ARC Resources Ltd. - News Release Archive

ARC Resources Ltd. Confirms June 15, 2012 Dividend Amount

Wed, 16 May 2012 12:55:00 -0400

May 16, 2012

CALGARY, May 16, 2012 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on June 15, 2012 to shareholders of record on May 31, 2012. The ex-dividend date is May 29, 2012.

As at May 16, 2012 the trailing twelve-month payments to investors, including the May 15, 2012 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $6.7 billion. ARC's common shares trade on the TSX under the symbol ARX.

ADVISORY - In the interests of providing ARC shareholders and potential investors with information regarding ARC, including management's assessment of ARC's future plans and operations, certain information contained in this document are forward-looking statements within the meaning of the "safe harbour" provisions of the United States Private Securities Litigation Reform Act of 1995 and the Ontario Securities Commission. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, including those risks and uncertainties contained in ARC Resources Ltd.'s Annual Information Form filed at www.sedar.com, which may cause ARC's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Reports First Quarter 2012 Results and a 21 per cent Reduction to the 2012 Capital Budget

Wed, 02 May 2012 18:04:00 -0400

May 2, 2012

CALGARY, May 2, 2012 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") is pleased to report its first quarter operating and financial results. First quarter production was a record 94,970 boe per day and funds from operations were $180.7 million ($0.62 per share). ARC's first quarter 2012 Unaudited Condensed Consolidated Financial Statements and Notes, as well as ARC's Management's Discussion and Analysis ("MD&A") for the three months ended March 31, 2012, are available on ARC's website at www.arcresources.com and on SEDAR at www.sedar.com.

		Three Months Ended March 31
		2012	2011
FINANCIAL
(Cdn$ millions, except per share and per boe amounts)
Funds from operations ⁽¹⁾		180.7	194.1
	Per share ⁽²⁾	0.62	0.68
Net income		40.9	65.2
	Per share ⁽²⁾	0.14	0.23
Operating income ⁽³⁾		46.9	72.8
	Per share ⁽²⁾	0.16	0.26
Dividends		87.0	85.5
	Per share ⁽²⁾	0.30	0.30
Capital expenditures		186.9	157.2
Net debt outstanding ⁽⁴⁾		991.5	731.9
Shares outstanding, weighted average		289.5	284.9
Shares outstanding, end of period		290.1	285.4
OPERATING
Production
	Crude oil (bbl/d)	31,305	28,108
	Condensate (bbl/d)	2,399	1,872
	Natural gas (mmcf/d)	353.0	246.4
	Natural gas liquids (bbl/d)	2,432	2,834
	Total (boe/d) ⁽⁵⁾	94,970	73,880
Average prices
	Crude oil ($/bbl)	87.24	82.27
	Condensate ($/bbl)	99.96	88.34
	Natural gas ($/mcf)	2.67	4.05
	Natural gas liquids ($/bbl)	44.46	43.83
	Oil equivalent ($/boe)	42.35	48.75
Operating netback ($/boe)
	Commodity and other sales	42.39	48.83
	Transportation costs	(1.18)	(1.10)
	Royalties	(6.65)	(6.81)
	Operating costs	(8.75)	(10.12)
	Netback before hedging	25.81	30.80
	Realized Hedging gain (loss)	-	2.03
	Netback after hedging	25.81	32.83
TRADING STATISTICS ⁽⁶⁾
High price		25.72	28.67
Low price		22.53	23.66
Close price		22.90	26.35
Average daily volume (thousands)		1,355	1,636

(1)	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. See "Non-GAAP Measures" section in the MD&A for the three months ended March 31, 2012 and 2011.
(2)	Per share amounts (with the exception of dividends) are based on weighted average shares.
(3)	Operating income is a non-GAAP measure. See "Operating Income" section in this news release.
(4)	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 prior production periods. Working capital deficit is calculated as current liabilities less the current assets as they appear on the Consolidated Balance Sheets, and excludes current unrealized amounts pertaining to risk management contracts, assets held for sale, asset retirement obligations contained within liabilities associated with assets held for sale and liabilities associated with exchangeable shares.
(5)	In accordance with NI 51-101, a boe conversion ratio of 6 Mcf : 1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.
(6)	Trading prices are stated in Canadian dollars and based on intra-day trading.

FINANCIAL AND OPERATIONAL HIGHLIGHTS

ARC's first quarter production was a record 94,970 boe per day, 29 per cent higher than the first quarter of 2011 and three per cent higher than the fourth quarter of 2011. ARC's drilling program throughout the second half of 2011 and first quarter of 2012, and the commissioning of the new 30 mmcf per day Ante Creek gas plant in February of 2012 contributed to the higher first quarter production.
ARC's first quarter liquids production of 36,136 barrels per day increased 10 per cent relative to both the first quarter of 2011 and the fourth quarter of 2011. ARC's focus has been to capitalize on the strength of crude oil prices by exploiting oil and liquids opportunities which generate the highest rates of return and cash flows. Strong production results from new oil wells at Pembina and Goodlands and expanded processing capacity at Ante Creek contributed to the significant increase in crude oil and liquids production in 2012.
ARC's focus on capital discipline has resulted in a $160 million reduction in the 2012 capital budget in response to the current commodity price environment and the expected impact on 2012 funds from operations. ARC has reduced its planned 2012 capital expenditure program from $760 million to $600 million, not including unbudgeted amounts for the acquisition of land and small producing properties, which in the first quarter totaled approximately $20 million. ARC will defer certain 2012 capital projects due to lower than expected 2012 funds from operations attributed to the negative outlook for 2012 natural gas prices and crude oil differentials. ARC plans to drill approximately 150 gross operated wells in 2012, a reduction of 45 gross wells from the originally budgeted number of 195 gross operated wells. The 2012 capital program will prioritize the highest return projects, primarily focused on oil and liquids projects, and will preserve ARC's strong financial position. Despite the reduction in 2012 capital spending, strong production performance in the first quarter of 2012 has enabled ARC to maintain full year 2012 production guidance at 90,000 - 95,000 boe per day, not including the impact of natural gas production that may be shut-in. The capital reduction will result in lower production in the latter half of 2012 and a reduction in the anticipated growth for 2013.

ARC commissioned the new 30 mmcf per day Ante Creek gas processing facility in late February. The increased gas processing capacity will facilitate production growth for both oil and liquids at Ante Creek as liquids production from the field was previously constrained by solution gas processing capacity. ARC had an inventory of drilled and completed wells leading up to the commissioning of the new gas plant whereby production at Ante Creek increased 12 per cent to approximately 9,500 boe per day (51 per cent crude oil and liquids) at the end of the first quarter.
First quarter 2012 commodity sales revenues were up 13 per cent relative to the first quarter of 2011. Crude oil and liquids production contributed approximately 77 per cent of sales revenue due to the strength of crude prices relative to natural gas prices. ARC's diversified production portfolio and an active hedging program served to mitigate the impact of the low natural gas price environment.
First quarter funds from operations were $180.7 million ($0.62 per share) down seven per cent from $194.1 million ($0.68 per share) in the first quarter of 2011. Increased production volumes and strong crude oil prices were offset by lower natural gas prices and current income taxes of $10.3 million.
Operating incomewas $46 million ($0.16 per share) in the first quarter of 2012, a 37 per cent decrease from operating income of $72.8 million ($0.26 per share) in the first quarter of 2011. The decrease in operating income reflects lower netbacks received during the quarter as well as current income tax expense of $10.3 million.
ARC's total realized price of $42.35 per boe in the first quarter of 2012 was down 13 per cent from $48.75 per boe in the first quarter of 2011. The decrease reflects depressed natural gas prices and widening differentials for Canadian crude oil experienced later in the quarter.
ARC's funds from operations included a total hedging gain of $0.7 million in the first quarter of 2012, attributed to a realized gain of $14.2 million on natural gas hedges offset by $15.5 million of losses on crude oil hedges and a gain of $2.0 million on foreign currency and power hedges. ARC realized a cash gain of $14.2 million on natural gas hedges in the first quarter as 23 per cent of natural gas production was hedged at an average floor price of Cdn$4.47 per mcf, well above the average first quarter market price of Cdn$2.52 per mcf. ARC's first quarter $15.5 million loss on crude oil hedges was attributed to 54 per cent crude oil hedged at an average ceiling price of US$91 per barrel during the quarter.
ARC has protected the price on approximately 210 mmcf per day (60 per cent) of natural gas production for the remainder of 2012 at an average price of US$3.75 per mmbtu. Approximately 18,000 barrels per day (50 per cent) of oil and liquids production is currently hedged at an average floor/ceiling price of US$90/US$91 per barrel for the remainder of 2012. Additional crude oil and natural gas volumes are hedged for 2013.
Capital expenditures for the first quarter totaled $186.9 million as ARC drilled 59 gross operated wells comprised of 53 gross operated oil wells, five gross operated liquids-rich gas wells and one natural gas well with a 100 per cent success rate during the first quarter. ARC will continue to focus on oil and liquids-rich opportunities at Ante Creek, Pembina, Goodlands, southeast Saskatchewan, and Tower in 2012.
ARC exited the quarter with a strong balance sheet including total credit capacity of $1.6 billion, borrowings of $879 million and a working capital deficit of $105 million, leaving approximately $583 million of total available credit capacity. ARC's covenants-based credit facility has a four year term to August 2015. Net debt to annualized funds from operations ratio was 1.4 times and net debt was approximately 13 per cent of ARC's total capitalization at the end of the first quarter; both well within ARC's target levels.
ARC declared and paid a dividend of $0.30 per share to shareholders for the first quarter of 2012 and has confirmed a dividend of $0.10 per share to shareholders for April 2012 to be paid on May 15, 2012. ARC has conditionally declared a dividend of $0.10 per share, payable monthly for May 2012, June 2012 and July 2012, subject to confirmation by monthly news release and subject to any further resolution of the Board of Directors. ARC has maintained the current monthly dividend level of $0.10 per share for a period of 35 months, including payments through April 16, 2012.

COMMODITY PRICE ENVIRONMENT

While benchmark crude oil prices were strong throughout the first quarter, averaging US$103 per barrel, Canadian crude oil differentials experienced significant volatility during the quarter, with the differential for Edmonton Par widening to $19.85 per barrel relative to WTI in March. The recent weakness in Canadian crude grades is due primarily to refinery outages and upgrades, oil production growth in both Canada and the United States and pipeline infrastructure bottlenecks in the mid-western region of the United States. Differentials have improved significantly for May crude oil deliveries and are estimated to be in the order of approximately $8.00 per barrel; however the risk of volatile differentials remains.

Natural gas prices reached their lowest level in 10 years during the first quarter of 2012 due to excess inventory of natural gas which is attributed to both increased supply and lower demand for natural gas. Canadian natural gas prices hit a low daily spot price of Cdn$1.63 per mcf during the quarter, decreasing further to a low daily spot price of Cdn$1.51 per mcf in April. Advances in well completion and fracturing technology have facilitated access to incremental natural gas reserves and resulted in higher natural gas production; with a significant portion coming from shale gas plays throughout North America. A mild winter in 2011/2012 resulted in lower than average demand for natural gas in North America, further contributing to the natural gas inventory build.

With natural gas prices currently at a 10 year low, it is anticipated that natural gas production may be voluntarily curtailed by producers due to deteriorating economics, and in some cases may be involuntarily apportioned due to storage constraints in North America. During the first quarter, ARC voluntarily shut-in approximately 4 mmcf per day of natural gas production that was uneconomic to produce. ARC continues to review the netbacks of all of its natural gas properties to determine whether to shut-in additional production. Any further shut-ins of natural gas production is not expected to materially affect funds from operations.

FINANCIAL REVIEW

Funds from Operations

ARC's first quarter funds from operations of $180.7 million ($0.62 per share) was down seven per cent compared to the first quarter of 2011 funds from operations of $194.1 million ($0.68 per share). Higher production and higher crude oil and liquids prices experienced during the first quarter of 2012 were offset by significantly lower natural gas prices and current income tax expense of $10.3 million.

Following is a reconciliation of funds from operations to net income and cash flow from operating activities.


		Three months ended March 31
($ millions)		2012	2011
Net income		40.9	65.2
Adjusted for the following non-cash items:
	Depletion, depreciation, amortization and impairment	129.3	66.0
	Accretion of asset retirement obligation	3.1	3.5
	Deferred tax (recovery) expense	(0.3)	19.1
	Unrealized loss on risk management contracts	21.8	148.6
	Unrealized losses on risk management contracts related to prior production periods ⁽¹⁾	(7.7)	(12.0)
	Foreign exchange gain on revaluation of debt	(7.3)	(9.6)
	Gain on disposal of petroleum and natural gas properties	-	(87.9)
	Other	0.9	1.2
Funds from operations		180.7	194.1
Unrealized losses on risk management contracts related to prior production periods ⁽¹⁾		7.7	12.0
Net change in other liabilities		(3.9)	(14.0)
Change in non-cash working capital		(26.7)	11.7
Cash flow from operating activities		157.8	203.8

(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 months ended March 31, 2012 and 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.

The following table details the items contributing to the change in funds from operations from the first quarter 2011 to the first quarter of 2012.


		Three months ended March 31
		$ millions	$/Share
Funds from operations - 2011 ⁽¹⁾		194.1	0.68
Volume variance
	Crude oil and liquids	26.5	0.09
	Natural gas	40.2	0.14
Price variance
	Crude oil and liquids	19.2	0.07
	Natural gas	(44.3)	(0.16)
Realized (losses) gains on risk management contracts		(17.3)	(0.06)
Unrealized losses on risk management contracts related to first quarter 2012 production⁽²⁾		4.3	0.02
Royalties		(12.1)	(0.04)
Expenses:
	Transportation	(2.9)	(0.01)
	Operating	(8.3)	(0.03)
	General and administrative	(7.4)	(0.03)
	Interest	(0.6)	-
	Current taxes	(10.3)	(0.04)
	Realized foreign exchange losses	(0.4)	-
Diluted shares		-	(0.01)
Funds from operations - 2012 ⁽¹⁾		180.7	0.62

(1)	This is a non-GAAP measure which may not be comparable with similar non-GAAP measures used by other entities. Refer to "Non-GAAP Measures" contained within the MD&A for the three and twelve months ended December 31, 2011.
(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 months ended March 31, 2012 and 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.

Operating Netbacks

ARC's operating netback, before hedging, decreased 16 per cent to $25.81 per boe in the first quarter of 2012 compared to $30.80 per boe in the first quarter of 2011. After hedging, ARC's first quarter netback was $25.81 per boe, a 21 per cent decrease relative to 2011. The decrease in netbacks both before and after hedging is primarily due to the decrease in natural gas prices.

ARC's total corporate royalty rate increased to 16 per cent ($6.65 per boe) in the first quarter of 2012 from 14 per cent ($6.81 per boe) in 2011 due to higher oil prices and fewer wells qualifying for the Alberta royalty incentive programs applicable to wells drilled between January 1, 2009 and March 31, 2011.

ARC's first quarter operating costs were $9.09 per boe prior to a one-time processing income credit of $0.34 per boe from a third party pertaining to prior periods. Reported first quarter operating costs were $8.75 per boe after the incremental processing income. First quarter operating costs of $9.09 per boe, prior to the one-time processing credits, were down ten per cent relative to operating cost of $10.12 per boe in the first quarter of 2011. Lower first quarter operating costs were primarily attributed to significantly lower power costs with Alberta Power Pool prices averaging $60/MWh during the first quarter of 2012 compared to $83/MWh in 2011. ARC hedges a portion of electricity costs; however the gains or losses on the contracts have not been recorded directly against the operating costs. Including the impact of gains on ARC's electricity hedge contracts, operating costs would decrease by $0.14 per boe for the first quarter of 2012.

The following table details components of operating netbacks for the first quarter of 2012 relative to 2011.


Netbacks ($ per boe)	Crude Oil ($/bbl)	Heavy Oil ($/bbl)	Condensate ($/bbl)	Natural Gas ($/mcf)	NGL ($/bbl)	Q1 2012 Total ($/boe)	Q1 2011 Total ($/boe)
Average sales price	87.56	75.76	99.96	2.67	44.46	42.35	48.75
Other	-	-	-	-	-	0.04	0.08
Total sales	87.56	75.76	99.96	2.67	44.46	42.39	48.83
Royalties	(15.46)	(9.59)	(27.32)	(0.16)	(12.87)	(6.65)	(6.81)
Transportation	(0.70)	(1.08)	(1.58)	(0.25)	(0.38)	(1.18)	(1.10)
Operating costs ⁽¹⁾	(14.13)	(17.71)	(4.23)	(0.80)	(8.80)	(8.75)	(10.12)
Netback prior to hedging	57.27	47.38	66.83	1.46	22.41	25.81	30.80
Hedging gain (loss) ⁽²⁾	(5.00)	-	-	0.44	-	-	2.03
Netback after hedging	52.27	47.38	66.83	1.90	22.41	25.81	32.83
% of total	63%	2%	7%	26%	2%	100%	100%

(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 gains on risk management contracts plus an unrealized loss on risk management contracts that relate to production for the first quarter. Foreign exchange risk management contracts are excluded from the netback calculation.

