions under the trust structure.  Comparative amounts in these and future financial statements will reflect the history of the Trust.

ARC’s principal place of business is located at 1200, 308 – 4th Avenue SW, Calgary, Alberta T2P 0H7.

2.  BASIS OF PREPARATION

The condensed financial statements (the “financial statements”) represent the Company’s initial presentation of its results and financial position under IFRS and were prepared in accordance with IAS 34 – Interim Financial Reporting and IFRS 1 - First-time Adoption of International Financial Reporting Standards using accounting policies consistent with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board.

A summary of ARC’s significant accounting policies under IFRS is presented in Note 3.  These policies have been retrospectively and consistently applied except where specific exemptions permitted an alternative treatment upon transition to IFRS in accordance with IFRS 1 as disclosed in Note 16.

An explanation of how the transition to IFRS has affected the reported balance sheet, changes to shareholders’ equity, income and comprehensive income, and cash flows of the Company is provided in Note 16.

The financial statements include the accounts of ARC and its wholly owned subsidiaries, ARC Resources General Partnership and 1504793 Alberta Ltd.  Any reference to the “Company” or “ARC” throughout these financial statements refers to the Company and its subsidiaries.  All inter-entity transactions have been eliminated.

The financial statements have been prepared on the historical cost basis with the exception of the following which are measured at fair value:

●    available-for-sale assets; and

●    derivative financial instruments.

These financial statements were authorized for issue by the Board of Directors on November 2, 2011.

3.  SUMMARY OF ACCOUNTING POLICIES

Revenue Recognition

Revenue associated with the sale of crude oil, natural gas, and natural gas liquids (“NGLs”) owned by ARC are recognized when the risks and rewards of ownership are transferred from ARC to its customers. Revenue is presented net of royalties accrued.

Transportation

Costs paid by ARC for the transportation of natural gas, crude oil and NGLs from the wellhead to the point of title transfer are recognized when the transportation is provided.

Joint Interests

ARC conducts many of its oil and gas production activities through jointly controlled assets and the financial statements reflect only ARC’s proportionate interest in such activities.

Page 33

Long-Term Incentive Plans

Restricted Share Unit & Performance Share Unit and Deferred Share Unit Plans

ARC has established a cash-settled Restricted Share Unit & Performance Share Unit Plan (“RSU & PSU Plan”) for employees, independent directors and long-term consultants who otherwise meet the definition of an employee of ARC as well as a Deferred Share Unit Plan (“DSU Plan”) for non-employee directors.  Compensation expense associated with the RSU & PSU plan and the DSU plan is granted in the form of Restricted Share Units (“RSUs”), Performance Share Units (“PSUs”) and Deferred Share Units (“DSUs”) and is determined based on the fair value of the share units at grant date and is subsequently adjusted to reflect the fair value of the share units at each period end.  This valuation incorporates the period-end share price, the number of RSUs, PSUs and DSUs outstanding at each period end, and certain management estimates.  As a result, large fluctuations, even recoveries, in compensation expense may occur due to changes in the underlying share price.  In addition, compensation expense is amortized and recognized in earnings over the vesting period of the RSU & PSU plan and DSU plan with a corresponding increase or decrease in liabilities.  Classification between accrued liabilities and accrued long term incentive compensation is dependent on the expected payout date.

Share Option Plan

ARC has established a share option plan for certain employees and consultants that will settle through the issuance of equity.  The fair value of share options is determined on their grant date using a valuation model and recorded as compensation expense over the period that the share options vest, with a corresponding increase to contributed surplus.  The exercise price of the share options granted may be reduced by the amount of dividends declared in future periods in accordance with the terms of the plan.  Forfeitures are estimated through the vesting period based on past experience and future expectations, and adjusted upon actual vesting.  When share options are exercised, the proceeds, together with the amounts recorded in contributed surplus, are recorded in shareholders’ capital.

Cash Equivalents

Cash equivalents include market deposits and similar type instruments, with an original maturity of three months or less when purchased.

Reclamation Funds

Reclamation funds hold investment grade assets and cash and cash equivalents.  Investments are categorized as available-for-sale assets. Available-for-sale assets are initially measured at fair value with subsequent changes in fair value recognized in other comprehensive income, net of tax.

Goodwill

ARC records goodwill relating to a business combination when the total purchase price exceeds the fair value of the identifiable assets and liabilities of the acquired company.  Goodwill is stated at cost less any accumulated impairment losses.

Intangible Exploration and Evaluation Assets (“E&E”)

Intangible exploration and evaluation costs are capitalized within E&E until the technical feasibility and commercial viability, or otherwise, of the project has been determined.  Such E&E costs may include costs of license acquisition, technical services and studies, and exploration drilling and testing.  Tangible assets acquired which are consumed in developing an intangible exploration asset are recorded as part of the cost of the intangible exploration asset.

If an E&E project is determined to be unsuccessful, all associated costs are charged to the income statement.

If commercial reserves are established for a project classified as E&E the relevant cost is transferred from E&E to development and production assets, classified as property, plant and equipment on the consolidated balance sheet.  Assets are reviewed for impairment prior to any such transfer.

Assets classified as E&E are not amortized.

Costs incurred prior to obtaining the legal right to explore are expensed as incurred.

Page 34

Property, Plant and Equipment (“PP&E”)

Items of PP&E, which include oil and gas development and production assets and corporate assets, are measured at cost less accumulated depletion, depreciation and amortization and accumulated impairment losses.

Gains and losses on disposal of an item of PP&E are determined by comparing the proceeds from disposal with the carrying amount of PP&E and are recognized separately in the statement of income.

Exchanges of properties are measured at fair value, unless the transaction lacks commercial substance or fair value cannot be reasonably measured.  Where the exchange is measured at fair value, a gain or loss is recognized in the statement of income.

Overhead costs which are directly attributable to bringing an asset to the location and condition necessary for it to be capable of use in the manner intended by management are capitalized.  These costs include compensation costs paid to internal personnel dedicated to capital projects.

Depletion, Depreciation and Amortization

Development and production assets are componentized into groups of assets with similar useful lives for the purposes of performing depletion calculations.  Depletion expense is calculated on the unit-of-production basis based on:

(a) total estimated proved and probable reserves calculated in accordance with Ontario Securities Commission’s National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities;

(b) total capitalized costs plus estimated future development costs of proved and probable reserves, including future estimated asset retirement costs; and

(c) relative volumes of petroleum and natural gas reserves and production, before royalties, converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil.

Depreciation of corporate assets is calculated on a straight-line basis over the useful life of the related assets.

Impairment

Development and Production Assets

ARC’s development and production assets are grouped into cash generating units (“CGUs”) for the purpose of assessing impairment.  A CGU is a grouping of assets that generate cash flows independently of other assets held by the Company.   Geological formation, product type, geography and internal management are key factors considered when grouping ARC’s oil and gas assets into CGUs.

CGUs are reviewed at each reporting date for indicators of potential impairment.  If such indicators exist, an impairment test is performed by comparing the CGU’s carrying value to its recoverable amount, defined as the greater of a CGU’s fair value less cost to sell and its current value in use.  Any excess of carrying value over recoverable amount is recognized in the income statement as an impairment charge, included within depletion, depreciation and amortization.

If there is an indicator that a previously recognized impairment charge may no longer be valid, the recoverable amount of the relevant CGU is calculated and compared against the carrying amount.  An impairment charge is reversed to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion, if no impairment loss had been recognized.

E&E, Corporate Assets and Goodwill

E&E, corporate assets and goodwill are assessed for impairment at the operating segment level.  Impairment tests are carried out when E&E assets are transferred to development and production assets following the declaration of commercial reserves, and any time that circumstances arise which could indicate a potential impairment.  Irrespective of whether or not there is any indication of impairment, goodwill balances are tested for impairment annually.  An impairment loss is recognized if the total carrying values of E&E, corporate assets and goodwill exceed the aggregate impairment cushions calculated for each of ARC’s CGUs and is applied first to reduce the carrying amount of goodwill and then to E&E and corporate assets on a pro-rata basis.  Any impairment loss of goodwill is not reversed.

If E&E, corporate assets and goodwill are subject to impairment testing in the same period in which there is an indication of impairment in one of ARC’s CGUs, that CGU is first tested for impairment and any resulting impairment loss is recorded prior to conducting impairment tests on assets at the operating segment level.

Page 35

Assets Held for Sale

Non-current assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use.  This condition is met when the sale is highly probable and the asset is available for immediate sale in its present condition.

Non-current assets classified as held for sale are measured at the lower of the carrying amount and fair value less costs to sell, with impairments recognized in the consolidated statement of income in the period measured.  Non-current assets held for sale are presented in current assets and liabilities within the consolidated balance sheet.  Assets held for sale are not depleted, depreciated or amortized.

Asset Retirement Obligations

ARC recognizes an asset retirement obligation (“ARO”) in the period in which it has a present legal or constructive liability and a reasonable estimate of the amount can be made.  On a periodic basis, management reviews these estimates and changes, if any, are applied prospectively.  The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase to the carrying amount of the related asset.  The capitalized amount is depreciated on a unit-of-production basis over the life of the associated proved plus probable reserves.  The long-term liability is increased each reporting period with the passage of time and the associated accretion charge is recognized in earnings.  Periodic revisions to the liability specific discount rate, estimated timing of cash flows or to the original estimated undiscounted cost can also result in an increase or decrease to the ARO.  Actual costs incurred upon settlement of the obligation are recorded against the ARO to the extent of the liability recorded.

Deferred Taxes

Deferred tax is recognized using the balance sheet 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 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 substantively enacted by the reporting date.

Deferred income tax expense is recognized in comprehensive income except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Deferred tax assets and tax liabilities are offset to the extent there is a legal right to settle on a net basis.

Financial Instruments

Financial assets, financial liabilities and derivatives are measured at fair value on initial recognition.  Measurement in subsequent periods depends on the financial instrument’s classification, as described below.

a. Fair value through profit and loss

Financial assets and liabilities designated as fair value through profit and loss are subsequently measured at fair value with changes in those fair values charged immediately to earnings.  With the exception of risk management contracts that qualify for hedge accounting, ARC classifies all risk management contracts and short term investments as fair value through profit and loss.  Cash and cash equivalents are also classified as fair value through profit and loss.

b. Available-for-sale assets

Available-for-sale financial assets are subsequently measured at fair value with changes in fair value recognized in Other Comprehensive Income (“OCI”), net of tax.  Amounts recognized in OCI for available-for-sale financial assets are charged to earnings when the asset is derecognized or when there is an other than temporary asset impairment.  ARC classifies its reclamation fund assets as available-for-sale assets.

c. Held-to-maturity investments, loans and receivables and other financial liabilities

Held-to-maturity investments, loans and receivables, and other financial liabilities are subsequently measured at amortized cost using the effective interest method.  ARC classifies accounts receivable to loans and receivables, and accounts payable, accrued long-term incentive compensation, dividends payable and long-term debt to other financial liabilities.

For derivative instruments that qualify as effective accounting hedges, policies and procedures are in place to ensure that the required documentation and approvals are obtained.  This documentation specifically ties the derivative financial instruments to their use, and in the case of commodities, to the mitigation of market price risk associated with cash flows expected to be generated.  When applicable, ARC also identifies all relationships between hedging instruments and hedged items, as well as its risk management objective and the strategy for undertaking hedge transactions.  This would include linking the particular derivative to specific assets and liabilities on the consolidated balance sheet or to specific firm commitments or forecasted transactions.

Page 36

Where specific hedges are executed, ARC assesses, both at the inception of the hedge and on an ongoing basis, whether the derivative used in the particular hedging transaction is effective in offsetting changes in fair value or cash flows of the hedged item.   Hedge accounting is discontinued prospectively when the derivative no longer qualifies as an effective hedge, or the derivative is terminated or sold, or upon the sale or early termination of the hedged item.

In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in OCI while the ineffective portion is recognized in earnings.  When hedge accounting is discontinued, the amounts previously recognized in Accumulated Other Comprehensive Income (“AOCI”) are reclassified to earnings during the periods when the variability in the cash flows of the hedged item affects earnings.  Gains and losses on derivatives are reclassified immediately to earnings when the hedged item is sold or early terminated.

When hedge accounting is applied to a derivative used to hedge an anticipated transaction and it is determined that the anticipated transaction will not occur within the originally specified time period, hedge accounting is discontinued and the unrealized gains and losses are reclassified from AOCI to earnings.

Exchangeable Shares

ARC’s exchangeable shares were derivative financial liabilities measured at fair value with changes in fair value recorded on the income statement.

Foreign Currency Translation

Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at the consolidated balance sheet date.  Revenues and expenses are translated at the period average rates of exchange.  Translation gains and losses are included in earnings in the period in which they arise.

ARC’s functional and presentation currency is Canadian dollars.

4.  NEW ACCOUNTING POLICIES

Current Year Accounting Changes

2011 is ARC’s first year reporting its financial statements under IFRS, commencing with the three months ended March 31, 2011.  Accounting standards issued to date effective for periods beginning on or after January 1, 2011 have been adopted as part of the transition to IFRS.

Future Accounting Changes

ARC has reviewed new and revised accounting pronouncements that have been issued but are not yet effective and determined that the following may have an impact on the Company:

As of January 1, 2015 , ARC will be required to adopt IFRS 9 “Financial Instruments”, which is the result of the first phase of the International Accounting Standards Board (“IASB”) project to replace IAS 39 “Financial Instruments:  Recognition and Measurement”.  The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories:  amortized cost and fair value.  Portions of the standard remain in development and the full impact of the standard on ARC’s Consolidated Financial Statements will not be known until the project is complete.

In May 2011, the IASB released the following new standards: IFRS 10, “Consolidated Financial Statements”, IFRS 11, “Joint Arrangements”, IFRS 12, “Disclosures of interests in other entities” and IFRS 13, “Fair Value Measurement”.  Each of these standards is to be adopted for fiscal years beginning January 1, 2013 with earlier adoption permitted.  A brief description of each new standard follows below:

●    IFRS 10, “Consolidated Financial Statements” supercedes IAS 27 “Consolidation and Separate Financial Statements” and SIC-12 “Consolidation – Special Purpose Entities”.  This standard provides a single model to be applied in control analysis for all investees including special purpose entities.

●    IFRS 11, “Joint Arrangements” divides joint arrangements into two types, joint operations and joint ventures, each with their own accounting model.  All joint arrangements are required to be reassessed on transition to IFRS 11 to determine their type to apply the appropriate accounting.

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●    IFRS 12, “Disclosure of Interests in Other Entities” combines in a single standard the disclosure requirements for subsidiaries, associates and joint arrangements as well as unconsolidated structured entities.

●    IFRS 13, “Fair Value Measurement” defines fair value, establishes a framework for measuring fair value and sets out disclosure requirements for fair value measurements.  This standard defines fair value as 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.

ARC is currently analyzing the expected impact, if any, that the adoption of each of these standards will have on its Consolidated Financial Statements.

5.  MANAGEMENT JUDGEMENTS AND ESTIMATION UNCERTAINTY

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingencies at the date of the financial statements, and revenues and expenses during the reporting year.  Actual results could differ from those estimated.  The key sources of estimation uncertainty that have a significant risk of causing material adjustment to the carrying amounts of assets and liabilities are discussed below.

Recoverability of asset carrying values

The recoverability of asset carrying values are assessed at the CGU level.  Determination of what constitutes a CGU is subject to management judgments.  The asset composition of a CGU can directly impact the recoverability of the assets included therein.  In assessing the recoverability of oil and gas properties, each CGU’s carrying value is compared to its recoverable amount, defined as the greater of its fair value less cost to sell and value in use.

At September 30, 2011 the recoverable amounts of ARC’s CGUs were estimated as their fair value less cost to sell based on the following information:

i)     the net present value of the after-tax cash flows from oil and gas reserves of each CGU based on reserves estimated by ARC’s independent reserve evaluator; and

ii)     the fair value of undeveloped land;

iii)     with consideration give to acquisition metrics of recent transactions completed on similar assets to those contained within the relevant CGU.

Key input estimates used in the determination of cash flows from oil and gas reserves include the following:

a)     Reserves.  Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available.  Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated.

b)     Oil and natural gas prices.  Forward price estimates of the oil and natural gas prices are used in the cash flow model.  Commodity prices have fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, exchange rates, weather, economic and geopolitical factors.

c)     Discount rate.  The discount rate used to calculate the net present value of cash flows is based on estimates of an approximate industry peer group weighted average cost of capital.  Changes in the general economic environment could result in significant changes to this estimate.

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Impairment tests were carried out at September 30, 2011 and were based on fair value less costs to sell calculations, using a discount rate of 10 per cent and the following forward commodity price estimates:

	WTI Oil			AECO Gas			Cdn$/US$
Year	(US$/bbl)(1)			(Cdn$/mmbtu)(1)			Exchange Rates(1)
2011		93.64			3.83			1.012
2012		90.00			4.39			0.980
2013		95.00			4.64			0.980
2014		100.00			5.15			0.980
2015		100.00			5.66			0.980
2016		100.00			6.17			0.980
2017		101.36			6.68			0.980
2018		103.38			7.16			0.980
2019		105.45			7.32			0.980
2020		107.56			7.47			0.980
Remainder		2.0	%		2.0	%		0.980

(1)  Source:  GLJ Petroleum Consultants price forecast, effective October 1, 2011.