Net Income

ARC recorded net income of $40.9 ($0.14 per share) for the first quarter of 2012 compared to net income of $65.2 million ($0.23 per share) in the first quarter of 2011. Higher production and crude oil prices had a positive impact on netbacks and funds from operations, however these gains were eroded by significantly lower natural gas prices. ARC recorded current income tax expense of $10.3 million in the first quarter of 2012 (nil in 2011) following its conversion to a corporation on January 1, 2011. First quarter net income included a $21.8 million unrealized loss on risk management contracts, primarily attributed to an increase in crude oil futures price at the end of the first quarter relative to year end 2011 ($148.6 million unrealized loss in 2011).

Operating Income

First quarter operating income was $46 million ($0.16 per share), down 37 per cent from $72.8 million ($0.26 per share) in the first quarter of 2011. The decrease in operating income was primarily due to lower netbacks and higher G&A expense in the first quarter of 2012.

Following is a summary of operating income for the first quarter of 2012 and 2011.


		Three months ended March 31
		2012	2011
Net income		40.9	65.2
Add (deduct) non-operating items, net of tax:
	Unrealized loss on risk management contracts	16.4	111.5
	Unrealized loss on risk management contracts relating to prior production periods ⁽¹⁾	(5.8)	(9.0)
	Unrealized gain on foreign exchange	(5.5)	(7.2)
	Gains on disposal of petroleum and natural gas properties	-	(65.9)
	Impairment (recovery) on property, plant and equipment	-	(21.3)
	Unrealized loss (gain) on short-term investment	0.9	(0.5)
Operating Income - $ millions ⁽²⁾		46.9	72.8
Operating Income - $ per share ⁽²⁾		0.16	0.26

(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 months ended March 31 have been applied to reduce operating income in order to more appropriately reflect the funds from operations generated during the period after any effect of contracts used for economic hedging.
(2)	Operating income is not a recognized performance measure under GAAP and does not have a standardized meaning prescribed by GAAP. The term "operating income" is defined as net income excluding the impact of after-tax loss on unrealized gains and losses on risk management contracts, after-tax unrealized gains and losses on foreign exchange, after-tax gains and losses on short-term investments, after-tax impairment (recovery) on property, plant and equipment, after-tax gains on disposal of petroleum and natural gas properties and the effect of changes in statutory income tax rates. ARC believes that adjusting net income for these non-operating items presents a better measure of financial performance that is more comparable between periods. The most directly comparable measure of operating income calculated in accordance with GAAP is net income.

Risk Management

ARC maintains a risk management program to reduce the volatility of sales, increase the certainty of cash flows and to protect acquisition and development economics. ARC currently limits the amount of total forecast production that can be hedged to a maximum of 55 per cent over the next two years, without specific approval by the Board of Directors, with the remaining 45 per cent of production being sold at market prices. ARC's hedging policy allows for further hedging on volumes associated with new production arising from specific capital projects and acquisitions with approval of the Board.

ARC realized cash gains on natural gas hedging contracts in the first quarter of 2012 of $14.2 million. ARC hedged approximately 23 per cent of first quarter 2012 natural gas production at an average floor price of Cdn$4.54 per mcf, well above first quarter average market prices of Cdn$2.52 per mcf.

ARC recognized a loss on crude oil hedging contracts in the first quarter of 2012 of $15.5 million. ARC hedged approximately 54 per cent of first quarter 2012 crude oil production at an average floor/ceiling price of US$90/US$91 per barrel, relative to the first quarter 2012 average market price of US$103 per barrel. First quarter crude oil hedging losses included a loss of $7.7 million on crude oil annual-settled call contracts relating to volumes hedged for the first quarter of 2012 ($12 million in the first quarter of 2011). Unlike the majority of ARC's risk management contracts that are settled monthly, these annual-settled call contracts, which relate to production throughout 2012, will be cash-settled in their entirety in January 2013 based on the annual average price.

Floor prices on crude oil and natural gas hedged volumes for 2012 provide a level of certainty for ARC to execute its business plan over the next year. Given the significant contribution of ARC's crude oil and natural gas liquids production to total sales and funds from operations, ARC management recognizes the risk associated with an unanticipated reduction in crude oil pricing. Accordingly, ARC has protected the selling price on a portion of crude oil production by establishing crude oil floor and ceiling prices through 2013. ARC expects to continue to execute its Risk Management program on volumes going forward, increasing hedged volumes in 2013. In total, ARC currently has hedged approximately 54 per cent and 36 per cent per cent of total crude oil and condensate production for the remainder of 2012 and 2013, respectively, as summarized in the table below. For a complete listing and terms of ARC's hedging contracts, see Note 7 "Risk Management Contracts" in the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2012 and 2011.


Summary of Hedge Positions ⁽¹⁾
As at May 2, 2012		2012		2013
Crude Oil ⁽²⁾		US$/bbl	bbl/day	US$/bbl	bbl/day
	Sold Call	91.11	18,000	105.01	11,984
	Bought Put	90.00	18,000	95.01	11,984
	Sold Put	63.44	16,000	63.33	6,000
Natural Gas ⁽³⁾		US$/mcf	mcf/day	US$/mcf	mcf/day
	Swap	3.75	210,018	-	-
	Sold Call	-	-	4.00	90,000
	Bought Put	-	-	3.25	90,000

(1)	The prices and volumes noted above represent averages for several contracts representing different periods 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 2012 and 2013, all put positions settle against the monthly average WTI price, providing protection against monthly volatility. Calls have been sold against either the monthly average or the annual average WTI price. In the case of settlements on annual positions, 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.
(3)	The natural gas price shown translates all AECO positions to a NYMEX equivalent price. The equivalent AECO price hedged would approximate a fixed sales price of CDN$3.24 per mcf for 2012.

ARC's first quarter unrealized loss of $21.8 million on commodity hedging contracts was due primarily to an increase in crude oil forward prices as at March 31, 2012 relative to year end 2011. The actual future cash settlements under the commodity hedge contracts will differ from the current unrealized liability as changes in commodity prices occur in future periods.

OPERATIONAL REVIEW

During the first quarter of 2012, ARC spent $186.9 million to execute its capital program including $28.3 million on facilities expenditures. ARC drilled 59 gross (54 net) wells on operated lands with a 100 per cent success rate. First quarter drilling activity was focused on oil and liquids development with 98 per cent of wells drilled being oil and liquids-rich gas wells. Activities focused on Tower in northeast British Columbia, Pembina and Ante Creek in northern Alberta and various oil properties throughout southeast Saskatchewan and Manitoba. ARC commissioned a new 30 mmcf per day gas processing facility at Ante Creek in late February to accommodate solution gas processing which will in turn facilitate increased liquids production.

First quarter production of 94,970 boe per day increased 29 per cent relative to the first quarter of 2011 and was three per cent higher than the fourth quarter of 2011. First quarter production comprised 62 per cent natural gas and 38 per cent crude oil and liquids. Crude oil and liquids production increased 10 per cent relative to the first quarter of 2011 due to production from new oil and liquids-rich gas wells drilled, predominantly at Ante Creek, Pembina and Goodlands. Higher natural gas production was attributed to the start-up of the 60 mmcf per day Dawson Phase 2 gas plant in the second quarter of 2011.

Ante Creek

The Ante Creek property in northern Alberta is a Montney oil and natural gas play in which ARC has a land position of 260 net sections. ARC's Ante Creek production averaged 8,700 boe per day in the first quarter of 2012 (51 per cent crude oil and natural gas liquids, 49 per cent natural gas). ARC commissioned the 30 mmcf per day Ante Creek gas plant in late February. Production at Ante Creek increased 10 per cent to approximately 9,500 boe per day (51 per cent crude oil and liquids) at the end of the first quarter. The new gas plant will alleviate gas processing capacity constraints and thereby facilitate increased liquids production. ARC believes that the Ante Creek property will provide a significant near-term growth opportunity with continued drilling and increased capacity.

Pembina

First quarter production at Pembina exceeded expectations due to strong well performance. First quarter production increased to approximately 10,816 boe per day (79 per cent light oil, 21 per cent natural gas), up four per cent from the first quarter of 2011.

During the first quarter, ARC drilled 14 gross horizontal wells into the Cardium formation. ARC is pleased with results to date of the horizontal drilling program at Pembina. Extensive work is planned on waterflood management in 2012 in order to optimize reservoir recoveries in the area.

Southeast Saskatchewan and Manitoba

First quarter production averaged approximately 11,249 boe per day of light crude oil, up seven per cent from 10,386 boe per day in the first quarter of 2011 and nine per cent higher than the fourth quarter of 2011.

The Goodlands property in Manitoba provides some of the best drilling economics in ARC's portfolio due to the high netback, light crude oil. First quarter Goodlands production averaged 2,200 boe per day of light crude oil, up 57 per cent from 1,400 boe per day in the first quarter of 2011 and 57 per cent higher than the fourth quarter of 2011. ARC drilled 10 Goodlands oil wells during the first quarter of 2012. ARC expanded an oil facility at Goodlands in the fourth quarter of 2011, adding 2,300 barrels per day of fluid capacity in response to active drilling programs in 2011 and planned for 2012.

Tower

ARC's Tower property consists of 48 net sections of contiguous land north and west of the Parkland field. First considered to be a potential very tight oil play when ARC acquired the property in 2010, ARC has since realized a significant liquids-rich hydrocarbon opportunity. The Tower property provides favorable economics due to the high liquids content, specifically, the condensate production at Tower yields premium prices relative to crude oil.

ARC had one well on production throughout the quarter and a second well came on production during the quarter. During the first quarter of 2012, ARC drilled four gross operated horizontal wells at Tower. To date, ARC has drilled seven gross operated wells at Tower, the remaining five wells are to be completed and tested during the second quarter.

ARC plans to drill three additional horizontal Tower wells in 2012 and will gather additional fluid samples on new wells and conduct recombined pressure-volume-temperature ("PVT") studies to better understand the fluids in place at Tower. Existing facilities in the Parkland/Tower region have sufficient capacity to handle current production levels; however ARC is evaluating infrastructure requirements to address future development plans at Tower.

Dawson

First quarter production at Dawson ran at capacity of 165 mmcf per day of natural gas throughout the quarter, with 120 mmcf per day flowing through operated facilities and the remaining 45 mmcf per day flowing through third party facilities. As a result of well productivity in Dawson continuing to exceed expectations, ARC has an inventory of 16 wells waiting to be brought on-stream to maintain current production of 165 mmcf per day throughout 2012.

Attachie

ARC holds a prospective land base of 115 net sections of liquids-rich Montney acreage at Attachie. During the first quarter of 2012, ARC reached an agreement with a third party to tie-in the 4-9 well on the eastern edge of the Attachie lands into the third party facility and expects to bring the well on production late in the second quarter. ARC executed a 3D seismic program over an area of 300 square kilometers at Attachie during the first quarter.

ARC plans to drill two horizontal wells at Attachie in 2012. Test rates from the three horizontal wells and one vertical well drilled to date at Attachie are a promising indicator of the potential of Attachie for commercial development. At present, there is limited infrastructure in the immediate area.

DIVIDENDS

ARC paid dividends totaling $0.30 per share for the first quarter of 2012 and $1.20 per share for the full year 2011. The Board of Directors has confirmed a dividend of $0.10 per share for April 2012, payable on May 15, 2012, and has conditionally declared a monthly dividend of $0.10 per share, payable monthly for May 2012, June 2012 and July 2012, targeting a total dividend of $0.30 per share for the second quarter of 2012. The dividends have been designated as eligible dividends under the Income Tax Act (Canada) and are payable as follows:


Ex-dividend date	Record date	Payment date	Per share amount
April 26, 2012	April 30, 2012	May 15, 2012	$0.10 ⁽¹⁾
May 29, 2012	May 31, 2012	June 15, 2012	$0.10 ⁽²⁾
June 27, 2012	June 29, 2012	July 16, 2012	$0.10 ⁽²⁾
July 27, 2012	July 31, 2012	Aug 15, 2012	$0.10 ⁽²⁾

(1)	Confirmed on April 16, 2012.
(2)	Conditionally declared, subject to confirmation by news release and further resolution by the Board of Directors.

The declaration of the dividends is conditional upon confirmation by news release and is subject to any further resolution of the Board of Directors. Dividends are subject to change in accordance with ARC's dividend policy depending on a variety of factors and conditions existing from time-to-time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of solvency tests imposed by the Business Corporations Act (Alberta) for the declaration and payment of dividends.

See "Outlook" for additional discussion regarding Dividends.

OUTLOOK

The pillar of ARC's business strategy is "risk-managed value creation". ARC's goal is to transform this value into shareholder returns through regular dividends and anticipated capital appreciation relating to future growth. During the first quarter of 2012, ARC achieved record production levels, commissioned the new 30 mmcf per day Ante Creek gas processing facility and drilled 59 gross operated wells focused on oil and liquids-rich natural gas properties. Despite the low natural gas price environment, ARC reported strong funds from operations and maintained low debt levels due to a disciplined approach to capital planning and execution focused on the highest rate of return projects across our asset portfolio. ARC's business strategy will remain unchanged in 2012. Our primary focus is to maximize value by directing capital to oil and liquids-rich natural gas projects to capitalize on the strength of crude oil prices. We will continually review drilling and infrastructure programs to ensure that projects meet targeted rates of return in accordance with our normal course risk-managed value creation operating criteria.

The first quarter of 2012 was punctuated by commodity price volatility with natural gas prices reaching ten year lows and Canadian crude oil differentials widening to unprecedented levels. The outlook for natural gas prices and Canadian crude oil differentials remains "bearish" and ARC is taking steps to mitigate the risks accordingly. ARC expects that its funds from operations will decrease in the second quarter. ARC has reduced its 2012 capital expenditure program from $760 million to $600 million, not including any unbudgeted amounts for the acquisition of land and small producing properties, in order to preserve our strong financial position through this commodity price downturn. We will reallocate capital to the highest rate of return projects to maximize cash flows.

ARC continues to actively hedge both oil and natural gas in order to provide a greater level of certainty over commodity prices, funds from operations and economics of capital projects. For the remainder of 2012, ARC has hedged 210 mmcf per day of estimated 2012 natural gas production (60 per cent) at an average price of US$3.79 per mmbtu, well in excess of current natural gas prices. ARC's diverse portfolio of high quality oil and liquids-rich natural gas prospects provides ARC with the optionality to exploit oil and liquids-rich assets during this period of low natural gas prices and the outlook for crude oil remains strong at this time.

A further decrease in natural gas prices or a prolonged period of low natural gas prices will impact ARC's funds from operations, level of capital expenditures, and may result in certain natural gas properties being shut-in. Our asset portfolio provides both dry gas and liquid-rich opportunities, in the current commodity price environment ARC favors investments in liquids-rich opportunities that offer higher rates of return.

ARC expects to finance its 2012 capital program with funds from operations, proceeds from the Dividend Re-investment Plan ("DRIP"), existing credit lines and proceeds from the disposition of minor and non-strategic assets. During the first quarter of 2012, ARC funded 63 per cent of its $187 million capital expenditure program with funds from operations and proceeds from the DRIP. ARC will continue its asset redeployment strategy in 2012 and beyond to high grade the asset base with the objective of enhancing shareholder value.

ARC is committed to the income component of our business model which is the regular monthly dividend payment to our shareholders. Our business model is dynamic and we continually assess dividend levels and capital spending in light of current and forecast market conditions. We believe that we are well positioned to sustain current dividend levels despite the current low natural gas price environment. However, if we experience a prolonged period of low commodity prices, our first priority will be to defer certain growth capital in order to preserve our strong financial position in the long-term.

All 2012 guidance estimates are summarized in the following table. ARC has reduced its planned 2012 capital expenditure program from $760 million to $600 million not including unbudgeted amounts for the acquisition of land and small producing properties. Despite the reduction in 2012 capital spending, strong production performance in the first quarter of 2012 has enabled ARC to maintain full year 2012 production guidance at 90,000 - 95,000 boe per day, not including the impact of natural gas production that may be shut-in.


		Original 2012 Guidance	Revised 2012 Guidance	Q1 2012 Actual	% Variance
Production:
	Oil (bbls/d)	31,000 - 32,000	31,000 - 32,000	31,305	-
	Condensate (bbls/d)	1,700 - 2,100	2,100 - 2,500	2,399	-
	Natural gas (mmcf/d)	330 - 350	330 - 350	353	-
	Natural Gas Liquids (bbls/d)	2,500 - 3,000	2,100 - 2,600	2,432	-
	Annual average production (boe/d)	90,000 - 95,000	90,000 - 95,000	94,970	-
Expenses ($/boe):
	Operating	9.55 - 9.95	9.55 - 9.95	8.75	8
	Transportation	1.00 - 1.10	1.00 - 1.10	1.18	(7)
	General and administrative ⁽²⁾	2.30 - 2.50	2.30 - 2.50	2.51	-
	Interest	1.10 - 1.20	1.10 - 1.20	1.21	-
	Income taxes	1.10 - 1.25	1.10 - 1.25	1.19	-
Capital expenditures ($ millions) ⁽³⁾		760	600	187	-
Weighted average shares outstanding (millions)		293	293	289	-

(1)	The 2012 annual guidance for general and administrative cost per boe is based on a range of $1.75 - $1.85 prior to the recognition of any expense associated with ARC's long-term incentive plan and $0.55-$0.65 per boe associated with ARC's long-term incentive plan. Actual per boe costs for each of these components for the three months ended March 31, 2012 were $1.59 per boe and $0.91 per boe, respectively.
(2)	The 2012 corporate tax estimate will vary depending on the level of commodity prices and represents only the current income tax expense.
(3)	Excludes amounts related to unbudgeted acquisitions of land and small producing properties which totaled approximately $20 million in the first quarter of 2012.