Due to the strengthening of forward commodity price estimates a $28.4 million recovery of a previously recorded impairment loss in the Southern Alberta and Southwest Saskatchewan CGU was recognized at March 31, 2011.

At September 30, 2011 an impairment test was performed on each CGU, as the carry value of the Southern Alberta and Southwest Saskatchewan CGU exceeded the fair value less costs to sell, an impairment was recognized for approximately $45.1 million.

A one per cent increase in the assumed discount rate would result in an additional impairment of $87.6 million for the nine months ended September 30, 2011, while a five per cent decrease in the forward commodity price estimate would result in an additional impairment of approximately $122.2 million.

The carrying value of goodwill at September 30, 2011 is $248.2 million.  This value is supported by the combined excess recoverable amount over the current carrying value of ARC’s six CGUs.

Depletion of oil and gas assets

Depletion of oil and gas assets is determined based on total proved and probable reserve values as well as future development costs as estimated by ARC’s external reserve evaluator.  See (a) above for discussion of estimates and judgements involved in reserve estimation.

Asset retirement obligation

The provision for site restoration and abandonment is based on current legal and constructive requirements, technology, price levels and expected plans for remediation.  Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, market conditions, discovery and analysis of site conditions and changes in technology.

Derivative Instruments

The estimated fair value of derivative instruments resulting in financial assets and liabilities, by their very nature are subject to measurement uncertainty.

Employee Compensation Costs

Compensation expense accrued for ARC’s Performance Share Unit Plan is dependent on an adjustment to the final number of PSU awards that eventually vest based on a performance multiplier.  The determination of the performance multiplier is subject to management estimation.

Compensation expense recorded for ARC’s Share Option Plan is based on a binomial-lattice option pricing model.  The inputs to this model rely on management judgment.

Deferred Taxes

Tax interpretations, regulations and legislation are subject to change and as such income taxes are subject to measurement uncertainty.  Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.

6.  CASH AND CASH EQUIVALENTS

Cash and cash equivalents included restricted cash amounts of $1.7 million at December 31, 2010. This balance represented amounts received from a government agency to fund certain future capital expenditures of the Company.  As qualifying expenditures under the funding agreement are not expected to be made, the undrawn cash plus interest accrued to date was repaid on September 30, 2011.

The remaining cash balance of $0.5 million at September 30, 2011 and $0.3 million at December 31, 2010 (nil at January 1, 2010) was held in investment grade assets.

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7.  INTANGIBLE EXPLORATION AND EVALUATION ASSETS (“E&E”) AND GOODWILL

The following table reconciles ARC’s E&E assets and goodwill:

	E&E			Goodwill
Balance, January 1, 2010	$	23.0		$	157.6
Additions		52.2			-
Acquisition through business combinations		-			90.6
Unsuccessful exploration and evaluation costs		(0.8	)		-
Balance, December 31, 2010	$	74.4		$	248.2
Additions		95.0			-
Balance, September 30, 2011	$	169.4		$	248.2

8.  PROPERTY, PLANT AND EQUIPMENT

The following table reconciles ARC’s property, plant and equipment:

Cost	Development and Production Assets			Administrative Assets
Balance, January 1, 2010	$	3,537.5		$	12.9
Additions		573.0			28.5
Acquisition through business combinations		712.7			-
Assets reclassified as held for sale		(123.9	)		-
Balance, December 31, 2010	$	4,699.3		$	41.4
Additions		604.2			3.0
Assets reclassified as held for sale		(13.2	)		-
Balance, September 30, 2011	$	5,290.3		$	44.4

Depletion, depreciation and amortization
Balance, January 1, 2010	$	-		$	-
Depletion, depreciation and amortization		(363.7	)		(3.1	)
Impairment loss (Note 5)		(30.7	)		-
Balance, December 31, 2010	$	(394.4	)	$	(3.1	)
Depletion, depreciation and amortization		(310.3	)		(4.2	)
Impairment loss (Note 5)		(16.6	)		-
Accumulated depletion reclassified as held for sale		1.7
Balance, September 30, 2011	$	(719.6	)	$	(7.3	)

Carrying amounts

As at January 1, 2010	3,537.5	12.9
As at December 31, 2010	4,304.9	38.3
As at September 30, 2011	4,570.7	37.1

For the nine months ended September 30, 2011 $16.6 million (2010 - $13.4 million) of general and administrative expenses were capitalized to property, plant and equipment.  In the third quarter of 2011, $7.9 million (2010 - $4.9 million) of general and administrative expenses were capitalized to property, plant and equipment.  For the year ended December 31, 2010, $20.9 million of general and administrative expenses were capitalized.

For the nine months ended September 30, 2011 ARC disposed of $132.6 million of PP&E that was classified as held for sale of which $123.9 million was classified as held for sale as at December 31, 2010.  Gains totaling $92.7 million were recognized in the statement of income in respect of these disposals.

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Assets held for sale
Balance, January 1, 2010	$	-		$	-
Additions		123.9			-
Balance, December 31, 2010	$	123.9		$	-
Additions		13.2			-
Disposals		(132.6	)		-
Balance, September 30, 2011	$	4.5		$	-

9.  LONG-TERM DEBT

		September 30, 2011		December 31, 2010
Syndicated credit facilities:
Cdn$ denominated	$	221.1	$	357.7
US$ denominated		-		-
Working capital facility		4.8		1.3
Senior notes:
Master Shelf Agreement
5.42% US$ Note		68.2		65.3
4.98% US$ Note		52.0		49.7
2004 Note Issuance
4.62% US$ Note		20.0		25.5
5.10% US$ Note		25.0		23.9
2009 Note Issuance
7.19% US$ Note		70.1		67.1
8.21% US$ Note		36.3		34.8
6.50% Cdn$ Note		29.0		29.0
2010 Note Issuance
5.36% US$ Note		155.8		149.2
Total long-term debt outstanding	$	682.3	$	803.5

Of the total amount of long-term debt outstanding at September 30, 2011,  $35.4 million is classified as current as it will be repaid or refinanced within the next twelve months ($15.7 million at December 31, 2010 and $20.7 million at January 1, 2010).

The fair value of all senior notes as at September 30, 2011, is $500.8 million compared to a carrying value of $456.4 million ($468.1 million compared to $444.5 million as at December 31, 2010).

10.  ASSET RETIREMENT OBLIGATIONS

The following table reconciles ARC’s provision for asset retirement obligations:

	Nine Months Ended September 30, 2011			Year Ended December 31, 2010
Balance, beginning of period	$	381.7		$	298.1
Increase in liabilities relating to corporate acquisitions		-			21.8
Increase in liabilities relating to development activities		4.4			4.6
Increase in liabilities relating to change in estimate and discount rate		89.4			64.3
Settlement of reclamation liabilities during the period		(5.0	)		(7.8	)
Accretion expense		10.1			12.6
Reclassified as liabilities directly associated with assets held for sale		(2.1	)		(11.9	)
Balance, end of period	$	478.5		$	381.7

The risk-free discount rate used to value ARC’s asset retirement obligations as at September 30, 2011 was 2.77 per cent (3.52 per cent as at December 31, 2010).

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11.  RISK MANAGEMENT CONTRACTS

ARC uses a variety of derivative instruments to reduce its exposure to fluctuations in commodity prices, foreign exchange rates, interest rates and power prices.  ARC considers all of these transactions to be effective economic hedges; however, the majority of ARC’s contracts do not qualify as effective hedges for accounting purposes.

Following is a summary of all risk management contracts in place as at September 30, 2011 that do not qualify for hedge accounting:

Financial WTI Crude Oil Contracts
			Volume	Bought Put	Sold Put	Sold Call	Bought Call
Term		Contract	bbl/d	$/bbl	$/bbl	$/bbl	$/bbl
1-Jan-11	31-Dec-11	3-Way	5,000	US$80.00(1)	US$60.00(1)	US$100.00(2)	-
1-Jan-11	31-Dec-11	Collar	8,000	US$85.00(1)	-	US$85.00(2)	-
1-Jan-11	31-Dec-11	3-Way	5,000	US$85.00(1)	US$60.00(1)	US$85.00(2)	-
1-Jan-11	31-Dec-11	3-Way	2,000	C$90.00(1)	C$65.00(1)	C$90.00(2)	-
1-Jan-12	31-Dec-12	Collar	1,000	US$90.00(1)	-	US$90.00(2)	-
1-Jan-12	31-Dec-12	3-Way	5,000	US$90.00(1)	US$60.00(1)	US$90.00(2)	-
1-Jan-12	31-Dec-12	Collar	10,000	US$90.00(1)	-	US$90.00(1)	-
1-Jan-12	31-Dec-12	Collar	4,000	-	US$70.00(1)	-	US$120.00(1)
1-Jan-12	31-Dec-12	Collar	3,000	-	US$65.00(1)	-	US$115.00(1)
1-Jan-12	31-Dec-12	Collar	2,000	-	US$60.00(1)	-	US$105.00(1)
1-Jan-13	30-Jun-13	Collar	2,000	US$90.00(1)	-	US$110.00(2)	-