Forward-looking Information and Statements

This news release 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 news release contains forward-looking information and statements pertaining to the following: guidance as to the capital expenditure plans of ARC under the heading "Financial and Operational Highlights", as to its views on the effect of commodity prices under the heading "Commodity Price Environment", as to its risk management plans for 2013 under the heading "Risk Management", as to its exploration and development plans under the heading "Operational Review", and all matters including 2012 guidance under the heading "Outlook".

The forward-looking information and statements contained in this news release reflect 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 funds from operations 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.

The forward-looking information and statements included in this news release 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 news release and in ARC's Annual Information Form).

The forward-looking information and statements contained in this news release speak only as of the date of this news release, 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.

ARC Resources Ltd. ("ARC") is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $7 billion. ARC expects 2012 oil and gas production to average 90,000 to 95,000 barrels of oil equivalent per day from its properties in western Canada. ARC's Common Shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Confirms May 15, 2012 Dividend Amount

Mon, 16 Apr 2012 15:56:00 -0400

Apr 16, 2012

CALGARY, April 16, 2012 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on May 15, 2012 to shareholders of record on April 30, 2012. The ex-dividend date is April 26, 2012.

As at April 16, 2012 the trailing twelve-month payments to investors, including the April 16, 2012 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $6.6 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Confirms April 16, 2012 Dividend Amount

Thu, 15 Mar 2012 17:22:00 -0400

Mar 15, 2012

CALGARY, March 15, 2012 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on April 16, 2012 to shareholders of record on March 30, 2012. The ex-dividend date is March 28, 2012.

As at March 15, 2012 the trailing twelve-month payments to investors, including the March 15, 2012 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $7.8 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Confirms March 15, 2012 Dividend Amount

Thu, 16 Feb 2012 15:54:00 -0500

Feb 16, 2012

CALGARY, Feb. 16, 2012 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on March 15, 2012 to shareholders of record on February 29, 2012. The ex-dividend date is February 27, 2012.

As at February 16, 2012 the trailing twelve-month payments to investors, including the February 15, 2012 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $7.8 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Reports Fourth Quarter 2011 Results

Wed, 08 Feb 2012 18:37:00 -0500

Feb 8, 2012

CALGARY, Feb. 8, 2012 /CNW/ - (TSX: ARX) ARC Resources Ltd. ("ARC") is pleased to report its fourth quarter operating and financial results. Fourth quarter production was a record 92,021 boe per day and funds from operations were $226.6 million ($0.79 per share). ARC's 2011 Annual Audited Consolidated Financial Statements and Notes, as well as ARC's Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2011, are available on ARC's website at www.arcresources.com and on SEDAR at www.sedar.com.

		Three Months Ended December 31		Twelve Months Ended December 31
		2011	2010 ⁽¹⁾	2011	2010 ⁽¹⁾
FINANCIAL
(Cdn$ millions, except per share and per boe amounts)
Funds from operations ⁽²⁾		226.6	180.4	844.3	667.0
	Per share ⁽³⁾	0.79	0.63	2.95	2.53
Net income		(49.0)	(86.9)	287.0	212.2
	Per share ⁽³⁾	(0.17)	(0.31)	1.00	0.80
Operating income ⁽⁴⁾		74.7	35.1	293.5	232.6
	Per share ⁽³⁾	0.26	0.12	1.02	0.88
Dividends		86.7	82.8	344.1	313.5
	Per share ⁽³⁾	0.30	0.30	1.20	1.20
Capital expenditures		195.0	159.1	726.0	590.9
Net debt outstanding ⁽⁵⁾		909.7	872.7	909.7	872.7
Shares outstanding, diluted		288.3	283.7	286.6	264.2
Shares outstanding, end of period		288.9	284.4	288.9	284.4
OPERATING
Production
	Crude oil (bbl/d)	28,470	27,417	27,158	27,341
	Condensate (bbl/d)	2,219	2,197	2,052	1,617
	Natural gas (mmcf/d)	355.3	311.5	310.6	254.2
	Natural gas liquids (bbl/d)	2,114	3,158	2,444	2,628
	Total (boe/d) ⁽⁶⁾	92,021	84,686	83,416	73,954
Average prices
	Crude oil ($/bbl)	92.85	76.08	89.51	73.85
	Condensate ($/bbl)	101.13	78.38	96.07	77.40
	Natural gas ($/mcf)	3.43	3.83	3.83	4.21
	Natural gas liquids ($/bbl)	51.02	39.89	47.53	39.57
	Oil equivalent ($/boe)	45.58	42.18	47.15	44.88
Operating netback ($/boe)
	Commodity and other sales	45.69	42.26	47.24	44.96
	Transportation costs	(1.14)	(1.08)	(1.18)	(1.10)
	Royalties	(7.60)	(6.03)	(7.20)	(7.14)
	Operating costs	(9.40)	(9.01)	(9.70)	(9.70)
	Netback before hedging	27.55	26.14	29.16	27.02
	Realized Hedging gain (loss)	2.28	2.50	2.18	2.20
	Netback after hedging	29.83	28.64	31.34	29.22
TRADING STATISTICS ⁽⁷⁾
High price		26.74	26.05	28.67	26.05
Low price		19.40	20.42	19.40	18.77
Close price		25.10	25.41	25.10	25.41
Average daily volume (thousands)		1,267	1,299	1,251	1,197

(1)	Beginning January 1, 2011, all Canadian publicly accountable enterprises are required to prepare their financial statements using International Financial Reporting Standards ("IFRS"). Amounts have been restated to comply with IFRS. See Note 23, "Explanation of Transition to International Financial Reporting Standards" in the audited Consolidated Financial Statements for the year ended December 31, 2011 and 2010 for information on ARC's transition to IFRS.
(2)	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. See "Non-GAAP Measures" section in the MD&A for the year ended December 31, 2011 and 2010.
(3)	Per share amounts (with the exception of dividends) are based on weighted average shares.
(4)	Operating income is a non-GAAP measure. See "Operating Income" in this news release.
(5)	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 prior production periods. Working capital deficit is calculated as current liabilities less the current assets as they appear on the Consolidated Balance Sheets, and excludes current unrealized amounts pertaining to risk management contracts, assets held for sale, asset retirement obligations contained within liabilities associated with assets held for sale and liabilities associated with exchangeable shares.
(6)	In accordance with NI 51-101, a boe conversion ratio of 6 Mcf : 1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.
(7)	Trading prices are stated in Canadian dollars and based on intra-day trading.

FINANCIAL AND OPERATIONAL HIGHLIGHTS

ARC's fourth quarter production was a record 92,021 boe per day, nine per cent higher than the fourth quarter of 2010 and an eight per cent increase relative to the third quarter of 2011. Activity levels ramped up in the second half of 2011 following production downtime and drilling delays attributed to flooding and forest fires in the second quarter of 2011. ARC's full year 2011 production averaged 83,416 boe per day, a 13 per cent increase from 2010. Full year 2012 production guidance of between 90,000 and 95,000 boe per day remains unchanged.
Fourth quarter and full year 2011 commodity sales were up 17 per cent and 18 per cent, respectively, relative to 2010. Crude oil and liquids sales accounted for 71 per cent and 70 per cent of fourth quarter and full year 2011 commodity sales, respectively. While crude oil and liquids production represented 36 per cent of fourth quarter production, it contributed approximately 71 per cent of sales revenue due to the strength of crude prices relative to natural gas prices. ARC's diversified production portfolio and an active hedging program served to mitigate the impact of the low natural gas price environment.
ARC announced the results of its year end reserves and resources evaluation which reflected considerable growth in reserves and identified the significant resource potential in the northeastern B.C. Montney region ("NE B.C. Montney"). See January 26, 2012 news release "ARC Resources Ltd. announces 18 per cent increase in 2011 year-end reserves and results of updated independent resources evaluation for northeast British Columbia Montney Assets" for additional information.
- Proved plus probable ("2P") reserves increased 18 per cent to 572 million boe
- Replaced 385 per cent of 2011 production, adding 117 mmboe of 2P reserves in 2011
- Finding and Development ("F&D") costs of $5.50 per boe and Finding, Development, and Acquisition ("FD&A") costs of $5.24 per boe for 2P reserves, before consideration of future development capital ("FDC")
- Recycle ratio of 5.3 times and 5.0 times for the current year and three year average, respectively, for 2P reserves based on 2011 F&D costs excluding FDC
- Increase in 2P and proved Reserve Life Index ("RLI") to 17 years and 10.7 years, respectively, based on mid-point 2012 production guidance of 92,500 boe per day
- Identified Economic Contingent Resource ("ECR") best estimate of 4.1 Tcf of natural gas and 101 mmbbls of liquids in excess of 2P reserves on ARC's NE B.C. Montney lands
- Discovered Petroleum Initially in Place ("DPIIP") increased to 25.5 Tcf (21.2 Tcf at a three per cent porosity cuf-off) and the estimate of Total Petroleum Initially in Place ("TPIIP") was identified to be 50.4 Tcf (39.6 Tcf at a three per cent porosity cut-off) on ARC's NE B.C. Montney lands
Fourth quarter funds from operations were $226.6 million ($0.79 per share) up 26 per cent from $180.5 million ($0.64 per share) in the fourth quarter of 2010. Full year 2011 funds from operations of $844.3 million ($2.95 per share) were up 27 per cent relative to 2010. Both fourth quarter and full year funds from operations were higher due to increased production and strong crude oil prices.
Operating incomewas $74.7 million ($0.26 per share) in the fourth quarter of 2011, a 113 per cent increase from operating income of $35.1 million ($0.12 per share) in the fourth quarter of 2010. Full year 2011 operating incomewas $293.5 million ($1.02 per share), up 26 per cent from 2010. The increase in fourth quarter and full year operating income was due to higher volumes and higher netbacks attributed to strong crude oil prices in 2011.
ARC's total realized price of $45.58 per boe in the fourth quarter of 2011 was up eight per cent from $42.18 per boe in the fourth quarter of 2010. Crude oil prices averaged US$94.02 per barrel in the fourth quarter, an increase of ten per cent relative to 2010 prices. Natural gas prices, depressed by high inventory levels and increased natural gas production in the United States, were down an average of three per cent relative to 2010 levels to Cdn$3.47 per mcf in the fourth quarter. ARC's full year realized price of $47.15 per boe was up five per cent relative to 2010 due to a 20 per cent increase in average U.S. WTI crude oil prices, which was partially offset by an 11 per cent decrease in average Canadian natural gas prices.
ARC realized cash hedging losses of $16 million and cash gains of $75.8 million in the fourth quarter and full year 2011, respectively. ARC realized a cash gain of $29 million on natural gas hedges in the fourth quarter as 45 per cent of natural gas production was hedged at an average floor price of Cdn$5.76 per mcf, well above the average fourth quarter market price of Cdn$3.47 per mcf. Full year cash hedging gains were attributed to natural gas hedges.
ARC has protected the price on 18,000 barrels per day, approximately 50 per cent of expected 2012 oil and liquids production, at an average floor/ceiling price of US$90/US$91 per barrel. Approximately 123 mmcf per day (36 per cent) of expected 2012 natural gas production is currently protected at average prices of $3.66 per mcf. Additional oil volumes are hedged for 2013.
Capital expenditures for the fourth quarter totaled $195 million, resulting in full year capital expenditures of $726 million. ARC drilled 46 gross operated oil wells and two gross operated natural gas wells with a 100 per cent success rate during the fourth quarter, bringing total wells drilled to 133 gross operated oil wells, 15 gross operated natural gas wells, and 16 gross operated liquids-rich gas wells with a 100 per cent success rate for 2011. Capital activities ramped up during the second half of 2011 following delays due to flooding and forest fires in the second quarter of 2011. Full year 2011 capital spending includes $75 million for purchases of predominately oil-prone lands in and around our core areas. ARC will continue to focus on oil and liquids-rich opportunities at Ante Creek, Pembina, Goodlands and Parkland and staged development of the Montney natural gas opportunities in NE B.C. in 2012.
ARC exited 2011 with a strong balance sheet with total credit capacity of $1.6 billion, borrowings of $762 million and a working capital deficit of $148 million, leaving approximately $674 million of total available credit capacity. Net debt to annual funds from operations ratio was 1.1 times and net debt was approximately 11 per cent of ARC's total capitalization at the end of 2011; both well within ARC's target levels.
ARC declared and paid a dividend of $0.30 per share to shareholders for the fourth quarter of 2011 and has confirmed a dividend of $0.10 per share to shareholders for January 2012 to be paid on February 15, 2012. ARC has conditionally declared a dividend of $0.10 per share, payable monthly for February 2012, March 2012 and April 2012, subject to confirmation by monthly news release and subject to any further resolution of the Board of Directors. Including payments through January 16, 2012, ARC has maintained the current monthly dividend level of $0.10 per share for a period of 32 months.

CORPORATE DEVELOPMENT

Over the past 12 months ARC has conducted a detailed analysis of the North American natural gas market and the potential of Liquefied Natural Gas ("LNG") exports from the west coast of Canada. ARC's recent resource assessment, the results which were released on January 26, 2012 along with its 2011 year-end reserves, confirmed the scope and scale of the capital opportunities within ARC's Montney portfolio. In reviewing the portfolio, ARC identified certain less strategic project areas, representing approximately 10 percent of the Company's NE B.C. Montney land base, that could represent an attractive opportunity to a third party. The Company considered the merit of a joint venture for the development of the subject project areas and ultimately determined that such a capitalization alternative was not what it wished to pursue at this time. Consequently, the selected project areas will be offered for potential sale. ARC has retained a qualified advisor to assist with the process.

ARC is committed to a paced, long-term development of its entire Montney portfolio including the lands selected for possible divestment. A sale will only occur if an offer is received which represents superior value relative to the Company's view of value attainable from its own development plan.

FINANCIAL REVIEW

The positive financial impact of record production volumes and higher oil prices was partially offset by continued low natural gas prices during the fourth quarter. ARC exited the quarter with a strong balance sheet due to strong year-to-date funds from operations and the receipt of $170 million of proceeds from the sale of properties in the first quarter of 2011. ARC maintained a dividend of $0.30 per share in the fourth quarter of 2011.

Funds from Operations

ARC's fourth quarter funds from operations of $226.6 million ($0.79 per share) were up 26 per cent compared to the fourth quarter of 2010 funds from operations of $180.5 million ($0.64 per share). Full year 2011 funds from operations of $844.3 million ($2.95 per share) were up 26 per cent compared to the funds from operations of $667.0 million ($2.53 per share) for 2010. Higher production and higher crude oil and liquids prices and cash gains on ARC's commodity hedging program positively impacted funds from operations in the fourth quarter and full year 2011.

Following is a reconciliation of net income to funds from operations for the fourth quarter and full year 2011 relative to the same periods in 2010.


		Three months ended December 31		Twelve months ended December 31
($ millions)		2011	2010	2011	2010
Net income (loss)		(49.0)	(86.8)	287.0	212.2
Adjusted for the following non-cash items:
	Depletion, depreciation and amortization and impairment	178.1	137.9	509.2	408.7
	Accretion of asset retirement obligation	3.3	3.4	13.4	12.6
	Exploration and evaluation expenses	-	0.8	-	0.8
	Deferred tax expense	(17.4)	12.9	97.0	33.2
	Unrealized loss (gain) on risk management contracts	80.1	85.9	16.5	(28.2)
	Foreign exchange loss (gain) on revaluation of debt	(9.4)	(14.9)	9.7	(26.8)
	Loss (gain) on disposal of petroleum and natural gas properties	3.2	-	(89.5)	-
	Other	(0.4)	41.3	1.0	54.5
	Unrealized loss on risk management contracts relating to 2011 production⁽¹⁾	38.1	-	-	-
Funds from operations		226.6	180.5	844.3	667.0

(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. Throughout 2011, ARC has applied the portion of losses associated with these contracts to the funds from operations calculation in the production period to which they relate to more appropriately reflect the funds from operations generated during the period after any effect of contracts used for economic hedging. At December 31, 2011, all gains and losses associated with these contracts have been realized, and in the fourth quarter losses previously applied to past production periods are reversed.

The following table details the items contributing to the change in funds from operations for the fourth quarter and full year 2011 relative to the same periods in 2010.


		Three months ended December 31		Twelve months ended December 31
		$ millions	$/Share	$ millions	$/Share
Funds from Operations - 2010⁽¹⁾		180.5	0.64	667.0	2.52
Volume variance
	Crude oil and liquids	0.2	-	1.8	0.01
	Natural gas	15.5	0.06	86.8	0.33
Price variance
	Crude oil and liquids	54.9	0.19	179.7	0.69
	Natural gas	(13.1)	(0.05)	(43.8)	(0.17)
Realized gains on risk management contracts		(36.0)	(0.13)	10.4	0.04
Unrealized losses on risk management contracts related to 2011 production⁽²⁾		38.1	0.13	-	-
Royalties		(17.3)	(0.05)	(26.5)	(0.10)
Expenses:
	Transportation	(1.3)	-	(6.4)	(0.02)
	Operating	(9.4)	(0.03)	(33.4)	(0.13)
	General and administrative	13.9	0.05	5.7	0.02
	Interest	1.3	-	3.6	0.01
	Cash taxes	0.1	-	0.2	-
	Realized foreign exchange gains and losses	(0.8)	-	(0.8)	-
Diluted shares		-	(0.02)	-	(0.25)
Funds from Operations - 2011⁽¹⁾		226.6	0.79	844.3	2.95

(1)

This is a non-GAAP measure which may not be comparable with similar non-GAAP measures used by other entities. Refer to "Non-GAAP Measures" contained within the MD&A for the three and twelve months ended December 31, 2011.

(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. Throughout 2011, ARC has applied the portion of losses associated with these contracts to the funds from operations calculation in the production period to which they relate to more appropriately reflect the funds from operations generated during the period after any effect of contracts used for economic hedging. At December 31, 2011, all gains and losses associated with these contracts have been realized, and in the fourth quarter losses previously applied to past production periods are reversed.

Operating Netbacks

ARC's operating netback, before hedging, increased five per cent to $27.55 per boe in the fourth quarter of 2011 compared to $26.14 per boe in the fourth quarter of 2010. The increase in pre-hedging netbacks is primarily due to the increase in crude oil prices. After hedging, ARC's fourth quarter netback was $29.83 per boe, a four per cent increase relative to 2010. ARC's full year 2011 netback after hedging was $31.34 per boe, a seven per cent increase from 2010 due primarily to higher crude oil prices.

ARC's total corporate royalty rate increased to 16.6 per cent ($7.60 per boe) in the fourth quarter of 2011 from 14.3 per cent ($6.03 per boe) in the fourth quarter of 2010 due to higher oil prices and fewer wells qualifying for the Alberta royalty incentive programs applicable to wells drilled between January 1, 2009 and March 31, 2011. The full year 2011 total corporate royalty rate decreased to 15.2 per cent ($7.20 per boe) from 15.9 per cent ($7.14 per boe) for the full year 2010 due to the higher proportion of natural gas production and low natural gas prices in 2011 relative to 2010.

Fourth quarter operating costs increased four per cent to $9.40 per boe relative to $9.01 per boe in the fourth quarter of 2010. Higher fourth quarter operating costs were primarily attributed to significantly higher power costs with Alberta Power Pool prices averaging $76/MWh during the fourth quarter of 2011 compared to $46/MWh in 2010. Full year 2011 operating costs of $9.70 per boe were unchanged relative to 2010. ARC hedges a portion of electricity costs using risk management contracts that are not recorded directly against the operating costs. Including the impact of gains on ARC's electricity hedge contracts, operating costs would decrease by $0.20 per boe for both the fourth quarter and full year 2011. The impact of these electricity hedge contracts was nil and a gain of $0.01 for the fourth quarter and full year 2010.

The following table details components of operating netbacks for the fourth quarter and full year 2011.


Netbacks	Crude Oil ($/bbl)	Heavy Oil ($/bbl)	Condensate ($/bbl)	Natural Gas ($/mcf)	NGL ($/bbl)	Q4 2011 Total ($/boe)	Q4 2010 Total ($/boe)
Average sales price	93.22	80.60	101.13	3.43	51.02	45.58	42.18
Other	-	-	-	-	-	0.11	0.08
Total sales	93.22	80.60	101.13	3.43	51.02	45.69	42.26
Royalties	(16.30)	(8.17)	(30.32)	(0.41)	(14.26)	(7.60)	(6.03)
Transportation	(0.61)	(1.74)	(0.32)	(0.24)	(0.70)	(1.14)	(1.08)
Operating costs ⁽¹⁾	(16.13)	(20.28)	(6.67)	(1.05)	(5.88)	(9.40)	(9.01)
Netback prior to hedging	60.18	50.41	63.82	1.73	30.18	27.55	26.14
Hedging gain (loss) ⁽²⁾	(3.82)	-	-	0.89	-	2.28	2.50
Netback after hedging	56.36	50.41	63.82	2.62	30.18	29.83	28.64
% of Total	57%	2%	5%	34%	2%	100%	100%

Netbacks	Crude Oil ($/bbl)	Heavy Oil ($/bbl)	Condensate ($/bbl)	Natural Gas ($/mcf)	NGL ($/bbl)	2011 Total ($/boe)	2010 Total ($/boe)
Average sales price	90.05	73.29	96.07	3.83	47.53	47.15	44.88
Other	-	-	-	-	-	0.09	0.08
Total sales	90.05	73.29	96.07	3.83	47.53	47.24	44.96
Royalties	(15.67)	(8.37)	(26.72)	(0.31)	(12.67)	(7.20)	(7.14)
Transportation	(0.57)	(1.78)	(0.29)	(0.26)	(0.45)	(1.18)	(1.10)
Operating costs ⁽¹⁾	(15.98)	(16.80)	(7.36)	(1.07)	(10.52)	(9.70)	(9.70)
Netback prior to hedging	57.83	46.34	61.70	2.19	23.89	29.16	27.02
Hedging gain (loss) ⁽²⁾	(3.87)	-	-	0.92	-	2.18	2.20
Netback after hedging	53.96	46.34	61.70	3.11	23.89	31.34	29.22
% of Total	54%	2%	5%	37%	2%	100%	100%

(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 gains on risk management contracts plus a reversal for unrealized losses on risk management contracts that relate to 2011 production that have been recognized in netback calculations in prior quarters. Foreign exchange, power and interest risk management contracts are excluded from the netback calculation.

Net Income

ARC recorded a fourth quarter net loss of $49 million ($0.17 per share) compared to a loss of $86.8 million ($0.31 per share) in the fourth quarter of 2010. While the increase in fourth quarter production and crude oil prices had a positive impact on netbacks and funds from operations, various non-cash charges reduced ARC's earnings during the quarter. Fourth quarter net income included an $80.1 million unrealized MTM loss on risk management contracts, primarily attributed to an increase in crude oil futures price at the end of 2011 relative to the third quarter ($85.9 million unrealized MTM loss in 2010). Fourth quarter net income also included a $9.4 million unrealized foreign exchange gain attributed to the revaluation of U.S. denominated debt balances caused by the appreciation of the Canadian dollar during the quarter ($14.9 million unrealized foreign exchange gain in 2010).

Full year 2011 net income of $287 million ($1.00 per share) was up 35 per cent from net income of $212.2 million ($0.80 per share) in 2010. Higher production, crude oil prices and netbacks had a positive impact on net income in 2011. Net income included a $16.5 million unrealized MTM loss on risk management contracts ($28.2 million unrealized MTM gain in 2010) and an $89.5 million gain on disposal of producing properties (nil 2010). Full year 2011 net income was reduced by $9.7 million for an unrealized foreign exchange loss attributed to the revaluation of U.S. denominated debt balances caused by the devaluation of the Canadian dollar during 2011 ($26.8 million unrealized foreign exchange gain in 2010).

During the fourth quarter and full year 2011, ARC recorded property impairments of $55.3 and $71.9 million, respectively, due to the decline in future natural gas prices during the period ($30.7 million impairment in fourth quarter and full year in 2010).

As a result of converting from a trust structure to a corporation in January 2011, ARC recorded higher deferred tax expense in the fourth quarter and full year 2011.

Operating Income

Fourth quarter operating income was $74.7 million ($0.26 per share), up 113 per cent from $35.1 million ($0.12 per share) in the fourth quarter of 2010. Full year 2011 operating income of $293.5 million ($1.02 per share) increased 26 per cent relative to 2010. The increase in fourth quarter and full year operating income was primarily due to higher production in 2011 and higher netbacks attributed to increased crude oil prices and higher cash hedging gains in 2011.

Following is a summary of operating income for the fourth quarter and full year 2011 and 2010.


		Three Months Ended December 31		Year Ended December 31
		2011	2010	2011	2010
Net income		(49.0)	(86.8)	287.0	212.2
Add (deduct) non-operating items, net of tax:
	Unrealized (gain) loss on risk management contracts	59.3	74.2	12.2	(24.4)
	Unrealized loss on risk management contracts relating to 2011 production ⁽¹⁾	28.2	-	-	-
	Unrealized (gain) loss on foreign exchange	(7.0)	(12.9)	7.2	(23.2)
	Loss (gain) on disposal of petroleum and natural gas properties	2.4	-	(66.2)	-
	Impairment of property, plant and equipment	40.9	26.5	53.2	26.5
	Unrealized (gain) loss on short-term investment	(0.1)	-	0.2	(0.9)
	Loss on revaluation of exchangeable shares	-	34.0	-	42.2
Operating Income - $ millions ⁽²⁾		74.7	35.1	293.5	232.6
Operating Income - $ per share ⁽²⁾		0.26	0.12	1.02	0.88

(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. Throughout 2011, ARC has applied the portion of losses associated with these contracts to the operating income calculation in the production period to which they relate to more appropriately reflect the funds from operations generated during the period after any effect of contracts used for economic hedging. At December 31, 2011, all gains and losses associated with these contracts have been realized, and in the fourth quarter losses previously applied to past production periods are reversed.

(2)

Operating income is not a recognized performance measure under GAAP and does not have a standardized meaning prescribed by GAAP. The term "operating income" is defined as net income excluding the impact of after-tax loss on unrealized gains and losses on risk management contracts, after-tax unrealized gains and losses on foreign exchange, after-tax gains and losses on short-term investments, after-tax gains and losses on revaluation of exchangeable shares, after-tax impairment (recovery) on property, plant and equipment, after-tax gains on disposal of petroleum and natural gas properties and the effect of changes in statutory income tax rates. ARC believes that adjusting net income for these non-operating items presents a better measure of financial performance that is more comparable between periods. The most directly comparable measure of operating income calculated in accordance with GAAP is net income.

Debt Management

ARC closed the year with a strong balance sheet with net debt to total capitalization of 11 per cent. Net debt to annual funds from operations was 1.1 times, within the range of ARC's target of 1.0 to 1.5 times. Debt levels increased slightly relative to year-end 2010 levels as a result of strong funds from operations and proceeds of $170 million from property sales early in 2011.

ARC's has total credit capacity of $1.6 billion, comprised of a $1 billion revolving credit facility and $559 million of private notes. At December 31, ARC had borrowings of $323.8 million under the credit facility, $437.9 million of private notes and a working capital deficit of $148 million, leaving approximately $674 million of total available credit capacity. Approximately 57 per cent of outstanding debt is fixed-rate with a weighted average remaining term of 5.3 years.

Risk Management

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

ARC realized cash gains on natural gas hedging contracts in the fourth quarter and full year 2011 of $29.0 million and $103.9 million, respectively. ARC hedged approximately 45 per cent and 41 per cent of fourth quarter and full year 2011 natural gas production at average floor prices of Cdn$5.76 per mcf and Cdn$5.45 per mcf, respectively, well above the fourth quarter and full year 2011 average market prices of Cdn$3.47 per mcf Cdn$3.67 per mcf, respectively.

ARC realized cash losses on crude oil hedging contracts in the fourth quarter and full year 2011 of $47.9 million and $37.2 million, respectively. Fourth quarter crude oil cash hedging losses of $47.9 million included a cash loss of $50.3 million on crude oil annual-settled call contracts relating to volumes hedged for the full year 2011. Unlike the majority of ARC's risk management contracts which settle monthly, these annual-settled call contracts are cash settled in their entirety on an annual basis and therefore were reflected as a cash loss in the fourth quarter based on the full year settlement loss of $50.3 million. ARC hedged approximately 62 per cent and 59 per cent of fourth quarter and full year 2011 crude oil production at average floor/ceiling prices of US$84/US$89 per barrel, relative to fourth quarter and full year 2011 average market prices of US$94.11 per barrel and US$95.11 per barrel, respectively.

Floor prices on crude oil and natural gas hedged volumes for 2012 provide a level of certainty for ARC to execute its business plan over the next year. Given the significant contribution of ARC's crude oil and natural gas liquids production to total sales and funds from operations, ARC management recognizes the risk associated with an unanticipated reduction in crude oil pricing. Accordingly, ARC has protected the selling price on a portion of crude oil production by establishing crude oil floor and ceiling prices through 2013. ARC expects to continue to execute its Risk Management program on volumes going forward, increasing hedged volumes in 2013. In total, ARC currently has hedged approximately 42 per cent and 8 per cent per cent of total production for 2012 and 2013, respectively, as summarized in the table below. For a complete listing and terms of ARC's hedging contracts, see Note 16 "Financial Instruments and Market Risk Management" in the audited Consolidated Financial Statements for the year ended December 31, 2011.


Hedge Positions Summary ⁽¹⁾ As at February 7, 2012		2012		2013
Crude Oil ⁽²⁾		US$/bbl	bbl/day	US$/bbl	bbl/day
	Bought Call	116.25	4,000	-	-
	Sold Call	91.11	18,000	102.51	7,984
	Bought Put	90.00	18,000	92.51	7,984
	Sold Put	63.44	16,000	63.33	6,000
Natural Gas ⁽³⁾		Cdn$/mcf	mcf/day	Cdn$/mcf	mcf/day
	Swap	3.66	123,456	-	-

(1)	The prices and volumes noted above represent averages for several contracts representing different periods 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 2012 and 2013, all put positions settle against the monthly average WTI price, providing protection against monthly volatility. Calls have been sold against either the monthly average or the annual average WTI price. In the case of settlements on annual positions, 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.
(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 fixed sales price of $4.20 per mmbtu for 2012.

ARC's fourth quarter unrealized MTM loss of $80.1 million on commodity hedging contracts was due primarily to an increase in crude oil forward prices as at December 31, 2011 relative to the third quarter. The actual future cash settlements under the commodity hedge contracts will differ from the current unrealized MTM value with changes in commodity prices in future periods.

OPERATIONAL REVIEW

ARC spent $195 million during the fourth quarter and $726 million in full year 2011 on drilling, facilities, optimization and exploration activities and the purchase of crown lands. ARC drilled 48 gross (46 net) operated wells comprising 46 gross (44 net) oil wells and 2 gross (2 net) natural gas wells with a 100 per cent success rate in the fourth quarter. This brings the total wells drilled in 2011 to 133 gross (124 net) oil wells and 31 gross (30 net) natural gas wells with a 100 per cent success rate. Oil and liquids-rich natural gas wells represented 91 per cent of total wells drilled in 2011, reflecting ARC's strategy to capitalize on the strength of oil prices through acceleration of oil and liquids projects in 2011 and 2012.

Fourth quarter production of 92,021 boe per day was up nine per cent relative to the fourth quarter of 2010. Fourth quarter production comprised 64 per cent natural gas and 36 per cent crude oil and liquids. Higher natural gas production was primarily attributed to the start-up of the 60 mmcf per day Dawson Phase 2 gas plant in the second quarter of 2011. The increase in fourth quarter crude oil and liquids production was attributed to new wells drilled, predominantly at Ante Creek, Pembina, and Goodlands.

For additional information regarding ARC's fourth quarter and full year 2011 operations, see January 26, 2012 news release "ARC Resources Ltd. announces 18 per cent increase in 2011 year-end reserves and results of updated independent resources evaluation for northeast British Columbia Montney Assets".

For additional information regarding ARC's 2012 capital program, see November 2, 2011 news release "ARC Resources Ltd. announces a $760 million capital budget for 2012, which includes a 12 per cent production growth target".

DIVIDENDS

ARC paid dividends totaling $0.30 per share for the fourth quarter of 2011 and $1.20 per share for the full year 2011. The Board of Directors has confirmed a dividend of $0.10 per share for January 2012, payable on February 15, 2012, and has conditionally declared a monthly dividend of $0.10 per share, payable monthly for February 2012, March 2012 and April 2012, targeting a total dividend of $0.30 per share for the first quarter of 2012. The dividends have been designated as eligible dividends under the Income Tax Act (Canada) and are payable as follows:


Ex-dividend date	Record date	Payment date	Per share amount
January 27, 2012	January 31, 2012	February 15, 2012	$0.10 ⁽¹⁾
February 24, 2012	February 28, 2012	March 15, 2012	$0.10 ⁽²⁾
March 29, 2012	March 31, 2012	April 16, 2012	$0.10 ⁽²⁾
April 27, 2012	April 29, 2012	May 16, 2012	$0.10 ⁽²⁾

(1)	Confirmed on January 16, 2012.
(2)	Conditionally declared, subject to confirmation by news release and further resolution by the Board of Directors.

See "Outlook" for additional discussion regarding Dividends.

CORPORATE INCOME TAX

On December 15, 2011 Federal Bill C-13 received royal assent and implemented the measure introduced in the June 2011 budget to limit the ability of a corporation to defer the taxation of income earned through a partnership. ARC's oil and natural gas properties are directly owned and operated by ARC Resources General Partnership, which has a January 31 year-end. ARC expects that it will be taxable in 2012 as a result of the loss of the deferral on partnership income.

Cash taxes payable in 2012 will largely be based on 2011 taxable income as the partnership has a January 31 year-end. ARC currently expects to pay cash income taxes of approximately $40 million in 2012.

OUTLOOK

ARC's business strategy will remain unchanged in 2012. With a Board approved $760 million capital program in 2012, our primary focus is to maximize value by directing capital to oil and liquids-rich natural gas projects to capitalize on the strength of crude oil prices. ARC plans to drill approximately 195 gross wells (182 net) on its operated properties, with 179 wells targeting oil, 13 wells targeting liquids-rich natural gas and three wells targeting dry natural gas. On ARC's non-operated properties we anticipate our partners will drill 44 gross wells (6 net). ARC will continually review drilling and infrastructure programs to ensure that projects meet targeted rates of return in accordance with our normal course risk-managed value creation operating criteria.