(1)  Settled on the monthly average price

(2) Settled on the term average price

Financial WTI Crude Oil Calendar Spread Contracts(3)
			Volume	Spread
Term		Contract	bbl/d	US$/bbl
1-Oct-11	31-Dec-11	1st vs. 2nd Month	2,000	($0.07)
1-Jan-12	31-Dec-12	1st vs. 2nd Month	4,000	$0.12

(3)  ARC pays the prompt contract monthly average; ARC receives the second delivery month contract average plus the calendar spread

Financial AECO Natural Gas Contracts(4)
			Volume	Sold Swap
Term		Contract	GJ/d	$C/GJ
1-Oct-11	31-Dec-11	Swap	135,000	$5.54
1-Oct-11	31-Oct-11	Bought Put	60,000	$3.75

(4)  AECO Monthly (7a) Index

Financial NYMEX Natural Gas Swap Contracts(5)
			Volume		Bought Put
Term		Contract	GJ/d		$C/GJ
1-Oct-11	31-Oct-11	Swap		45,000	$4.60
1-Nov-11	31-Mar-11	Swap		10,000	$5.02
1-Jan-12	31-Mar-12	Swap		45,000	$5.03
1-Apr-12	31-Oct-12	Swap		65,000	$4.94
1-Jan-12	31-Dec-12	Swap		25,000	$5.08

(5)  Last Day Settlement

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Financial Basis Swap Contracts
			Volume		Sold Swap		Ratio Sold Swap
Term		Contract	mmbtu/d		US$/mmbtu(6)		AECO/NYMEX (7)
1-Oct-11	31-Oct-11	L3d Settlement		15,000		($0.4850)
1-Oct-11	31-Oct-11	Ld Settlement		15,000		($0.2242)
1-Oct-11	31-Dec-12	Ld Settlement		30,000		($0.6067)
1-Nov-11	31-Oct-12	L3d Settlement		15,000		($0.4067)
1-Jan-12	31-Oct-12	Ld Settlement		30,000		($0.4483)
1-Jan-12	31-Dec-12	Ld Settlement		20,000		($0.5988)
1-Jan-12	31-Dec-12	Ld Settlement		20,000			0.9012

(6)  ARC receives Nymex price based on Last Day (Ld) or Last 3 Day (L3d) settlement less fixed basis; ARC pays AECO (7a) monthly index $US/mmbtu

(7)  ARC receives Nymex price based on Last Day (Ld) settlement multiplied by AECO/NYMEX $US/mmbtu ratio; ARC pays AECO (7a) monthly index $US/mmbtu

US$ Long Term Principal and Interest Debt repayment (8)
Forward Date	Contract	Notional US$	CDN$/US$	US$/CDN$
12-Dec-12	USD Purchased Forward	$10,000,000	$0.9880	$1.0121

(8)  Based on ARC’s private note repayment commitments

Financial Electricity Heat Rate Contracts (9)
			Volume	AESO Power	AECO 5(a)	multiplied	Heat Rate
Term		Contract	MWh	$C/MWh	$C/GJ	by	GJ/MWh
1-Oct-11	31-Dec-11	Heat Rate Swap	15	Receive AESO	Pay AECO 5(a)	X	9.08
1-Jan-12	31-Dec-12	Heat Rate Swap	15	Receive AESO	Pay AECO 5(a)	X	9.10
1-Jan-13	31-Dec-13	Heat Rate Swap	10	Receive AESO	Pay AECO 5(a)	X	9.15

(9)  Alberta Power Pool (monthly average 24x7); AECO Monthly (5a) index

Financial Electricity Contracts (10)
			Volume	Bought Swap
Term		Contract	MWh	Cdn$/MWh
1-Oct-11	31-Dec-12	Swap	5	$72.50

(10)  Alberta Power Pool (monthly average 24x7)

At September 30, 2011, the net fair value associated with ARC’s risk management contracts was $88.1 million ($24.5 million at December 31, 2010).  ARC recorded gains on risk management contracts for the three months ended September 30, 2011 of $178.7 million and a gain of $155.4 million for the nine months ended September 30, 2011 in its statement of income (gains of $49.1 million and $159.5 million for the three and nine months ended September 30, 2010, respectively).

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12.  SHAREHOLDERS’ CAPITAL

(thousands of units)	Nine Months Ended September 30, 2011		Year Ended December 31, 2010
Trust units , beginning of period		-		236,615
Equity offering		-		13,000
Issued on conversion of ARL exchangeable shares		-		424
Issued for acquisition consideration		-		23,003
Distribution reinvestment program		-		3,683
Exchanged pursuant to the Arrangement		-		(276,725	)
Trust units, end of period		-		-

(thousands of shares)	Nine Months Ended September 30, 2011		Year Ended December 31, 2010
Common shares, beginning of period		284,379		-
Issued for trust units pursuant to the Arrangement		-		276,725
Issued for ARL exchangeable shares pursuant to the Arrangement		-		7,654
Dividend reinvestment program		3,331		-
Common shares, end of period		287,710		284,379

Net income per common share has been determined based on the following:

(thousands of shares)	Nine Months Ended September 30, 2011		Nine Months Ended September 30, 2010
Weighted average common shares		286,008		254,441
Diluted common shares		286,008		257,656

Dividends for the three and nine months ended September 30, 2011 are $0.30 and $0.90 per share, respectively ($0.30 and $0.90 per unit for the three and nine months ended September 30, 2010).

For the three and  nine months ended September 30, 2011 the share options outstanding were anti-dilutive and were not included in the diluted common shares calculation.

On October 17, 2011 the Board of Directors declared a dividend of $0.10 per common share, payable in cash, to shareholders of record on October 31, 2011.  The dividend payment date is November 15, 2011.

13.  LONG TERM INCENTIVE PLANS

RSU & PSU Plan

Compensation associated with the RSU & PSU Plan is granted in the form of RSUs and PSUs and is determined based on the fair value of the RSUs and PSUs at the date of grant, adjusted to the current fair value of outstanding awards at each period end.  Upon vesting, the plan participant receives a cash payment based on the fair value of the underlying shares plus accrued dividends.

A portion of total compensation costs associated with the RSU & PSU Plan is charged to property, plant and equipment to reflect those costs that are directly attributable to spending on capital projects, a portion is charged to operating expenses to reflect the awards that are attributable to certain individuals working in field operations, and the remainder is charged to general and administrative expense.

DSU Plan

Effective January 1, 2011, ARC offers a DSU Plan to non-employee directors, under which each director receives a minimum of 55 per cent of their total annual remuneration in the form of DSUs.  Each DSU fully vests on the date of grant, but is distributed only when the director has ceased to be a member of the Board of Directors of the Company.  Compensation expense associated with the DSU Plan is based on the fair value of DSUs at the date of grant, adjusted to the current fair value of outstanding awards at each period end.  Units are settled in cash based on the common share price plus accrued dividends.  Compensation expense relating to the DSU Plan is charged to general and administrative expense.

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The following table summarizes the RSU, PSU and DSU movement for the nine months ended September 30, 2011:

(number of units, thousands)	RSUs			PSUs			DSUs
Balance, beginning of period		1,017			1,301			-
Granted		376			520			48
Distributed		(474	)		(304	)		-
Forfeited		(55	)		(51	)		-
Balance, end of period		864			1,466			48

Compensation charges relating to the RSU & PSU and DSU Plans can be reconciled as follows:

	Nine Months Ended September 30, 2011		Nine Months Ended September 30, 2010
General and administrative expense		19.2		12.9
Operating expense		3.2		3.2
Property, plant and equipment		1.6		2.7
Total compensation charges	$	24.0	$	18.8
Cash payments	$	28.1	$	28.6

At September 30, 2011 $30.3 million of compensation amounts payable were included in accounts payable and accrued liabilities on the Condensed Consolidated Balance Sheet ($22.7 million at December 31, 2010 and $22.4 million at January 1, 2010), and $15.7 million was included in long-term incentive compensation liability ($26.6 million at December 31, 2010 and $10.9 million at January 1, 2010).  A recoverable amount of $0.7 million was included in accounts receivable at September 30, 2011 ($1 million at December 31, 2010 and $0.7 million at January 1, 2010).

Share Option Plan

Effective January 1, 2011 ARC implemented a share option plan.  Share options are granted to officers, certain employees and certain consultants of ARC which vest evenly on the fourth and fifth anniversary of their grant date and have a maximum term of seven years.  The option holder has the right to exercise the options at the original grant price or at a reduced exercise price, equal to the grant price less all dividends paid subsequent to the grant date and prior to the exercise date.