ARC has a balanced portfolio of high-quality assets with 70 per cent of current sales from oil, condensate and natural gas liquids and 30 per cent from the sale of natural gas. The mix of liquids and natural gas in our portfolio has enabled us to respond to the prolonged, low natural gas price environment effectively by redirecting a portion of capital to oil and liquids projects that generate significant returns and cash flow relative to near-term dry gas projects. The United States continued to establish new natural gas production records during 2011. Consequently, North American natural gas inventories are at record highs and natural gas prices declined considerably in 2011 relative to 2010 and have decreased further in 2012.

In the prevailing environment of low natural gas prices, development of dry gas projects is a less strategic priority in our near-term strategy. A further decrease in natural gas prices will impact ARC's funds from operations, level of capital expenditures, and may result in certain natural gas properties being shut-in. ARC is fortunate to be in properties such as Dawson where we are centered on the "sweet spot" of a dry gas resource and returns remain competitive, even at a Cdn$3 field gas price. Our asset portfolio provides for optionality and we may choose to favour investments in liquids-rich opportunities that offer higher rates of return. ARC is currently reviewing the implications of the current natural gas pricing on the timing of the on-stream date for the proposed Sunrise 60 mmcf per day gas plant. ARC has approval from the B.C. Oil and Gas Commission to construct two 60 mmcf per day gas plants at Sunrise; early well performance from the wells that are producing and on test is promising. As minimal cost is required at this point to continue towards the original timeline, ARC will evaluate this project and provide further guidance in our first quarter 2012 financial and operational review.

ARC expects to finance its 2012 capital program with funds from operations, proceeds from the Dividend Re-investment Plan ("DRIP"), existing credit lines and proceeds from the disposition of minor and non-strategic assets. During 2011, ARC funded 98 per cent of its net capital expenditures of $614.7 million with funds from operations and the DRIP. Proceeds from net dispositions of $111 million were used to fund a portion of ARC's internal development program and enabled ARC to execute its $726 million internal development program while holding year-over-year debt balances essentially flat. ARC will continue its asset redeployment strategy in 2012 and beyond to high grade the asset base with the objective of enhancing shareholder value.

ARC believes that full year 2012 production volumes will average 90,000 - 95,000 boe per day. All 2012 guidance estimates are summarized in the following table.


		2012 Guidance	2011 Guidance	2011 Actual	% Variance
Production (boe/d)		90,000 - 95,000	82,000 - 83,000	83,416	1
Expenses ($/boe):
	Operating	9.55 - 9.95	9.40 - 9.70	9.70	-
	Transportation	1.00 - 1.10	1.10 - 1.20	1.18	-
	General and administrative ⁽¹⁾	2.30 - 2.50	2.50 - 2.70	2.63	-
	Interest	1.10 - 1.20	1.25 - 1.40	1.28	-
Corporate taxes ⁽²⁾		1.10 - 1.25	-	-	-
Capital expenditures ($ millions)		760	730	726	-
Diluted shares (millions)		293	286	287	-

(1)

The 2012 Guidance for general and administrative cost per boe is based on a range of $1.75 - $1.90 per boe prior to the recognition of any expense associated with ARC's long-term incentive plan, $0.75-$0.80 per boe associated with cash payments under ARC's long-term incentive plan, and the remainder represents the non-cash "accrued" compensation under ARC's long-term incentive plan. Actual per boe costs for each of these components for the year ended December 31, 2011 were $1.83 per boe, $0.67 per boe offset by a recovery of $0.13 per boe, respectively.

(2)

The 2012 corporate tax estimate will vary depending on the level of commodity prices.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

Effective January 1, 2011 all Canadian publicly accountable enterprises are required to prepare their financial statements in accordance with International Financial Reporting Standards ("IFRS"). ARC has prepared its audited Consolidated Financial Statements for the year ended December 31, 2011 under IFRS and has restated its audited Consolidated Financial Statements for the year ended December 31, 2010 to comply with IFRS. For further information on ARC's transition to IFRS and a reconciliation of its affected financial information for the year ended December 31, 2010, please refer to Note 23, "Explanation of Transition to International Financial Reporting Standards" in the audited Consolidated Financial Statements for the year ended December 31, 2011 and 2010 filed on SEDAR at www.sedar.com.

SUPPLEMENTAL FINANCIAL INFORMATION CONSOLIDATED BALANCE SHEETS (unaudited)
As at December 31 and January 1
(Cdn$ millions)		December 31, 2011		December 31, 2010		January 1, 2010
ASSETS
Current assets
	Cash and cash equivalents	$	0.5	$	2.0	$	-
	Short-term investment		3.3		3.5		-
	Accounts receivable		168.1		160.5		115.9
	Prepaid expenses		14.3		12.0		18.2
	Risk management contracts		21.0		66.8		5.9
	Assets held for sale		4.6		123.9		-
			211.8		368.7		140.0
Reclamation funds			26.9		25.0		33.2
Risk management contracts			3.7		0.6		3.2
Property, plant and equipment			4,645.6		4,343.2		3,550.4
Intangible exploration and evaluation assets			187.7		74.4		23.0
Goodwill			248.2		248.2		157.6
Total assets		$	5,323.9	$	5,060.1	$	3,907.4

LIABILITIES
Current liabilities
	Accounts payable and accrued liabilities	$	305.0	$	211.7	$	166.7
	Current portion of long-term debt		40.5		15.7		27.0
	Dividends payable		28.9		27.7		23.7
	Risk management contracts		18.9		22.0		12.9
	Exchangeable shares		-		-		47.2
	Liabilities associated with assets held for sale		1.9		18.0		-
			395.2		295.1		277.5
Risk management contracts			3.0		20.9		1.0
Long-term debt			721.2		787.8		819.1
Long-term incentive compensation liability			18.5		26.6		10.9
Other deferred liabilities			21.4		25.0		-
Asset retirement obligations			496.4		381.7		298.1
Deferred taxes			506.4		410.6		255.1
Total liabilities			2,162.1		1,947.7		1,661.7


SHAREHOLDERS' EQUITY
	Shareholders' capital		3,218.3		3,112.5		2,898.3
	Contributed surplus		0.5		-		-
	Deficit		(57.0)		-		(652.0)
	Accumulated other comprehensive loss		-		(0.1)		(0.6)
Total shareholders' equity			3,161.8		3,112.4		2,245.7
Total liabilities and shareholders' equity		$	5,323.9	$	5,060.1	$	3,907.4

CONSOLIDATED STATEMENTS OF INCOME (unaudited)
For the three and twelve months ended December 31

		Three Months Ended December 31				Twelve Months Ended December 31
(Cdn$ millions, except per share amounts)		2011		2010		2011		2010

Sales of crude oil, natural gas and natural gas liquids		$	386.8	$	329.3	$	1,438.2	$	1,213.7
Royalties			(64.3)		(47.0)		(219.3)		(192.8)
REVENUE			322.5		282.3		1,218.9		1,020.9

(Loss) gain on risk management contracts			(96.1)		(65.9)		59.3		93.6
			226.4		216.4		1,278.2		1,114.5

EXPENSES
	Transportation		9.7		8.4		36.1		29.7
	Operating		79.6		70.2		295.3		261.9
	Exploration and evaluation expenses		-		0.8		-		0.8
	General and administrative		18.6		34.7		80.1		91.6
	Interest and financing charges		9.2		10.5		38.9		42.5
	Accretion of asset retirement obligation		3.3		3.4		13.4		12.6
	Depletion, depreciation and amortization and impairment		178.1		137.9		509.2		408.7
	(Gain) loss on foreign exchange		(8.8)		(15.1)		10.5		(26.8)
	Loss on revaluation of exchangeable shares		-		39.4		-		48.8
	(Gain) loss on short-term investments		(0.1)		-		0.2		(0.9)
	Gain on disposal of petroleum and natural gas properties		3.2		-		(89.5)		-
			292.8		290.2		894.2		868.9
Capital and other taxes			-		0.1		-		0.2
Deferred tax (recovery) expense			(17.4)		12.9		97.0		33.2
Net (loss) income		$	(49.0)	$	(86.8)	$	287.0	$	212.2

Net income per share
	Basic	$	(0.17)	$	(0.31)	$	1.00	$	0.82
	Diluted	$	(0.17)	$	(0.31)	$	1.00	$	0.80

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
For the three and twelve months ended December 31
		Three Months Ended December 31				Twelve Months Ended December 31
(Cdn$ millions)			2011		2010		2011		2010

Net income (loss)		$	(49.0)	$	(86.8)	$	287.0	$	212.2

Other comprehensive income, net of tax
	Gains on financial instruments designated as cash flow hedges		-		0.5		-		0.5
	Gains (losses) on financial instruments designated as cash flow hedges in prior periods realized in net income in the current year		-		(0.2)		-		0.1
	Net unrealized gains (losses) on available-for-sale reclamation funds' investments		0.1		(0.1)		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			0.1		-		0.1		0.5
Comprehensive income		$	(48.9)	$	(86.8)	$	287.1	$	212.7

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (unaudited)
For the years ended December 31

(Cdn$ millions)
	Shareholders' Capital		Contributed Surplus		Deficit		Accumulated other comprehensive 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		7.9		-		-		-		7.9
Trust units issued pursuant to the distribution reinvestment program		74.4		-		-		-		74.4
Trust unit issue costs⁽¹⁾		(10.7)		-		-		-		(10.7)
Comprehensive income		-		-		212.2		0.5		212.7
Distributions declared		-		-		(313.5)		-		(313.5)
Issued for exchangeable shares pursuant to the Arrangement (Note 1)		194.4		-		-		-		194.4
Elimination of deficit pursuant to the Arrangement		(753.3)		-		753.3		-		-
December 31, 2010	$	3,112.5	$	-	$	-	$	(0.1)	$	3,112.4
Shares issued pursuant to the dividend reinvestment program		105.8		-		-		-		105.8
Share options granted		-		0.5		-		-		0.5
Comprehensive income		-		-		287.0		0.1		287.1
Dividends declared		-		-		(344.0)		-		(344.0)
December 31, 2011	$	3,218.3	$	0.5	$	(57.0)	$	-	$	3,161.8

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
For the three and twelve months ended December 31
		Three Months Ended				Twelve Months Ended
		December 31				December 31
(Cdn$ millions)		2011		2010		2011		2010

CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income		$	(49.0)	$	(86.8)	$	287.0	$	212.2
Add items not involving cash:
	Unrealized (gain) loss on risk management contracts		80.1		85.9		16.5		(28.2)
	Accretion of asset retirement obligation		3.3		3.4		13.4		12.6
	Depletion, depreciation and amortization and impairment		178.1		137.9		509.2		408.7
	Exploration and evaluation expenses		-		0.8		-		0.8
	(Gain) loss on foreign exchange		(9.4)		(14.9)		9.7		(26.8)
	(Gain) loss on disposal of petroleum and natural gas properties		3.2		-		(89.5)		-
	Deferred tax (recovery) expense		(17.4)		12.9		97.0		33.2
	Other		(0.4)		41.3		1.0		54.5
Net change in other liabilities			4.1		12.4		(9.6)		7.9
Change in non-cash working capital			36.9		(9.2)		68.0		2.1
			229.5		183.7		902.7		677.0

CASH FLOW FROM FINANCING ACTIVITIES
Issue (repayment) of long-term debt under revolving
credit facilities, net			98.6		45.2		(35.2)		(241.3)
Issue of Senior Notes			-		-		-		210.4
Repayment of Senior Notes			(9.7)		(15.6)		(16.3)		(81.4)
Issue of shares			0.3		0.6		1.6		241.8
Cash dividends paid			(59.6)		(59.5)		(238.7)		(237.1)
			29.6		(29.3)		(288.6)		(107.6)

CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of petroleum and natural gas properties			(23.0)		(1.2)		(57.8)		(9.0)
Disposals of petroleum and natural gas properties			(1.2)		0.4		167.6		3.9
Property, plant and equipment development expenditures			(175.7)		(155.8)		(614.8)		(537.9)
Exploration and evaluation expenditures			(18.3)		(0.2)		(113.3)		(51.4)
Net reclamation fund (contributions) withdrawals			(1.2)		8.1		(1.8)		8.3
Change in non-cash working capital			(39.7)		(4.0)		4.5		18.7
			(259.1)		(152.7)		(615.6)		(567.4)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			-		1.7		(1.5)		2.0
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			0.5		0.3		2.0		-
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	0.5	$	2.0	$	0.5	$	2.0

The following amounts are included in Cash Flows From Operating Activities:
Income taxes paid in cash		$	-	$	-	$	1.7	$	-
Interest paid in cash		$	11.0	$	9.6	$	25.8	$	20.6

Forward-looking Information and Statements

This news release 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 news release contains forward-looking information and statements pertaining to the following: guidance as to the capital expenditure plans of ARC under the heading "Financial and Operational Highlights", as to its risk management plans for 2013 under the heading "Risk Management", as to its taxability for 2012 under the heading "Corporate Income Tax", and all matters including 2012 guidance under the heading "Outlook".

The forward-looking information and statements contained in this news release reflect 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 Funds from operations 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.

ARC Resources Ltd. ("ARC") is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC expects 2012 oil and gas production to average 90,000 to 95,000 barrels of oil equivalent per day from its properties in western Canada. ARC's Common Shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Announces 18 per cent Increase in 2011 Year-End Reserves and Results of Updated Independent Resources Evaluation for Northeast British Columbia Montney Assets

Thu, 26 Jan 2012 20:32:00 -0500

Jan 26, 2012

CALGARY, Jan. 26, 2012 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") released today its
2011 year-end reserves and resources information.

HIGHLIGHTS

Proved plus probable ("2P") reserves increased 18 per cent to 572 mmboe, comprised of 2.4 Tcf of natural gas and 170 mmbbls of liquids, at year-end 2011
Proved reserves increased eight per cent to 360 mmboe at year-end 2011
ARC achieved record production of 92,021 boe per day and 83,416 boe per day for the fourth quarter and full year 2011, respectively, due to a strong 2011 drilling program that delivered 13 per cent year-over-year production growth. Full year 2011 production was comprised of 62 per cent natural gas production and 38 per cent crude oil and liquids production.
ARC replaced 385 per cent of 2011 production, adding 117 mmboe of 2P reserves after the net divestment of non-core properties with associated 2P reserves of 14.6 mmboe in 2011
Finding and Development costs ("F&D") of $5.50 per boe for 2P reserves and $10.84 per boe for proved reserves excluding Future Development Capital ("FDC")
All-in annual Finding, Development and Acquisition ("FD&A") costs of $5.24 per boe for 2P reserves, excluding FDC, represent ARC's lowest annual FD&A costs since 2001
Recycle ratio of 5.3 times and 5.0 times for the current year and three year average, respectively, for 2P reserves based on 2011 F&D costs excluding FDC and 2011 netback of $29.16 per boe
Increase in 2P and proved Reserve Life Index ("RLI") to 17 years and 10.7 years, respectively, based on the mid-point 2012 production guidance of 92,500 boe per day
Crude oil and natural gas liquids ("NGL's") reserves comprise 30 per cent of total 2P reserves at year-end 2011
2P reserves per share increased 16 per cent and proved reserves per share increased six per cent relative to year-end 2010
Total 2P reserves for the Montney in NE B.C.increased to 1.9 Tcf of natural gas and 21 mmbbls of NGL's, a 48 per cent increase over year-end 2010 reserves of 1.3 Tcf of natural gas and 12.5 mmbbls of NGL's. Reserves have been assigned to 146 net sections on ARC's total land position of 434 net sections in this region.
ARC commissioned an Independent Resources Evaluation ("Resources Evaluation" or "Independent Resources Evaluation") for its Montney lands in the northeast British Columbia ("NE B.C.") Montney region ⁽¹⁾. The findings confirm that the Montney is a significant long-term growth opportunity with considerable potential reserves, which go well beyond existing booked reserves and even the current estimates of the Economic Contingent Resource ("ECR"). In addition to year-end 2011 2P reserves of 1.9 Tcf of natural gas and 21 mmbbls of NGL's, the Resources Evaluation assigned an ECR best estimate of 4.1 Tcf of natural gas and 101 mmbbls of liquids. As part of this study and based on a zero per cent porosity cut-off, the estimate of Discovered Petroleum Initially in Place ("DPIIP") has increased to 25.5 Tcf (21.2 Tcf at a three per cent porosity cut-off) and the estimate of Total Petroleum Initially in Place ("TPIIP") was identified to be 50.4 Tcf (39.6 Tcf at a three per cent porosity cut-off). ARC estimates that approximately $54 million would need to be spent to drill and complete sufficient wells on ARC's land base in order to reclassify all of the TPIIP into DPIIP.
Total 2P reserves plus the ECR represent less than 13 per cent of the TPIIP based upon a zero per cent porosity cut-off (approximately 15 per cent of TPIIP based upon a three per cent porosity cut-off). ARC expects the ultimate recovery may exceed this level with the long-term natural gas price being the primary determinant of ultimate recovery.
ARC continues to update its long-term development plan as resource estimates grow with a range of scenarios being developed to reflect a range of potential recovery factors of the substantial NE B.C. Montney natural gas and liquids resource.

(1)

References to NE B.C. Montney pursuant to the Independent Resources Evaluation throughout this new release includes Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown, and Blueberry located in B.C. and Pouce Coupe located in Alberta.

RESOURCES AND RESERVES DISCUSSION AND ANALYSIS

The following discussion in "NE B.C. Montney Resources and Reserves", "Ante Creek Montney Resources and Reserves "and "2011 Operational and Property Review" is subject to a number of cautionary statements, assumptions and risks as set forth therein. See "Information Regarding Disclosure on Oil and Gas Resources and Operational Information" for additional cautionary language, explanations and discussion and "Forward Looking Statements" for a statement of principal assumptions and risks that may apply. See also "Definitions of Oil and Gas Reserves, Resources and Reserves". The discussion includes reference to TPIIP, DPIIP and ECR as per the GLJ Petroleum Consultants Ltd. ("GLJ") Resources Evaluation as at December 31, 2011, prepared in accordance with the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Unless indicated otherwise in this news release, all references to ECR volumes are Best Estimate ECR volumes.

There is no certainty that it will be commercially viable to produce any of the resources that are categorized as discovered resources. There is no certainty that any portion of ARC's resources that have been categorized as undiscovered resources will be discovered. Furthermore, if discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered resources.

MONTNEY RESOURCES AND RESERVES

ARC's inventory of value-creating opportunities continue to expand at a rapid pace with the Montney formation in NE B.C. being the primary area of major resource expansion. In both dry gas and liquids-rich gas resource plays, the cycle time from drilling the initial discovery well to significant production coming on-stream often requires new infrastructure such that our current internal development plans span well beyond the period of production growth included in our year-end reserves report. We have successfully continued to move DPIIP into ECR, ECR into 2P reserves and probable reserves into proved reserves at a steady pace. Notably, our year-end 2011 2P reserves have increased by an amount equal to the ECR estimate released just 12 months ago. Since ARC's strategic plan and capital allocation decisions are based upon our assessment of the complete scale of the identified opportunities, rather than the subset of those opportunities which are currently booked as 2P reserves or identified as ECR, the discussion presented herein focuses on our total resource opportunity.

The DPIIP and TPIIP estimates presented herein for the NE B.C. Montney formation have been prepared by our independent reserve evaluators, GLJ, based upon mapping supported by significant well control. As with any reserve or resource estimate, the value will change over time as new information becomes available. At this time, ARC believes the TPIIP to be the most appropriate estimate of the opportunity that exists for the NE B.C. Montney and forms the basis for our ongoing short-term and long-term strategic decisions. Therefore, it is extremely relevant to the discussion of our resource and potential future reserve opportunities.

When conducting reserve and resource assessments, the process traditionally includes estimates of the level of porosity in the rock below which the reservoir fluids are not expected to contribute to future production and reserves; this is referred to as the "porosity cut-off". In new resource plays where the technology is enabling our industry to extract commercial production rates from rock previously believed to be "too tight" to produce, it is uncertain as to what the correct porosity cut-off is. In the early days of developing the Montney formation at Dawson, ARC used a six per cent porosity cut-off which was subsequently reduced to three per cent based upon the performance of the wells. GLJ's resource assessment continues to reflect the use of a three per cent porosity cut-off, ARC however believes the three per cent porosity cut-off may be too high based on continued strong performance within Dawson. For the purposes of this disclosure, the DPIIP and TPIIP results do not impose a porosity cut-off unless otherwise indicated, therefore, the discussion and analysis becomes focused on what the best estimate of the recovery factor will be over time rather than adjusting the in-place resource estimates and the recovery factor on an ongoing basis. By removing the porosity cut-off, expected recovery factors have been lowered accordingly; future production performance will be used to refine the recovery factor estimates. Footnotes have been added to certain tables presented herein to identify how the referenced volumes would change if a three per cent porosity cut-off was to be imposed on the in-place volume calculation. For information purposes, ARC's TPIIP at a three per cent porosity cut-off is estimated to be 39.6 Tcf which represents 78 per cent of the estimated TPIIP of 50.4 Tcf at a zero per cent porosity cut-off; this speaks to the high quality of the Montney formation on ARC's lands.

NE B.C. Montney Resource Discussion and Analysis

The Montney formation in NE B.C. has been identified as a world class unconventional natural gas resource play with the potential for significant volumes of recoverable resources. The area includes both dry gas and liquids-rich gas opportunities. It is one of the largest and lowest cost natural gas resource plays in North America and is expected to serve as the anchor supply to support major liquefied natural gas ("LNG") projects currently being planned for the west coast of British Columbia. ARC has a significant presence in the region with a land position of 434 net sections; this represents one of the largest land positions of any operator in the most prospective areas of the play.

Since 2003, when ARC first established a presence in the region, we have become a key player having increased total 2P reserves from 110 Bcf to 1.9 Tcf of natural gas and 21 mmbbls of NGL's, increased production from 17 mmcf per day to 235 mmcf per day of natural gas and 1,800 bbls per day of liquids and significantly expanded its land base from 62 net sections to 434 net sections. At present, ARC's NE B.C. Montney portfolio includes ownership in Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown, and Blueberry. Although the Montney in this region is typically thought of as a dry gas reservoir, recent drilling conducted by ARC at Tower, Septimus and Attachie has tested liquids-rich gas and/or light oil.

In an effort to better understand ARC's long-term future reserve and resource potential in the NE B.C. Montney, GLJ was commissioned to conduct an Independent Resources Evaluation for ARC's lands in the region including Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown, and Blueberry in northeastern B.C and Pouce Coupe just across the border in Alberta (the "Evaluated Areas"). The Resources Evaluation was conducted effective December 31, 2011 based on GLJ forecast pricing as at January 1, 2012. All references in the following discussion to ECR, TPIIP and DPIIP are in reference to the Evaluated Areas included in the Independent Resources Evaluation. See "Definitions of Oil and Gas Resources and Reserves".

The following map illustrates the Evaluated Areas included in the Independent Resources Evaluation.

Following is a summary of ARC's land base within the Evaluated Areas.

Table 1


NE B.C. Montney Resources and Reserves Land Base - December 31, 2011⁽¹⁾
Evaluated Areas	ARC Lands Net Sections	Net sections with DPIIP	Net sections with 2PReserves	Liquids Yield (bbls/mmcf)
Dawson	129	119	74	5
Parkland	23	23	20	20 - 40
Tower	48	35	6	50 - 200
Sunrise/Sunset	32	32	27	5
Attachie	115	78	10	30 - 200
Septimus	22	20	7	5 - 30
Pouce Coupe	26	21	2	5
Sundown	18	6	0	5
Blueberry	21	5	0	0 - 200
TOTAL NET SECTIONS	434	339	146

DPIIP has been assigned on 339 net sections, representing 78 per cent of ARC's land base of 434 net sections in the Evaluated Areas. To date, 2P reserves have been assigned on 146 net sections, representing 34 per cent of ARC's landholdings in this region.

In addition to consistently adding reserves at a low F&D cost, ARC has developed an inventory of ECR in excess of the 2P reserves in the NE B.C. Montney region. GLJ has estimated the 2P reserves to be 1.9 Tcf of natural gas and 21 mmbbls of NGL's. In addition to 2P reserves, GLJ has estimated the ECR to be 4.1 Tcf of natural gas and 101 mmbbls of NGL's effective December 31, 2011, up significantly from 0.7 Tcf of natural gas and 4 mmbbls of NGL's at year-end 2010. TPIIP of 50.4 Tcf was assigned on ARC's 434 net sections of Montney lands in NE B.C. The TPIIP is comprised of 25.5 Tcf of DPIIP and 24.9 Tcf of UPIIP. The following tables summarize the results of the Independent Resources Evaluation.

Table 2a

Resource Categories ^(1)(2)(3)

Tcf

Total Petroleum Initially In Place (TPIIP)

50.4

Discovered Petroleum Initially In Place (DPIIP)

25.5

Undiscovered Petroleum Initially In Place (UPIIP)

24.9

(1)			TPIIP, DPIIP and UPIIP have been estimated using a zero percent porosity cut-off which means all gas bearing rock has been incorporated into the calculations. Using a three per cent porosity cut-off the TPIIP, DPIIP and UPIIP estimates would be 39.6 Tcf, 21.2 Tcf, and 18.4 Tcf, respectively.
(2)			The Resource Categories do not include the free oil/liquids or associated solution gas in the Tower field. Refer to Tower commentary in "2011 Operational and Property Review".
(3)			All volumes in table are company gross and raw gas volumes.

Table 2b

Reserves and Economic Contingent Resources ^(1)(2)(6)

Low
Estimate

Best
Estimate

High
Estimate

Natural Gas (Tcf)

Reserves ⁽³⁾

1.0

1.9

2.4⁽⁴⁾

Economic Contingent Resources

2.5

4.1

5.7

Natural Gas Liquids(mmbbls)⁽⁵⁾

Reserves ⁽³⁾

11.3

21.1

26.6

Economic Contingent Resources

64.2

101.0

133.9

(1)			All DPIIP other than cumulative production, reserves, and ECR has been categorized as unrecoverable.
(2)			All volumes in table are company gross and sales volumes.
(3)			For reserves, the volume under the heading Low Estimate are proved reserves, the volume under the heading Best Estimate are 2P reserves and the number under the heading High Estimate are 2P plus possible reserves.
(4)			This volume is an arithmetic sum of multiple estimates of reserves, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of reserves and appreciate the differing probabilities associated with each class.
(5)			The liquid yields are based on average yield over the producing life of the property.
(6)			Cumulative production has been 0.2 Tcf on a raw basis.

Table 2c

Prospective Resources ⁽¹⁾⁽²⁾

Low
Estimate

Best
Estimate

High
Estimate

Natural gas (Tcf)

2.9

4.0

5.3

Natural gas liquids (mmbbls)

69.0

98.0

131.2

(1)			All UPIIP other than Prospective Resources has been categorized as unrecoverable.
(2)			All volumes in table are company gross and sales volumes.

TPIIP consists of both DPIIP and UPIIP. In the Independent Resources Evaluation, DPIIP was generally ascribed to ARC's properties which were located within a three mile radius of a hydrocarbon test, and UPIIP was ascribed to ARC's properties which were located outside of a three mile radius but within an area where the reservoir is believed to contain hydrocarbons. TPIIP is a raw gas number and in some areas contains variable amounts of hydrocarbon liquids (propane, butane and condensate). Management estimates that approximately $54 million would need to be spent to drill and complete sufficient wells on ARC's land base within a three mile radius of known gas tests in order to reclassify the UPIIP to DPIIP.

Resource plays of this nature evolve based upon increased knowledge and confidence derived from ongoing drilling and production activities. The following table illustrates the growth which has been delivered in NE B.C. Montney reserves and resources in the Evaluated Areas over the past five years.

Table 3
	NE B.C Montney Historic Reserves and Resources
		Proved plus Probable Reserves		Economic Contingent Resource		DPIIP
		Natural Gas Tcf	NGL's mmbbls	Natural Gas Tcf	NGL's mmbbls	Tcf
	2011 ⁽¹⁾	1.9	21.1	4.1	101.0	25.5
	2010 ⁽²⁾	1.3	12.5	0.7	4.0	10.1
	2009	0.8	3.4	NA	NA	NA
	2008	0.5	2.1	NA	NA	NA
	2007	0.2	1.0	NA	NA	NA

(1)			Represents the Evaluated Areas included in the 2011 GLJ Independent Resources Evaluation.
(2)			2010 Evaluated Areas included Dawson, Parkland, Sunrise/Sunset, Septimus, and Sundown.

While the year-over-year growth in ECR has been exceptional, the total of cumulative production to date, 2P reserves and ECR still represents less than 13 per cent of the TPIIP, a clear indication of the early stage of the development of ARC's NE B.C. Montney assets. Based on ARC's track record of successfully converting ECR into reserves and growing ECR, management expects that the ECR and reserves will continue to grow as drilling progresses.

This significant growth in reserves and resources is the result of the utilization of multi-stage fracture stimulation of horizontal wells, a technique that ARC pioneered in the Dawson area in 2005. In addition to utilizing this technology throughout our Montney lands, ARC is utilizing horizontal drilling with multi-stage fraccing across our Western Canadian asset base and recently has had success in oil prone reservoirs such as Pembina Cardium, Ante Creek and Goodlands. As evidenced in Table 3, both the DPIIP and ECR have increased considerably over a short period of time. It is for this reason we have now chosen to publish our TPIIP estimate since it is less variable and does in fact form the basis for understanding the progression of resource quantification to commercialization.

ARC has successfully grown its NE B.C. Montney production from 45 mmcf per day in 2008 to over 235 mmcf per day of natural gas and 1,800 bbls per day of liquids at present. This growth has been achieved through staged development and the deployment of an average of $245 million of capital investment per year over the past three years. To continue this growth, significant additional capital will be required. ARC's 2P reserves in the NE British Columbia Montney region now stand at over 1.9 Tcf of natural gas and 21 mmbbls of NGL's. As the 2P reserves grow, the amount of FDC required to bring the reserves to production also increases. The FDC for this region is now estimated by GLJ in our reserve report to be $2.1 billion. We believe the ultimate potential extends well beyond the currently booked 2P reserves and ECR; accordingly, the future capital requirements will also be significantly greater.

As we continue to evolve the development plan for our NE B.C. Montney assets, our perspectives on the ultimate production potential of the assets also continues to evolve. We estimate that the currently assigned 2P reserves plus the current estimate of ECR (combined resource of 6 Tcf of natural gas and 123 mmbbls of liquids) could sustain a peak production rate up to 800 mmcf per day of natural gas and 17,000 bbls per day of liquids for ten years. This compares to fourth quarter 2011 production from this area of approximately 235 mmcf per day of natural gas. As previously stated, the cumulative production to date plus currently booked 2P reserves and the current best estimate of ECR represents less than 13 per cent of the TPIIP, therefore higher recovery factors could lead to higher production rates. The key determining factor in what the ultimate recovery and associated peak production rate will be is expected to be the price of natural gas in the long-term. It is within this context that ARC's long-term development plan for the assets has been developed and is being refined.

ARC's long-term development plan focuses on the highest rate of return projects across our asset portfolio. We are also focused on maintaining a high level of capital discipline as has been exhibited since our inception. In the prevailing environment of low natural gas prices, near-term development of dry gas projects is not a priority. ARC is fortunate to be in properties such as Dawson where we are centered on the "sweet spot" of a dry gas resource and returns remain competitive, even at a Cdn$3 field gas price. However, further near-term investment in new dry gas developments will likely be deferred in favour of liquids-rich opportunities that offer higher rates of return.

ARC's successful 2011 drilling programs at Tower and Attachie proved up discoveries of liquids-rich gas with the liquids content ranging from 30 to 200 bbls of liquids per mmcf of raw gas. ARC will continue to exploit these reservoirs and expand our understanding of long-term potential as evidenced by the planned seven well program at Tower in our 2012 budget. These new high liquids yield projects are very compelling; however, a better understanding of long-term production performance of both the natural gas and liquids components of these properties is required before full scale development can occur.

Early stage drilling in high quality reservoirs at Attachie, Sunrise, Parkland, Tower and Dawson are indicating significant future resource opportunities in excess of our 2P reserves and, we believe, in excess of the current estimate of ECR. While providing significant future growth opportunities for ARC, an asset of this nature also poses unique challenges to our organization. The most important strategic question we are addressing is how to extract the greatest value for our shareholders while managing the technical, market and execution risks inherent in a world class asset of this nature. Key considerations with respect to the future risk managed value creation from the assets are both the pace of development and how we fund the very significant capital required to fully develop the resource. Equally important is understanding the implications of developing significant new natural gas production in what appears to be a well-supplied North American market. These issues are well understood by ARC's management team and our long-term strategic development plan continues to evolve with the size and scope of our opportunities and developments in the market.

Based upon the forgoing analysis and ARC's expertise in the Montney formation in NE B.C., it is expected that significant additional reserves will be developed in the future with continued drilling success on currently undeveloped Montney acreage together with further development, completion refinements and improved economic conditions. Historic drilling success and recoveries on the more fully developed Montney acreage, abundant well log and production test data, and the application of increased drilling densities support ARC's belief that significant additional resources will be recovered. Continuous development through multi-year exploration and development programs and significant levels of future capital expenditures are required in order for additional resources to be recovered in the future. The principal risks that would inhibit the recovery of additional reserves relate to the potential for variations in the quality of the Montney formation where minimal well data currently exists, access to the capital which would be required to develop the resources, low gas prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the required services at the appropriate cost, and the effectiveness of fraccing technology and applications. The contingencies that prevent the ECR from being classified as reserves are due to the early evaluation stage of these potential development opportunities. Additional drilling, completion, and test results are required before these contingent resources are converted to reserves and a larger component of DPIIP is converted to ECR.

ANTE CREEK MONTNEY RESOURCES AND RESERVES

In addition to the NE B.C. Montney, ARC also has a significant land position in the Montney oil and liquids-rich gas resource play at Ante Creek in northwestern Alberta. Over the past 11 years ARC has strategically amassed land holdings of over 260 net sections of land at Ante Creek. 2P reserves at Ante Creek of 47.2 mmboe are comprised of 43 per cent liquids and account for eight per cent of ARC's total 2P reserves. This property will provide material production growth in 2012 and will also be a key property for future development. The Ante Creek property was not included in the Independent Resources Evaluation and therefore has no independent assessment of ECR, DPIIP or TPIIP. During the course of 2012, ARC will be working with GLJ to conduct a similar analysis at Ante Creek as the one which was conducted in the NE B.C. Montney. It is our expectation that similar to the NE B.C. Montney, significant unbooked resource potential will be identified at Ante Creek.