ARC recorded compensation expense of $0.3 million relating to the share option plan for the nine months ended September 30, 2011.

ARC estimated the fair value of the share options granted using a binomial-lattice option pricing model.  The grant date fair value of the share option plan was $3.6 million, or $8.40 per option outstanding at September 30, 2011.  The following assumptions were used to arrive at the estimated fair value at the date of the options grant:

Weighted average share price	$	27.11
Exercise price	$	27.11
Expected annual dividends	$	1.20
Expected volatility (1)		37.00	%
Risk-free interest rate		2.61	%
Expected life of share option	5.5 to 6 years

(1) Expected volatility is determined by the average price volatility of the common shares/trust units over the past seven years.

The number of share options outstanding and related exercise prices are as follows:

	Number of share options outstanding			Weighted average exercise price
Balance, beginning of year		-		$	-
Granted		430,990			27.11
Exercised		-			-
Forfeited		(10,083	)		27.11
Balance, September 30, 2011		420,907		$	27.11
Exercisable, September 30, 2011		-		$	-

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14.  COMMITMENTS AND CONTINGENCIES

Following is a summary of ARC’s contractual obligations and commitments as at September 30, 2011:

	Payments Due by Period
($ millions)	1 year		2–3 years		4-5 years		Beyond 5 years		Total
Debt repayments (1)		46.0		82.5		311.0		242.8		682.3
Interest payments (2)		26.3		45.3		34.6		45.5		151.7
Reclamation fund contributions (3)		4.4		7.9		6.8		58.3		77.4
Purchase commitments		45.6		30.1		11.3		6.1		93.1
Transportation commitments (4)		17.7		45.5		27.1		0.5		90.8
Operating leases		10.8		18.2		16.0		63.2		108.2
Risk management contract premiums (5)		1.6		0.2		-		-		1.8
Total contractual obligations		152.4		229.7		406.8		416.4		1,205.3

(1) Long-term and short-term debt.

(2) Fixed interest payments on senior notes.

(3) Contribution commitments to a restricted reclamation fund associated with the Redwater property.

(4) Fixed payments for transporting production from the Dawson gas plant.

(5) Fixed premiums to be paid in future periods on certain commodity risk management contracts.

In addition to the above risk management contract premiums, ARC has commitments related to its risk management program (see Note 11).  As the premiums are part of the underlying risk management contract, they have been recorded at fair market value at September 30, 2011 on the balance sheet as part of risk management contracts.

ARC enters into commitments for capital expenditures in advance of the expenditures being made.  At a given point in time, it is estimated that ARC has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the expenditures in a future period.

ARC is involved in litigation and claims arising in the normal course of operations.  Management is of the opinion that it has made adequate provision for such legal claims.

15.  SUPPLEMENTAL DISCLOSURES

Income Statement Presentation

The following table details the amount of total employee compensation costs included in the operating and general and administrative expense line items in the statement of income.

	Three Months Ended September 30				Nine Months Ended September 30
	2011		2010		2011		2010
Operating	$	6.4	$	6.0	$	19.0	$	16.9
General and administrative		18.9		15.2		54.3		45.7
Total employee compensation costs	$	25.3	$	21.2	$	73.3	$	62.6

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Cash Flow Statement Presentation

The following tables provide a detailed breakdown of certain line items contained within cash flow from operating activities.

Changes in Non-Cash Working Capital

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
Accounts receivable	$	0.1		$	(7.8	)	$	12.5		$	(7.7	)
Accounts payable and accrued liabilities		49.2			27.9			67.4			38.6
Prepaid expenses		(5.0	)		(3.1	)		(4.5	)		3.1
Total		44.3			17.0			75.4			34.0
Relating to:
Operating activities		2.4			4.4			31.2			11.3
Investing activities		41.9			12.6			44.2			22.7
Total	$	44.3		$	17.0		$	75.4		$	34.0

Other Non-Cash Items

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011		2010
Non-cash lease inducement	$	(0.6	)	$	2.0		$	0.8	$	4.7
Loss on revaluation of exchangeable shares		-			8.7			-		9.4
Loss (Gain) on short term investments		1.2			(0.9	)		0.3		(0.9	)
Share option expense		0.1			-			0.3		-
Total other non-cash items	$	0.7		$	9.8		$	1.4	$	13.2

Other Liabilities

	Three Months Ended September 30						Nine Months Ended September 30
	2011			2010			2011			2010
Long-term incentive compensation liability	$	(3.5	)	$	-		$	(8.7	)	$	0.6
Abandonment expenditures		(1.6	)		(1.4	)		(5.0	)		(5.1	)
Total other liabilities	$	(5.1	)	$	(1.4	)	$	(13.7	)	$	(4.5	)

16.  EXPLANATION OF TRANSITION TO INTERNATIONAL FINANCIAL REPORTING STANDARDS

The condensed interim consolidated financial statements for the period ended March 31, 2011 were the Company’s first financial statements prepared under IFRS.  For all annual and interim periods prior to that date, the Company prepared its financial statements under Canadian generally accepted accounting principles (“GAAP”).

IFRS 1 First-time Adoption of International Financial Reporting Standards sets forth guidance for the initial adoption of IFRS.  Under IFRS 1 the standards are applied retrospectively at the transitional balance sheet date with all adjustments to assets and liabilities recognized in retained earnings unless certain exemptions are applied.  The Company has applied the following optional exemptions to its opening balance sheet dated January 1, 2010:

(a)   Business Combinations

IFRS 1 indicates that a first-time adopter may elect not to apply IFRS 3 Business Combinations retrospectively to business combinations that occurred before the date of transition to IFRS.  ARC has taken advantage of this exemption and has applied IFRS 3 only to business combinations that occurred on or after January 1, 2010.

(b)   Deemed Cost

IFRS requires that property, plant and equipment associated with oil and natural gas development and production be monitored and depreciated at a more granular level than was required under full cost accounting allowable under Canadian GAAP.  The deemed cost exemption contained within IFRS 1 allows companies using full cost accounting under their previous GAAP to elect that the deemed cost of their oil and gas property, plant and equipment at transition date be equal to their historic carrying value under Canadian GAAP.   ARC has applied this exemption at January 1, 2010 and accordingly has measured its property, plant and equipment on the following basis:

Page 47

●    Exploration and evaluation assets at their carrying value under Canadian GAAP; and

●    Development and production assets at the amount determined by allocating their total net book value under Canadian GAAP on a pro rata basis using discounted proved plus probable reserve values.

(c)   Borrowing Costs

IFRS 1 indicates that a first-time adopter may elect not to apply IAS 23 Borrowing Costs retrospectively, but rather capitalize borrowing cost only in respect of qualifying assets for which the commencement date for capitalization was on or after January 1, 2010.  ARC has applied this election.

(d)   Leases

IFRS 1 allows for a first-time adopter to avoid reassessing the determination of whether an arrangement contains a lease at the date of adoption if the assessment was already made under a previous GAAP if that determination would have given the same outcome as under IFRIC 4 – Determining Whether an Arrangement Contains a Lease.  EIC 150 – Determining Whether an Arrangement Contains a Lease was issued under Canadian GAAP in December 2004 and was to be applied to arrangements agreed to, or committed to, after January 1, 2005.  As there are no differences between IFRIC 4 and EIC 150, any arrangements that were identified under EIC 150 and determined to contain or not contain an operating or financing lease do not need to be reassessed.  Accordingly, ARC has elected to apply the exemption granted under IFRS 1 and has assessed historic arrangements which were entered into before January 1, 2005 that exist at January 1, 2010 to determine whether they contain a lease based on the facts and circumstances that existed at that date.  No new leasing arrangements that require any changes to the IFRS financial statements have been identified during this process.

IFRS employs a conceptual framework that is similar to Canadian GAAP.  However, significant differences exist in matters of recognition, measurement and disclosure of certain specific items.  While adoption of IFRS has not changed the Company’s actual cash flows, it has resulted in changes to the Company’s reported financial position and results of operations.  In order to allow the users of the financial statements to better understand these changes, ARC’s consolidated balance sheets at January 1, 2010, September 30, 2010, and December 31, 2010 as prepared under Canadian GAAP and statements of income and comprehensive income for the three and nine months ended September 30, 2010 and the twelve months ended December 31, 2010, as prepared under Canadian GAAP, have been reconciled to IFRS, with the resulting differences explained.