2011 OPERATIONAL AND PROPERTY REVIEW

ARC had another year of exceptional drilling results in 2011. Since year-end 2008, ARC's 2P reserves have almost doubled to 572 mmboe, while our F&D costs and associated recycle ratios have been among the best in the industry. The NE B.C. Montney region has been the primary driver of this strong performance with reserves increasing by approximately 300 per cent since year-end 2008 and production increasing from 45 mmcf per day to 235 mmcf per day of natural gas and 1,800 bbls per day of liquids at present.

During 2011 ARC spent $726 million to execute its capital program. ARC's 2011 capital spending included $92 million on facilities and an investment of $75 million in undeveloped land. ARC drilled 164 gross (154 net) wells on operated lands with a 100 per cent success rate. A significant portion of ARC's 2011 capital program was focused on resource play development with $240 million (33 per cent of the 2011 capital spending) being allocated to the Montney region in NE B.C. and Ante Creek in Alberta.

ARC's 2011 capital development program yielded 2P reserve additions of 132 mmboe, representing a 433 per cent replacement of 2011 production through internal development. ARC divested of certain non-core properties in 2011 with attributed 2P reserves of 14.6 mmboe, net of acquisitions. ARC's total reserve additions were 117 mmboe after the net divestment of properties, representing a total 2011 production replacement of 385 per cent. This is the fourth year in a row that ARC has been able to replace greater than 200 per cent of production from internal development activities.

The following discussion includes well flow-test results which are not necessarily indicative of long-term performance or of ultimate recovery from the subject wells.

Dawson
In 2011, ARC drilled 12 wells in the Dawson field and increased production to 165 mmcf per day with the commissioning of the second 60 mmcf per day Gas Plant. The 2P reserves increased 15 per cent from 882 Bcf to 1,012 Bcf.

As a result of well productivity in Dawson continuing to exceed expectations, ARC has a sufficient inventory of wells waiting to be brought on-stream to maintain current production of 165 mmcf per day throughout 2012. ARC plans to drill one well at Dawson in 2012 to retain lands which would otherwise expire.

Parkland
At Parkland, the Upper Montney section is approximately 100 meters thick with significant portions having greater than six per cent porosity. ARC drilled 10 wells at Parkland in 2011. ARC believes that existing horizontal wells are not draining the complete thickness of the Montney, and therefore requires a second horizontal well, beneath the existing ones to effectively drain the entire section. During 2011, ARC drilled its first well into the lower portion of the upper Montney beneath an existing well bore and realized a one month initial production rate ("IP") of 4.7 mmcf per day which is similar to the upper well. No communication between the two wells has been seen to date. Should this continue to be the case, the future drilling inventory at Parkland will expand considerably.

The year-end 2011 2P reserves increased 28 per cent to 49.7 mmboe from 38.8 mmboe at year-end 2010 after the production of 3 mmboe in 2011.

Tower
ARC's 48 net sections of contiguous land north and west of the Parkland field is referred to as Tower. When ARC acquired this land in 2010, it was considered to be a potential very tight oil play which was unproven at the time of the acquisition. Since that time, ARC has realized a significant liquids-rich hydrocarbon opportunity. ARC drilled three horizontal wells in the Tower field in 2011 applying newly developed multi-stage fracture stimulation techniques. The 13-8-82-17 well was flowing at 610 boe per day (340 bbls per day of 45º API oil, condensate and natural gas liquids and 1.7 mmcf per day of gas) at the end of a 23 day production test. The 5-14-81-17 well was flowing at 405 boe per day (240 bbls of 47º API condensate and natural gas liquids and 1.0 mmcf per day of gas) at the end of an 11 day production test. The A4-8-81-16 well, was flowing 445 boe per day, (230 bbls per day of 49º API condensate and natural gas liquids and 1.3 mmcf per day of gas) at the end of a 12 day production test. The A4-8 well was put on production in late October 2011 with an initial 30 day average production rate of 258 barrels per day of oil and 1.1 mmcf per day of liquids-rich gas. The test and production volumes only refer to the free liquids produced. In addition to the free liquids, the gas stream is liquids-rich with 30 bbls per mmcf of gas; this will be recovered upon processing the gas.

GLJ has assigned 4.5 mmboe of 2P reserves (1.4 mmbbls liquids and 19 Bcf of natural gas) at Tower for year-end 2011. The Tower prospect is a liquids-rich gas reservoir. GLJ recognizes an oil reservoir in one gross (0.5 net) section of the pool with 2P reserves of 115 mbbls of oil and 549 mbbls of oil in ECR on the one oil section.

ARC's seven well 2012 capital program will include gathering additional fluid samples on new wells and completing recombined pressure-volume-temperature ("PVT") studies to better understand the fluids in place at Tower.

Septimus
During 2011, ARC completed and tested a previously drilled horizontal well at Septimus. The A13-11-81-20W6 well, tested at a stabilized rate of 11.5 mmcf per day of gas and expected 24 barrels per mmcf of liquids, at 1,200 psia at the end of a 3.5 day production test. ARC acquired three additional sections of land in 2011, increasing its land base to 22 net sections.

Attachie
ARC holds a prospective land base of 115 net sections of liquids-rich Montney acreage at Attachie. During 2011, ARC drilled and tested three horizontal Montney wells spread across the large land base. The first horizontal well, 4-20-84-24, on the west side of the land base, was completed in the second quarter of 2011 and achieved a stabilized test production rate of 10.7 mmcf per day of gas and 350 barrels per day of free liquids at a pressure of 1,300 psia over a 4.2 day test period. This is a promising indicator of the potential of Attachie for commercial development. ARC will continue to collaborate with third parties regarding options for commercial development and infrastructure requirements for this new play.

Sunrise/Sunset
ARC's strategy for 2011 was to test new completion techniques on three Montney zones, the Upper Montney 'A' and 'B' and the Lower Montney 'E', to establish important production type curves for development of the Sunrise property. The Montney 'A' well tested at 11.2 mmcf per day at 2,074 psia over a 2.1 day test period. This well` has been on production since September 2011 and is currently producing 5.6 mmcf per day with significant back-pressure being held on the well at 1,885 psia. The Montney 'B' well tested at 12 mmcf per day at 2,234 psia over a 2.4 day test period is currently producing 5.5 mmcf per day against 1,450 psia of back pressure. The Montney 'E' well tested at 6.7 mmcf per day at 754 psia over a 2.5 day test period and is currently producing 3 mmcf per day against 360 psia of back pressure. Production of 15 mmcf per day from the three operated wells was brought on-stream through a third party facility late in the third quarter of 2011.

The very positive production results from all three zones have allowed GLJ to significantly increase 2P reserves from 235 Bcf at year-end 2010 to 483 Bcf at year-end 2011. The Montney zone in Sunrise is approximately 320 meters thick, translating into a huge potential resource.

Ante Creek
The Ante Creek property in Northern Alberta is a Montney oil play in which ARC has a land position of 260 net sections. ARC's Ante Creek production averaged 7,400 boe per day in 2011 (49 per cent crude oil and natural gas liquids, 51 per cent natural gas), a level which is currently facility constrained. ARC plans to double drilling to 40 horizontal wells and complete a new 30 mmcf per day processing facility to alleviate processing constraints during 2011. ARC drilled 20 horizontal wells in 2011 in anticipation of the new facility being on-stream at the end of the first quarter 2012.

ARC added 4.7 mmboe of reserves at Ante Creek in 2011, to bring total reserves to 47.2 mmboe. ARC believes that the Ante Creek property will provide significant near-term growth opportunities with continued drilling and expansion of facilities.

Pembina
ARC continues to have positive results with the horizontal drilling program in the Pembina area. In 2011, ARC drilled 37 horizontal wells in the Cardium formation and added 3.2 mmboe of 2P reserves through this development activity. Production increased to 10,450 boe per day of primarily light oil in 2011, an increase of 14 per cent from 2010. This is the first significant increase in production as a result of development drilling activity since ARC began operations in the Pembina area in 1996.

2011 INDEPENDENT RESERVES EVALUATION

GLJ conducted an independent reserves evaluation effective December 31, 2011 and prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and NI 51-101. The reserve evaluation was based on GLJ forecast pricing and foreign exchange rates at January 1, 2012 as outlined in Table 4 below.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument ("NI") 51-101. This news release contains several cautionary statements that are specifically required by NI 51-101 under the heading "Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information". In addition to the detailed information disclosed in this news release more detailed information will be included in ARC's Annual Information Form ("AIF").

Table 4
GLJ January 1, 2012 Price Forecast	West Texas Intermediate Crude Oil ($US/bbl)	Edmonton Light Crude Oil ($Cdn/bbl)	Natural Gas at AECO ($Cdn/mmbtu)	Foreign Exchange ($US/$Cdn)
2012	97.00	97.96	3.49	0.98
2013	100.00	101.02	4.13	0.98
2014	100.00	101.02	4.59	0.98
2015	100.00	101.02	5.05	0.98
2016	100.00	101.02	5.51	0.98
2017	100.00	101.02	5.97	0.98
2018	101.35	102.40	6.21	0.98
2019	103.38	104.47	6.33	0.98
2020	105.45	106.58	6.46	0.98
2021	107.56	108.73	6.58	0.98
Escalate thereafter at	+2.0%/yr	+2.0%/yr	+2.0%/yr	0.98

Table 5
RESERVES SUMMARY	Light and Medium Crude Oil (mbbl)	Heavy Crude Oil (mbbl)	Total Crude Oil (mbbl)	NGLs (mbbl)	Natural Gas (Bcf)	Oil Equivalent 2011 (mboe)	Oil Equivalent 2010 (mboe)
Company Gross
Proved Producing	87,626	1,874	89,500	10,210	655	208,920	210,860
Proved Developed Non-producing	1,794	0	1,794	756	44	9,952	15,678
Proved Undeveloped	12,768	0	12,768	8,122	719	140,769	107,894
Total Proved	102,188	1,874	104,062	19,088	1,419	359,641	334,432
Proved plus Probable	135,071	2,308	137,379	32,774	2,413	572,374	485,121
Net Interest
Proved Producing	75,293	1,801	77,094	7,640	556	177,318	179,481
Proved Developed Non-producing	1,587	0	1,587	626	38	8,485	13,097
Proved Undeveloped	11,025	0	11,025	6,736	604	118,362	91,114
Total Proved	87,905	1,801	89,706	15,002	1,197	304,165	283,692
Proved plus Probable	115,416	2,220	117,636	25,955	2,001	477,028	406,543
Company Interest ⁽¹⁾
Proved Producing	87,755	2,040	89,795	10,319	662	210,425	212,733
Proved Developed Non-producing	1,796	0	1,796	756	44	9,959	15,685
Proved Undeveloped	12,778	0	12,778	8,123	720	140,840	107,921
Total Proved	102,329	2,040	104,369	19,198	1,426	361,224	336,339
Proved plus Probable	135,253	2,526	137,779	32,903	2,423	574,435	487,418

(1)

Company Interest reserves represent gross reserves plus royalty interest reserves.

Table 6
RESERVES RECONCILIATION COMPANY GROSS


	Light and Medium Crude Oil (mbbl)	Heavy Crude Oil (mbbl)	Total Crude Oil (mbbl)	NGLs (mbbl)	Natural Gas (mmcf)	Oil Equivalent (mboe)
PROVED PRODUCING
Opening Balance	90,258	2,071	92,329	11,302	643,377	210,861
Exploration Discoveries	0	0	0	0	0	0
Drilling Extensions	1,856	0	1,856	972	64,960	13,655
Improved Recovery	880	0	880	28	300	958
Infill Drilling	3,745	60	3,805	382	40,370	10,915
Technical Revisions	1,886	6	1,892	636	51,995	11,193
Acquisitions	21	6	27	3	307	81
Dispositions	-1,362	0	-1,362	-1,427	-28,084	-7,470
Economic Factors	-123	-1	-124	-66	-5,682	-1,137
Production	-9,535	-268	-9,803	-1,620	-112,284	-30,137
Closing Balance	87,626	1,874	89,500	10,210	655,259	208,919
TOTAL PROVED
Opening Balance	103,104	2,105	105,209	18,329	1,265,363	334,432
Exploration Discoveries	61	0	61	465	6,702	1,643
Drilling Extensions	4,015	0	4,015	2,822	218,146	43,195
Improved Recovery	451	0	451	26	284	524
Infill drilling	5,157	30	5,187	380	41,558	12,493
Technical Revisions	529	1	530	1,544	131,257	23,949
Acquisitions	21	6	27	47	8,857	1,550
Dispositions	-1,465	0	-1465	-2,447	-55,516	-13,165
Economic Factors	-150	0	-150	-458	-85,421	-14,845
Production	-9,535	-268	-9,803	-1,620	-112,284	-30,137
Closing Balance	102,188	1,874	104,062	19,088	1,418,946	359,641
PROBABLE
Opening Balance	33,750	672	34,422	8,003	649,578	150,689
Exploration Discoveries	131	0	131	204	2,981	832
Drilling Extensions	2,733	0	2,733	5,996	319,364	61,956
Improved Recovery	-152	0	-152	0	-48	-160
Infill Drilling	714	-30	684	80	14,359	3,157
Technical Revisions	-3,408	-208	-3,616	-101	-18,079	-6,727
Acquisitions	11	0	11	87	16,598	2,864
Dispositions	-899	0	-899	-741	-25,506	-5,891
Economic Factors	3	0	3	158	35,134	6,017
Production	0	0	0	0	0	0
Closing Balance	32,883	434	33,317	13,686	994,381	212,734
PROVED PLUS PROBABLE
Opening Balance	136,854	2,777	139,631	26,332	1,914,941	485,121
Exploration Discoveries	192	0	192	669	9,683	2,475
Drilling Extensions	6,748	0	6,748	8,818	537,510	105,151
Improved Recovery	299	0	299	26	236	364
Infill Drilling	5,871	0	5,871	460	55,917	15,651
Technical Revisions	-2,879	-207	-3,086	1,443	113,178	17,222
Acquisitions	32	6	38	134	25,455	4,415
Dispositions	-2,364	0	-2364	-3,188	-81,022	-19,056
Economic Factors	-147	0	-147	-300	-50,287	-8,828
Production	-9,535	-268	-9,803	-1,620	-112,284	-30,137
Closing Balance	135,071	2,308	137,379	32,774	2,413,327	572,375

RESERVE LIFE INDEX ("RLI")

ARC's 2P RLI increased to 17 years at year-end 2011 while the proved RLI was 10.7 years based upon the GLJ reserves and ARC's 2012 production guidance mid-point of 92,500 boe per day. The increase in the 2P RLI from 2008 through 2011 is attributed to the successful development of the Montney region and the resultant growth in 2P reserves. The following table summarizes ARC's historical RLI.

Table 7
Reserve Life Index	2011⁽¹⁾	2010⁽²⁾	2009	2008	2007
Total Proved	10.7	10.4	10.3	10.3	9.7
Proved Plus Probable	17.0	15.1	14.4	13.6	12.3

(1)			Based on 2012 production guidance midpoint of 92,500 boe per day.
(2)			2010 reserves excludes 10.6 mmboe proved and 14.1 mmboe 2P gross reserves relating to assets divested in January 2011 and included in the year-end 2010 reserves evaluation. The 2011 production guidance excluded production from the divested assets of approximately 3,400 boe per day.

NET PRESENT VALUE ("NPV") SUMMARY

ARC's crude oil, natural gas and natural gas liquids reserves were evaluated using GLJ's product price forecasts effective January 1, 2012 prior to provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the NPV of Cash Flow estimated by GLJ represents the fair market value of the reserves. NPVs on both a before and after tax basis are presented below.

Table 8
NPV of Cash Flow ⁽¹⁾	Undiscounted $MM	Discounted at 5% $MM	Discounted at 10% $MM	Discounted at 15% $MM	Discounted at 20% $MM
Before Tax
Proved Producing	6,954	4,750	3,662	3,014	2,583
Proved Developed Non-Producing	301	214	168	140	121
Proved Undeveloped	2,678	1,572	975	620	393
Total Proved	9,933	6,536	4,805	3,774	3,097
Probable	6,365	3,021	1,715	1,084	735
Proved plus Probable	16,298	9,557	6,520	4,858	3,832
After Tax ⁽²⁾
Proved Producing	5,888	4,117	3,229	2,693	2,332
Proved Developed Non-Producing	224	160	125	104	90
Proved Undeveloped	1,999	1,131	662	384	208
Total Proved	8,112	5,407	4,016	3,181	2,630
Probable	4,752	2,227	1,239	764	502
Proved plus Probable	12,863	7,635	5,255	3,945	3,132

(1)			Based on NI-51-101 Net Interest reserves and GLJ January 1, 2012 Forecast Prices and Costs.
(2)			Based on ARC's estimated tax pools at year-end 2011.
(3)			The after-tax net present value of ARC's oil and gas properties here reflects the tax burden on the properties on a stand-alone basis. It does not consider the business-entity-level tax situation, or tax planning. It does not provide an estimate of the value at the level of the business entity, which may be significantly different. ARC's Consolidated Financial Statements and Management's Discussion & Analysis should be consulted for information at the business entity level.

At a 10 per cent discount factor, the proved producing reserves constitute 56 per cent of the before tax 2P estimated value while total proved reserves account for 74 per cent of the before tax 2P estimated value.

FUTURE DEVELOPMENT CAPITAL ("FDC")

NI 51-101 requires that F&D costs be calculated including changes in FDC. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the independent evaluator's best estimate of what it will cost to bring the proved undeveloped and probable reserves on production. The increase in reserves and in particular the level of undeveloped reserves now booked on the Montney acreage has yielded an increased capital cost expectation in the 2011 evaluation.