Page 48

CONSOLIDATED BALANCE SHEET (unaudited)

As at January 1, 2010

(Cdn$ millions)	Previous Canadian GAAP			Effect of transition to IFRS			IFRS
ASSETS
Current assets
Accounts receivable	$	115.9		$	-		$	115.9
Prepaid expenses		18.2			-			18.2
Risk management contracts		5.9			-			5.9
Future income/deferred taxes (j)		7.1			(7.1	)		-
		147.1			(7.1	)		140.0
Reclamation funds		33.2			-			33.2
Risk management contracts		3.2			-			3.2
Property, plant and equipment (b)		3,573.4			(23.0	)		3,550.4
Intangible exploration and evaluation assets (b)		-			23.0			23.0
Goodwill		157.6			-			157.6
Total assets	$	3,914.5		$	(7.1	)	$	3,907.4
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	$	166.7		$	-		$	166.7
Current portion of long-term debt (i)		-			27.0			27.0
Distributions payable		23.7			-			23.7
Risk management contracts		12.9			-			12.9
Exchangeable shares (f)		-			47.2			47.2
		203.3			74.2			277.5
Risk management contracts		1.0			-			1.0
Long-term debt  (i)		846.1			(27.0	)		819.1
Accrued long-term incentive compensation		10.9			-			10.9
Asset retirement obligations (e)		149.9			148.2			298.1
Future income/deferred taxes (j)		328.9			(73.8	)		255.1
Total liabilities		1,540.1			121.6			1,661.7
COMMITMENTS AND CONTINGENCIES
UNITHOLDERS’ EQUITY
Unitholders’ capital (f), (k)		2,917.6			(19.3	)		2,898.3
Non-controlling interest (f)		36.0			(36.0	)		-
Deficit (l)		(578.6	)		(73.4	)		(652.0	)
Accumulated other comprehensive loss		(0.6	)		-			(0.6	)
Total unitholders’ equity		2,374.4			(128.7	)		2,245.7
Total liabilities and unitholders’ equity	$	3,914.5		$	(7.1	)	$	3,907.4

Page 49

CONSOLIDATED BALANCE SHEET (unaudited)
As at September 30, 2010
(Cdn$ millions)	Previous Canadian GAAP			Effect of Transition to IFRS			IFRS
ASSETS
Current assets
Cash and cash equivalents	$	0.3		$	-		$	0.3
Short–term investment		3.8			-			3.8
Accounts receivable		143.9			-			143.9
Prepaid expenses		17.1			-			17.1
Risk management contracts		83.1			-			83.1
Assets held for sale (g)		-			105.5			105.5
		248.2			105.5			353.7
Reclamation funds		33.3			-			33.3
Risk management contracts		27.5			-			27.5
Property, plant and equipment (b), (c), (e), (g)		4,396.4			(40.9	)		4,355.5
Intangible exploration and evaluation assets (b)		-			74.2			74.2
Goodwill (h)		243.2			5.0			248.2
Total assets	$	4,948.6		$	143.8		$	5,092.4
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities (g)	$	216.0		$	(6.8	)	$	209.2
Current portion of long-term debt (i)		-			336.2			336.2
Distributions payable		27.6			-			27.6
Risk management contracts		0.2			-			0.2
Exchangeable shares (f)		-			160.1			160.1
Future income/deferred taxes (j)		18.2			(18.2	)		-
Liabilities directly associated with assets held for sale (g)		-			15.5			15.5
		262.0			486.8			748.8
Risk management contracts		0.1			-			0.1
Long-term debt (i)		788.8			(336.2	)		452.6
Other long-term liabilities		35.4			-			35.4
Asset retirement obligations (e), (g), (h)		162.9			236.0			398.9
Future income/deferred taxes (j)		439.8			(43.9	)		395.9
Total liabilities		1,689.0			342.7			2,031.7
COMMITMENTS AND CONTINGENCIES
UNITHOLDERS’ EQUITY
Unitholders’ capital (f), (k)		3,662.4			(18.0	)		3,644.4
Non-controlling interest (f)		142.7			(142.7	)		-
Deficit (l)		(545.4	)		(38.2	)		(583.6	)
Accumulated other comprehensive loss		(0.1	)		-			(0.1	)
Total unitholders’ equity		3,259.6			(198.9	)		3,060.7
Total liabilities and unitholders’ equity	$	4,948.6		$	143.8		$	5,092.4

Page 50

CONSOLIDATED BALANCE SHEET (unaudited)
As at December 31, 2010
(Cdn$ millions)	Previous Canadian GAAP			Effect of Transition to IFRS			IFRS
ASSETS
Current assets
Cash and cash equivalents (a)	$	0.3		$	1.7		$	2.0
Accounts receivable		160.5			-			160.5
Prepaid expenses		12.0			-			12.0
Risk management contracts		66.8			-			66.8
Short-term investment		3.5			-			3.5
Assets held for sale (g)		-			123.9			123.9
		243.1			125.6			368.7
Restricted cash (a)		1.7			(1.7	)		-
Reclamation funds		25.0			-			25.0
Risk management contracts		0.6			-			0.6
Property, plant and equipment (b), (c), (d), (e), (g)		4,432.9			(89.7	)		4,343.2
Intangible exploration and evaluation assets (b)		-			74.4			74.4
Goodwill (h)		243.2			5.0			248.2
Total assets	$	4,946.5		$	113.6		$	5,060.1
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities (g)	$	217.8		$	(6.1	)	$	211.7
Current portion of long-term debt (i)		-			15.7			15.7
Distributions payable		27.7			-			27.7
Exchangeable shares (f), (m)		-			-			-
Risk management contracts		22.0			-			22.0
Future income/deferred taxes (j)		6.0			(6.0	)		-
Liabilities directly associated with assets held for sale (g)		-			18.0			18.0
		273.5			21.6			295.1
Risk management contracts		20.9			-			20.9
Long-term debt (i)		803.5			(15.7	)		787.8
Long-term incentive compensation liability		26.6			-			26.6
Other deferred liabilities		25.0			-			25.0
Asset retirement obligations (e), (g), (h)		169.1			212.6			381.7
Future income/deferred taxes (j)		433.5			(22.9	)		410.6
Total liabilities		1,752.1			195.6			1,947.7
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY
Shareholders’ capital (m)		3,194.5			(82.0	)		3,112.5
Deficit (l), (m)		-			-			-
Accumulated other comprehensive loss		(0.1	)		-			(0.1	)
Total shareholders’ equity		3,194.4			(82.0	)		3,112.4
Total liabilities and shareholders’ equity	$	4,946.5		$	113.6		$	5,060.1

Page 51

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

For the three months ended September 30, 2010

(Cdn$ millions)	Previous Canadian GAAP			Effect of Transition to IFRS			IFRS
Sales of crude oil, natural gas and natural gas liquids	$	293.6		$	-		$	293.6
Royalties		(46.4	)		-			(46.4	)
REVENUE		247.2			-			247.2
Gain on risk management contracts		49.1			-			49.1
		296.3			-			296.3
EXPENSES
Transportation		7.6			-			7.6
Operating		66.4			-			66.4
General and administrative		19.2			-			19.2
Interest and financing charges		13.6			-			13.6
Accretion of asset retirement obligation (e)		2.4			0.7			3.1
Depletion, depreciation and amortization and impairment (recovery) (c)		123.2			(22.4	)		100.8
Gain on foreign exchange		(13.5	)		-			(13.5	)
Loss on revaluation of exchangeable shares (f)		-			8.7			8.7
		218.9			(13.0	)		205.9
Gain on short-term investment		0.9			-			0.9
Capital and other taxes		(0.1	)		-			(0.1	)
Future income/deferred tax recovery (expense) (j), (k)		2.8			(3.7	)		(0.9	)
Net income	$	81.0		$	9.3		$	90.3
Net income attributable to:
The Trust		79.5			10.8			90.3
Non-controlling interest (f)		1.5			(1.5	)		-
Net income per unit
Basic and diluted	$	0.30		$	0.04		$	0.34

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

For the three months ended September 30, 2010

(Cdn$ millions)	Previous Canadian GAAP			Effect of Transition to IFRS			IFRS
Net Income	$	81.0		$	9.3		$	90.3
Other comprehensive income, net of tax
Losses on financial instruments designated as cash flow hedges		(0.4	)		-			(0.4	)
Gains on financial instruments designated as cash flow hedges		0.3			-			0.3
Net unrealized gains on available-for-sale reclamation funds’ investments		0.1			-			0.1
Other comprehensive income		-			-			-
Comprehensive income	$	81.0		$	9.3		$	90.3
Comprehensive income attributable to:
The Trust		79.5			10.8			90.3
Non-controlling interest		1.5			(1.5	)		-

Page 52

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

For the nine months ended September 30, 2010

(Cdn$ millions)	Previous Canadian GAAP			Effect of Transition to IFRS			IFRS
Sales of crude oil, natural gas and natural gas liquids	$	884.4		$	-		$	884.4
Royalties		(145.8	)		-			(145.8	)
REVENUE		738.6			-			738.6
Gain on risk management contracts		159.5			-			159.5
		898.1			-			898.1
EXPENSES
Transportation		21.3			-			21.3
Operating		191.7			-			191.7
General and administrative		56.9			-			56.9
Interest and financing charges		32.0			-			32.0
Accretion of asset retirement obligation (e)		7.3			1.9			9.2
Depletion, depreciation and amortization and impairment (recovery) (c)		321.5			(50.7	)		270.8
Gain on foreign exchange		(11.7	)		-			(11.7	)
Loss on revaluation of exchangeable shares (f)		-			9.4			9.4
		619.0			(39.4	)		579.6
Gain on short-term investment		0.9			-			0.9
Capital and other taxes		(0.1	)		-			(0.1	)
Future income/deferred tax expense (j), (k)		(12.8	)		(7.5	)		(20.3	)
Net income	$	267.1		$	31.9		$	299.0
Net income attributable to:
The Trust		263.8			35.2			299.0
Non-controlling interest (f)		3.3			(3.3	)		-
Net income per unit
Basic	$	1.04		$	0.14		$	1.18
Diluted	$	1.04		$	0.12		$	1.16

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

For the nine months ended September 30, 2010

(Cdn$ millions)	Previous Canadian GAAP		Effect of Transition to IFRS			IFRS
Net Income	$	267.1	$	31.9		$	299.0
Other comprehensive income, net of tax
Gains on financial instruments designated as cash flow hedges		0.3		-			0.3
Net unrealized gains on available-for-sale reclamation funds’ investments		0.2		-			0.2
Other comprehensive income		0.5		-			0.5
Comprehensive income	$	267.6	$	31.9		$	299.5
Comprehensive income attributable to:
The Trust		264.3		35.2			299.5
Non-controlling interest		3.3		(3.3	)		-

Page 53

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

For the twelve months ended December 31, 2010

(Cdn$ millions)	Previous Canadian GAAP			Effect of Transition to IFRS			IFRS
Sales of crude oil, natural gas and natural gas liquids	$	1,213.7		$	-		$	1,213.7
Royalties		(192.8	)		-			(192.8	)
REVENUE		1,020.9			-			1,020.9
Gain on risk management contracts		93.6			-			93.6
		1,114.5			-			1,114.5
EXPENSES
Transportation		29.7			-			29.7
Operating		261.9			-			261.9
Unsuccessful exploration and evaluation costs (b)		-			0.8			0.8
General and administrative		91.6			-			91.6
Interest and financing charges		42.5			-			42.5
Accretion of asset retirement obligation (e)		9.9			2.7			12.6
Depletion, depreciation and amortization and impairment (recovery) (c), (d)		451.2			(42.5	)		408.7
Gain on foreign exchange		(26.8	)		-			(26.8	)
Loss on revaluation of exchangeable shares (f)		-			48.8			48.8
		860.0			9.8			869.8
Gain on short term investments		0.9			-			0.9
Capital and other taxes		(0.2	)		-			(0.2	)
Future income/deferred tax recovery (expense) (j), (k)		5.6			(38.8	)		(33.2	)
Net income	$	260.8		$	(48.6	)	$	212.2
Net income per unit
Basic	$	1.00		$	(0.18	)	$	0.82
Diluted	$	0.99		$	(0.19	)	$	0.80

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

For the twelve months ended December 31, 2010

(Cdn$ millions)	Previous Canadian GAAP			Effect of Transition to IFRS			IFRS
Net Income	$	260.8		$	(48.6	)	$	212.2
Other comprehensive income, net of tax
Gains on financial instruments designated as cash flow hedges		0.5			-			0.5
Gains and losses on financial instruments designated as cash flow hedges in prior periods realized in net income in the current year		0.1			-			0.1
Net unrealized gains on available-for-sale reclamation funds’ investments		0.1			-			0.1
Gains and losses on financial instruments designated as available-for-sale reclamation fund investments in prior periods realized in net income in the current year		(0.2	)		-			(0.2	)
Other comprehensive income		0.5			-			0.5
Comprehensive income	$	261.3		$	(48.6	)	$	212.7

Page 54

The following conventions are used in the reconciling tables below:

Asset and expense accounts:  Increase, (Decrease)

Liability and equity accounts:  (Increase), Decrease

(a)   Restricted Cash

Under IFRS cash subject to restriction is classified as cash and cash equivalents.  Canadian GAAP requires that cash subject to restriction preventing its use for current purposes is to be excluded from current assets.

	January 1, 2010		September 30, 2010		December 31, 2010
Increase in cash and cash equivalents		-		-		1.7
Decrease in restricted cash		-		-		(1.7	)
Impact on deficit		-		-		-

(b)   Intangible Exploration and Evaluation Assets

Under IFRS ARC capitalizes costs associated with exploration and evaluation activities until a project is deemed successful or otherwise.  If a project is deemed successful, the capitalized exploration and evaluation costs are tested for impairment and then transferred to property, plant and equipment.  If a project is deemed unsuccessful the associated costs are charged to the income statement in the period as unsuccessful exploration and evaluation costs.

IFRS requires that intangible exploration and evaluation assets (E&E) are presented separately in the consolidated balance sheet.  Under Canadian GAAP, these assets are included in the general balance of property, plant and equipment.

Consolidated balance sheet

	January 1, 2010			September 30, 2010			December 31, 2010
Costs classified as E&E assets		23.0			74.2			75.2
E&E assets reclassified to unsuccessful E&E costs		-			-			(0.8	)
Decrease in property, plant and equipment		(23.0	)		(74.2	)		(75.2	)
Increase in deficit		-			-			(0.8	)

Consolidated statement of income

	Three months ended September 30, 2010		Nine months ended September 30, 2010		Year ended December 31, 2010
Increase in unsuccessful E&E costs		-		-		0.8
Adjustment before tax		-		-		0.8

(c)   Property, Plant and Equipment - Depletion

Under IFRS ARC’s oil and natural gas assets contained within property, plant and equipment are depleted over the life of its total proved plus probable reserve base. Canadian GAAP requires that total proved reserves be used as the basis for depletion of oil and gas assets accounted for under the full cost method of accounting.

Consolidated balance sheet

	January 1, 2010		September 30, 2010			December 31, 2010
Increase in property, plant and equipment		-		50.7			73.2
Related tax effect		-		(12.7	)		(18.3	)
Decrease in deficit		-		38.0			54.9

Consolidated statement of income

	Three months ended September 30, 2010.			Nine months ended September 30, 2010			Year ended December 31, 2010
Decrease in depletion and depreciation		(22.4	)		(50.7	)		(73.2	)
Adjustment before tax		(22.4	)		(50.7	)		(73.2	)

Page 55

(d)   Property, Plant & Equipment - Impairment

IFRS uses a one-step approach for testing and measuring impairment, with asset carrying values compared directly with the higher of fair value less costs to sell and value in use.  Under IFRS, impairment of PP&E must be calculated at a more granular level than what is currently required under Canadian GAAP resulting in impairment testing being done at the cash generating unit (“CGU”) level.

Canadian GAAP uses a two-step approach to impairment testing;  first comparing asset carrying values with undiscounted future cash flows to determine whether an impairment exists, and then measuring impairment by comparing asset carrying values to their fair value (which is calculated using discounted cash flows).  Under Canadian GAAP, ARC includes all assets in one impairment test.

Under IFRS, an impairment charge of $30.7 million was recognized on ARC’s property, plant and equipment at December 31, 2010 relating to one of ARC’s oil producing CGU’s.

Consolidated balance sheet

	January 1, 2010		September 30, 2010		December 31, 2010
Decrease in property, plant and equipment		-		-		(30.7	)
Related tax effect		-		-		7.7
Increase in deficit		-		-		(23.0	)

Consolidated statement of income

	Three months ended September 30, 2010		Nine months ended September 30, 2010		Year ended December 31, 2010
Increase in depletion and depreciation		-		-		30.7
Adjustment before tax		-		-		30.7

(e)   Asset Retirement Obligation

Under IFRS, the provision for asset retirement obligations includes both constructive and legal obligations and must be revalued at each reporting date using a pre-tax liability specific discount rate that reflects the time value of money.  As a result of applying the IFRS 1 deemed cost exemption, any adjustments in the carrying amount of the obligation on transition to IFRS are required to be charged directly to retained earnings.  All subsequent changes will adjust the carrying value of property, plant and equipment.

Accretion of the asset retirement obligation is calculated using the current risk-free interest rate.

Under Canadian GAAP, ARC recorded its asset retirement obligations discounted by its credit adjusted risk-free rate in effect at the time the liability arises.  The value is not subsequently adjusted for changes in the credit adjusted risk-free rate.  Canadian GAAP does not require the inclusion of constructive liabilities in the determination of a company’s asset retirement obligation.

Accretion is calculated using the credit adjusted risk-free rate in effect at the time the provision was originally recorded and is presented in the depletion, depreciation and accretion line item in the Canadian GAAP consolidated income statement.

Consolidated balance sheet

	January 1, 2010			September 30, 2010			December 31, 2010
Increase in property, plant and equipment		-			88.1			66.9
Increase in asset retirement obligation		(148.2	)		(238.0	)		(217.8	)
Related tax effect		37.1			37.5			37.8
Increase in deficit		(111.1	)		(112.4	)		(113.1	)

Consolidated statement of income

	Three months ended September 30, 2010		Nine months ended September 30, 2010		Year ended December 31, 2010
Increase in accretion		0.7		1.9		2.7
Adjustment before tax		0.7		1.9		2.7

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(f)   Exchangeable Shares

Under IFRS, ARC’s exchangeable shares meet the criteria of a financial liability and are presented at fair value at each balance sheet date.  Accordingly, in ARC’s opening IFRS balance sheet exchangeable shares have been restated to reflect their fair value on January 1, 2010, with a corresponding adjustment to unitholders’ capital and retained earnings recorded to reflect all exchanges into trust units over time measured at fair value.  Subsequent changes in fair value are recorded directly to the consolidated income statement.

Under Canadian GAAP, ARC classifies its exchangeable shares as non-controlling interest. When exchangeable shares are converted to trust units net income amounts previously recorded as non-controlling interest are re-classified to unitholders’ capital.

Consolidated balance sheet

	January 1, 2010			September 30, 2010			December 31, 2010
Increase in exchangeable shares on revaluation		(34.4	)		(43.8	)		(83.2	)
Decrease in non-controlling interest		23.2			26.5			23.2
Decrease in unitholders’ capital		20.1			20.1			20.1
Increase in exchangeable shares on book value reclassification		(12.8	)		(12.8	)		(12.8	)
Decrease in non-controlling interest on book value reclassification		12.8			12.8			12.8
Decrease (increase) in deficit		8.9			2.8			(39.9	)

Consolidated statement of income

	Three months ended September 30, 2010			Nine months ended September 30, 2010			Year ended December 31, 2010
Revaluation of exchangeable shares		8.7			9.4			48.8
Reversal of non-controlling interest		(1.5	)		(3.3	)		-
Adjustment before tax		7.2			6.1			48.8

(g)   Assets Held For Sale

Under IFRS, a non-current asset must be classified as held for sale if its carrying amount will be recovered principally through a sale transaction rather than continuing use.  Assets held for sale are recorded at the lower of their carrying value or fair value less costs to sell.  Once classified as held for sale these assets are no longer depreciated.

At the end of the fourth quarter of 2010 a group of producing oil and gas properties were packaged for sale and as such were classified as assets held for sale in accordance with IFRS.

Under Canadian GAAP if the disposal of these properties would not change the corporate depletion rate by more than 20 per cent there is no separate presentation of assets held for sale.

Consolidated balance sheet

	January 1, 2010		September 30, 2010			December 31, 2010
Increase in assets held for sale		-		105.5			123.9
Decrease in property, plant and equipment		-		(105.5	)		(123.9	)
Increase in liabilities directly associated with assets held for sale		-		(15.5	)		(18.0	)
Decrease in accounts payable and accrued liabilities		-		6.8			6.1
Decrease in asset retirement obligation		-		8.7			11.9
Impact on deficit		-		-			-

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(h)   Goodwill

ARC recognized the purchase price of Storm Exploration Inc (“Storm”) in accordance with CICA Handbook Section 1582 - Business Combinations.  The fair value of the assets and liabilities are the same under IFRS and Canadian GAAP with the exception of the asset retirement obligation.

Under Canadian GAAP, ARC recorded asset retirement obligations associated with Storm using a credit adjusted risk-free rate, under IFRS a risk-free discount rate was used, thus resulting in a larger asset retirement obligation being recognized.  The offset to this change is an increase to goodwill, net of the resulting differences in the deferred tax asset assumed.

Consolidated balance sheet

	January 1, 2010		September 30, 2010			December 31, 2010
Increase in asset retirement obligation		-		(6.7	)		(6.7	)
Increase in goodwill		-		5.0			5.0
Decrease in deferred tax liability		-		1.7			1.7
Impact on deficit		-		-			-

(i)   Current Portion of Long-Term Debt

Under IFRS debt balances due within one year must be classified as current in the consolidated balance sheet unless these amounts can be refinanced or rolled-over on a long-term basis with the same counter-party.  As a result amounts due within 12 months under the senior notes have been re-classified to current liabilities.

Under Canadian GAAP amounts due within 12 months under the senior notes are classified as long-term as management has the ability and intent to refinance these amounts through the syndicated credit facility.

At June 30, 2010, ARC’s credit facility was due to mature in less than 12 months, thereby requiring presentation as a current liability under IFRS.

Under Canadian GAAP, ARC presented its credit facility as a long-term liability as it had renewed its facility after the balance sheet date but prior to the date of approval for release of the financial statements.  IAS 1 does not allow for an adjustment to the financial statements if the renewal to the arrangement was completed after the balance sheet date, but requires disclosure regarding the renewal in the notes to the financial statements.

Consolidated balance sheet

	January 1, 2010			September 30, 2010			December 31, 2010
Increase in current portion of long-term debt		27.0			336.2			15.7
Decrease in long-term debt		(27.0	)		(336.2	)		(15.7	)
Impact on deficit		-			-			-

(j)   Deferred Taxes

Under IFRS, all deferred tax balances are classified as long-term irrespective of the classification of the underlying assets or liabilities to which they relate, or the expected reversal of the temporary difference.

Under Canadian GAAP future tax assets and liabilities are presented as current or non-current based on the classification of the underlying assets or liability to which they relate.

The following table reconciles the decrease (increase) in deferred tax liability:

	January 1, 2010		September 30, 2010			December 31, 2010
Change in asset retirement obligation (i)		37.1		37.5			37.8
Change in asset retirement obligation on acquisition (i)		-		1.7			1.7
Depletion (i)		-		(12.7	)		(18.3	)
Asset impairment (i)		-		-			7.7
Change in future tax rate (ii)		29.6		35.6			-
Decrease in deferred tax liability		66.7		62.1			28.9

(i)  As per notes (c), (d), (e), and (h) above.

(ii)  Under IFRS, entities that are subject to different tax rates on distributed and undistributed income must calculate deferred taxes using the undistributed profits rate, which is the higher of the two.  Canadian GAAP requires each individual tax rate to be applied to distributed and undistributed profits, respectively.  On December 31, 2010 ARC effectively completed its conversion from an income trust to a corporation, therefore, the undistributed profits rate was no longer applicable in calculating ARC’s deferred tax liability.

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(k)   Share Issue Costs

As the undistributed profits income tax rate is applied to share issue costs in the calculation of the IFRS deferred tax liability, an incremental amount of unitholders’ capital was recorded under IFRS.

Consolidated balance sheet

	January 1, 2010			September 30, 2010			December 31, 2010
Increase in unitholders’ capital		(0.8	)		(2.1	)		-
Increase in deficit		(0.8	)		(2.1	)		-

(l)   Deficit

The following is a summary of adjustments to the deficit:

	January 1, 2010			September 30, 2010			December 31, 2010
Asset retirement obligation		(148.2	)		(148.2	)		(148.2	)
Revaluation of exchangeable shares		8.9			(0.4	)		(39.9	)
Deferred tax		65.9			58.3			27.2
Non-controlling interest		-			3.3			-
Unsuccessful E&E costs		-			-			(0.8	)
Depletion		-			50.7			73.2
Impairment of oil and gas assets		-			-			(30.7	)
Accretion		-			(1.9	)		(2.7	)
Increase in deficit		(73.4	)		(38.2	)		(121.9	)

(m)   Shareholders’ Capital

Pursuant to the Plan of Arrangement each unitholder of the Trust received one common share of the Company for each trust unit held.  Exchangeable shareholders received common shares on the same basis as the holders of the Trust Units based on the number of Trust Units into which each exchangeable share would be exchangeable into on December 31, 2010.  Due to the accounting differences under IFRS and Canadian GAAP for exchangeable shares, discussed in (f) above, the carrying value of these instruments differs, thus resulting in a difference in Shareholder’s Capital at the time of the Arrangement.

Pursuant to the Arrangement shareholders’ capital is reduced by the amount necessary to eliminate the deficit of the Trust outstanding at the time of the Arrangement.  The deficit at the time of the Arrangement differs under IFRS compared to Canadian GAAP and as a result the shareholders’ capital amount differs.

The following is a summary of adjustments to shareholders’ capital pursuant to the Plan of Arrangement:

	January 1, 2010		September 30, 2010		December 31, 2010
Elimination of deficit		-		-		(121.9	)
Exchangeable shares exchanged		-		-		39.9
Decrease in shareholders’ capital		-		-		(82.0	)

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