Following is a summary of GLJ estimated FDC required to bring total proved and probable reserves on production.

Table 9
Future Development Capital ⁽¹⁾ $ Millions	Total Proved	Total Proved + Probable
2012	301	448
2013	521	650
2014	326	496
2015	328	544
2016	206	287
Remainder	165	687
Total FDC undiscounted	1,847	3,112
Total FDC discounted at 10%	1,444	2,299

(1)

FDC as per GLJ independent reserve evaluation as of December 31, 2011 and based on GLJ forecast pricing as
at January 1, 2012.

FINDING DEVELOPMENT AND ACQUISITION COSTS ("FD&A")

ARC's F&D costs were $5.50 per boe and $10.84 per boe for 2P and proved reserves, respectively in 2011, excluding FDC ($11.96 per boe and $16.23 per boe, respectively, for 2P and proved reserves including FDC). The low F&D costs are attributed to the high quality of ARC's property portfolio, excellent results from ARC's development program and strong reserve growth particularly at Sunrise, Dawson, Parkland, Tower, Ante Creek and Attachie.

Including net dispositions, ARC's 2011 FD&A costs were $5.24 per boe of 2P and $11.11 per boe of proved reserves before FDC ($12.23 per boe and $17.13 per boe, respectively, for 2P and proved reserves including FDC). The three year average FD&A costs were $7.15 per boe for 2P reserves and $12.02 per boe for total proved reserves, excluding FDC.

ARC's three year 2P F&D and FD&A costs excluding FDC of $5.80 per boe and $7.15 per boe, respectively, are at the lowest levels since 1999 and 2001, respectively. ARC's low FD&A costs are a reflection of ARC's focus on high quality assets, cost management and allocation of resources and capital to the highest rate of return projects.

The following table illustrates FD&A costs excluding and including FDC.

Table 10
		Excluding FDC		Including FDC
FD&A costs - Company Gross ⁽¹⁾⁽²⁾ $ Thousands		Proved	Proved + Probable	Proved	Proved + Probable
E&D capital expenditures		726,011	726,011	726,011	726,011
E&D capital expenditures - change in FDC		-	-	360,466	852,821
	Total E&D capital expenditures	726,011	726,011	1,086,477	1,578,832
Net dispositions		(111,285)	(111,285)	(111,285)	(111,285)
Net dispositions - change in FDC		-	-	(27,111)	(32,389)
Total net dispositions		(111,285)	(111,285)	(138,395)	(143,674)
	Total capital including net dispositions	614,726	614,726	948,082	1,435,158
E&D reserve additions		66,961	132,032	66,961	132,032
Net disposition reserves		(11,615)	(14,641)	(11,615)	(14,641)
	Reserve additions including net dispositions	55,346	117,391	55,346	117,391
FD&A costs - $ per boe:
F&D Costs - Current Year		10.84	5.50	16.23	11.96
F&D Costs - Three Year Average		9.86	5.80	14.51	11.54
Net Disposition Cost - Current Year		9.58	7.60	11.92	9.81
Net Disposition Cost - Three Year Average		25.19	16.03	31.78	21.83
FD&A Costs - Current Year		11.11	5.24	17.13	12.23
FD&A Costs - Three Year Average		12.02	7.15	16.95	12.90

(1)			The aggregate of Exploration and Development ("E&D") costs incurred in the most recent financial year and the change in estimated future development costs ("FDC") generally will not reflect total finding and development costs related to reserves additions for that year.
(2)			Under NI 51-101, the calculation of F&D costs must incorporate the change in future development capital required to bring the proved undeveloped and probable reserves to production. In all cases, the F&D, or FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions both before and after FDC costs.

Table 11
Company Gross Historic FD&A Costs ($ per boe)	2011	2010	2009	2008	2007
Proved Reserves:
Annual FD&A excluding FDC	11.11	13.35	10.53	14.31	20.71
Three year average FD&A excluding FDC	12.02	12.82	13.86	18.50	18.75
Annual FD&A including FDC	17.13	18.21	14.36	22.01	20.71
Three year average FD&A including FDC	16.95	18.04	18.41	23.12	20.57
Proved plus Probable Reserves:
Annual FD&A excluding FDC	5.24	9.23	6.46	10.18	19.24
Three Year Average FD&A excluding FDC	7.15	8.62	9.61	14.85	16.77
Annual FD&A including FDC	12.23	14.26	11.59	17.08	20.29
Three Year Average FD&A including FDC	12.90	14.08	14.81	20.04	19.43

DEFINITIONS OF OIL AND GAS RESOURCES AND RESERVES

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:

	Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

	Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

	Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total resources" is equivalent to "Total Petroleum Initially-In-Place". Resources are classified in the following categories:

	Total Petroleum Initially-In-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.

	Discovered Petroleum Initially-In-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable.

	Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.

	Economic Contingent Resources are those contingent resources which are currently economically recoverable.

	Undiscovered Petroleum Initially-In-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as "prospective resources" and the remainder as "unrecoverable."

	Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.

	Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and resources as follows:

	Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

	Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

	High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES, RESOURCES AND OPERATIONAL INFORMATION

All amounts in this news release are stated in Canadian dollars unless otherwise specified. Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip, and given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. 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. In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom) are based on "company gross reserves" using forecast prices and costs. Our oil and gas reserves statement for the year-ended December 31, 2011, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedar.com. In relation to the disclosure of estimates in the Highlights, Resources and Reserves Discussion and Analysis, and 2011 Operational and Property Review, such estimates for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

This news release contains references to estimates of oil and gas classified as TPIIP and DPIIP in the Montney region in northeastern British Columbia which are not, and should not be confused with, oil and gas reserves. See "Definitions of Oil and Gas Resources and Reserves".

Projects have not been defined to develop the resources in the Evaluated Areas as at the evaluation date. Such projects, in the case of the Montney resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints, ARC's policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of ARC on gas prices, the results of exploration and development activities of ARC and others in the area and possible infrastructure capacity constraints.

ARC's belief that it will establish significant additional reserves over time with conversion of DPIIP into ECR, ECR into 2P reserves and probable reserves into proved reserves is a forward looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading "Forward Looking Statements".

NOTICE TO U.S. READERS
The oil and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects of United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the "SEC") generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves (as defined in SEC rules). Canadian securities laws require oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only proved reserves (which are defined differently from the SEC rules) but also probable reserves, each as defined in NI 51-101. Accordingly, proved reserves disclosed in this news release may not be comparable to U.S. standards, and in this news release, ARC has disclosed reserves designated as "probable reserves" and "proved plus probable reserves" and "proved plus probable plus possible reserves". Probable reserves and possible reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves. The SEC's guidelines strictly prohibit reserves in these categories from being included in filings with the SEC that are required to be prepared in accordance with U.S. disclosure requirements. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments. Moreover, ARC has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. As a consequence of the foregoing, ARC's reserve estimates and production volumes in this news release may not be comparable to those made by companies utilizing United States reporting and disclosure standards. Additionally, the SEC prohibits disclosure of oil and gas resources, whereas Canadian issuers may disclose resource volumes. Resources are different than, and should not be construed as, reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, resources, see above.

FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release 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 news release contains forward-looking information and statements pertaining to the following: the recognition of significant additional reserves under the heading "2011 Independent Reserve Evaluation" and the recognition of significant resources under the heading "Resources and Reserves Discussion and Analysis", the volumes and estimated value of ARC's oil and gas reserves; the life of ARC's reserves; the volume and product mix of ARC's oil and gas production; future oil and natural gas prices and ARC's commodity risk management programs; future results from operations and operating metrics; and future development, exploration, acquisition and development activities (including drilling plans) and related production expectations.

The forward-looking information and statements contained in this news release 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; results from drilling and development activities consistent with past results; the continued and timely development of infrastructure in areas of new production; 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 reserve 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 plans expenditures. There are a number of assumptions associated with the development of the Evaluated Areas, including the quality of the Montney reservoir, continued performance from existing wells, future drilling programs and performance from new wells, the growth of infrastructure, well density per section, recovery factors and development necessarily involves known and unknown risks and uncertainties, including those risks identified in this press release. 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.

The forward-looking information and statements included in this news release 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; the early stage of development of some areas in the Evaluated Areas; the potential for variation in the quality of the Montney formation, changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; unanticipated results from ARC's exploration and development activities; 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 news release and in ARC's Annual Information Form).

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Confirms February 15, 2012 Dividend Amount

Mon, 16 Jan 2012 12:52:00 -0500

Jan 16, 2012

CALGARY, Jan. 16, 2012 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on February 15, 2012 to shareholders of record on January 31, 2012. The ex-dividend date is January 27, 2012.

As at January 16, 2012 the trailing twelve-month payments to investors, including the January 16, 2012 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $7.7 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Confirms January 16, 2012 Dividend Amount

Fri, 16 Dec 2011 12:54:00 -0500

Dec 16, 2011

CALGARY, Dec. 16, 2011 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on January 16, 2012 to shareholders of record on December 30, 2011. The ex-dividend date is December 28, 2011.

As at December 16, 2011 the trailing twelve-month payments to investors, including the December 15, 2011 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. to Present at the FirstEnergy/Société Générale Montreal Energy Conference

Mon, 05 Dec 2011 10:00:00 -0500

Dec 5, 2011

CALGARY, Dec. 5, 2011 /CNW/ - Notification of live webcast event:

ARC RESOURCES LTD. (TSX: ARX)
Live webcast presentation
Wednesday, December 7, 2011, 3:05 PM ET

To listen and view this online event, please visit:

http://jetslides.tv/lobby/593

The presentation will be available in an archived version at this link for 30 days following the live presentation.

For further information:

For more information on the webcast please visit www.firstenergy.com or contact:

ARC RESOURCES LTD.

Niki Anderson
Senior Advisor, Investor Relations
Email: nanderson@arcresources.com
Telephone: 403-503-8600

www.arcresources.com

ARC Resources Ltd. Confirms December 15, 2011 Dividend Amount

Wed, 16 Nov 2011 12:25:00 -0500

Nov 16, 2011

CALGARY, Nov. 16, 2011 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on December 15, 2011 to shareholders of record on November 30, 2011. The ex-dividend date is November 28, 2011.

As at November 16, 2011 the trailing twelve-month payments to investors, including the November 15, 2011 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.
John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Announces a $760 million Capital Budget for 2012, which includes a 12 per cent production growth target

Wed, 02 Nov 2011 18:03:00 -0400

Nov 2, 2011

CALGARY, Nov. 2, 2011 /CNW/ - (TSX: ARX) ARC Resources Ltd. ("ARC") announced today that its Board of Directors has approved a budget for 2012 that includes a $760 million capital expenditure program and plans for substantial growth in production.

John Dielwart, ARC's Chief Executive Officer, said, "With a clear focus on value creation, we will continue to invest the majority of our capital expenditures in our oil and liquids-rich natural gas opportunities. With outstanding opportunities in our portfolio and a $760 million capital budget in 2012, we expect to achieve approximately a 12 per cent year-over-year increase in our total production volumes to 92,500 boe per day, highlighted by an estimated 15 per cent increase in our liquids production."

2012 Capital Budget Strategic Objectives

The strategic objectives of ARC's 2012 capital budget, which are aligned with ARC's long-term objective of risk-managed value creation are:

Maximize value by focusing on oil and liquids opportunities to capitalize on the strength of crude oil prices
Grow production in 2012 through exploitation of existing resource plays and continue to develop ARC's significant Montney land base
Expand knowledge and technical expertise in early stage developments and identify infrastructure needs to set the stage for long-term development and growth in key areas including a planned Sunrise gas plant in 2013
Execute a disciplined exploration program to identify future development and growth opportunities
Preserve ARC's strong balance sheet to maintain financial flexibility to fund capital programs

2012 Capital Budget Highlights

The capital budget has been set at $760 million with a focus on oil and liquids-rich gas opportunities at Ante Creek and Pembina in Alberta, Parkland in British Columbia, Goodlands in Manitoba and various properties in southeast Saskatchewan:
- Drilling of 195 gross (182 net) operated wells and 44 gross (six net) non-operated wells to be drilled by partners; horizontal drilling will account for 94 per cent of the operated wells to be drilled in 2012
- Total oil and liquids spending of $660 million, representing 87 per cent of the capital budget
- Limited natural gas drilling budget of $15 million to drill three gross operated (three net) dry gas wells in 2012, two of the gas wells to be drilled are to retain lands
- Natural gas infrastructure spending of $48 million for construction of Ante Creek and Sunrise gas plants to alleviate capacity constraints and set the stage for long-term growth
Production target for 2012 of 90,000 to 95,000 boe per day comprising approximately 40 per cent crude oil and liquids and 60 per cent natural gas
Despite limited natural gas drilling in 2012, including only one well planned at Dawson in 2012, ARC expects year-over-year natural gas production to increase 10 per cent in 2012
Emphasis on oil opportunities is expected to generate a 15 per cent increase in 2012 average oil and liquids production relative to 2011 levels
Exploration expenditures account for seven per cent of the budget and will be directed towards identification of future growth areas targeting large resource opportunities
Operating costs in 2012 are expected to be $9.55 to $9.95 per boe, effectively flat relative to 2011 estimated costs
Given the current outlook for crude oil and natural gas prices and current hedge position, ARC expects to maintain its monthly dividend payment at $0.10 per share
ARC expects to finance the majority of the 2012 capital budget with funds from operations and proceeds from the Dividend Reinvestment Program ("DRIP"), the remainder will be financed with a modest amount of debt and proceeds from potential minor property divestments.

2012 Capital Program

ARC's 2012 capital program has been set at $760 million, the highest in ARC's history, up four per cent from the $730 million capital program in 2011. The primary focus of the 2012 budget is to maximize value by directing more capital to oil and liquids-rich gas projects to capitalize on the strength of crude oil prices. Approximately $400 million will be spent in 2012 to maintain current production levels while the remainder will be directed towards growth projects. ARC's strong hedge position and available credit capacity will provide ARC with the ability to internally finance the growth component of this budget.

Based on 2012 budget projections, ARC will drill approximately 195 gross wells (182 net) on its operated properties, with 179 wells targeting oil, 13 wells targeting liquids-rich natural gas and three wells targeting dry natural gas. On ARC's non-operated properties we anticipate our partners will drill 44 gross wells (6 net) with ARC's share of expenditures to be approximately $51 million.


2012 Capital Budget by Core Area ($ millions except wells drilled)	2012 Capital ($ millions)⁽¹⁾	Operated wells drilled (gross)	Gas/Oil wells drilled	Comment
Northeast BC/Northwest Alberta	186	13	Liquids/Gas	Sunrise, Parkland
Northern Alberta	265	55	Oil/Liquids/Gas	Ante Creek
Pembina	100	43	Oil
Southern Alberta/Southwest Saskatchewan	18	7	Oil	Smiley, Gull Lake
Southeast Saskatchewan/Manitoba	143	67	Oil	Goodlands
Redwater	25	10	Oil
Corporate	23	-	-
Total Capital Budget	$760	195

(1) Includes Operated and Non-operated.

Ante Creek

Ante Creek is a significant growth area with 259 gross sections of land (257 net sections). ARC has allocated $156 million to drill 40 gross operated horizontal oil wells at Ante Creek in 2012. A portion of 2012 capital will be allocated to complete construction of the 30 mmcf per day gas plant, expected to be on-stream early in 2012, which will contribute to increased oil and liquids production. Drilling will continue through 2012 to fill the new Ante Creek gas plant.

Parkland/Tower

At Tower, ARC has budgeted $43 million for the drilling of seven horizontal wells in the liquids-rich region located northwest of the main Parkland pool. ARC will drill and complete three wells in the Tower region in 2011. Test results from the first two wells were encouraging, and work is being done to tie-in the wells to determine the productive potential of this area. In 2012, ARC will focus on further testing of the productive capacity in the liquids-rich Tower area. ARC is currently working towards bringing the three wells on production by year-end 2011.

Southeast Saskatchewan and Manitoba

ARC plans to spend $95 million to drill 67 gross operated oil wells (66 will be horizontals) in southeast Saskatchewan and Manitoba including Goodlands, Lougheed, Skinner Lake, Oungre, Weir Hill, Parkman and Elmore. The 2012 program represents a 46 per cent increase from the 46 well gross operated drilling program in 2011. Full year average oil production is expected to grow by approximately 19 per cent to 12,300 boe per day in 2012.

A considerable level of the activity in this area will occur at Goodlands where ARC will drill 25 horizontal oil wells. Oil production at Goodlands is expected to average 2,700 boe per day in 2012, an increase of 93 per cent relative to 2011 levels. The high quality light oil production at Goodlands currently yields the highest netbacks in ARC's portfolio.

Pembina

ARC plans to spend approximately $100 million to drill 41 horizontal and two vertical oil wells at Pembina in 2012 with 40 of the wells targeting Cardium oil. ARC expects to maintain production at current levels of approximately 10,000 boe per day through 2012. Also during 2012, extensive work is planned on waterflood management in order to optimize reservoir recoveries at Pembina.

ARC is pleased with results to date, with third month production averaging 180 boe per day for our recent wells. Due to the areal extent of the field and the geologic complexity of the reservoir, each location needs to be evaluated individually. ARC will continue to evaluate this field in order to gain a better understanding of where the horizontal completion technology can be most effectively applied.

Attachie

At Attachie in northeast British Columbia, ARC plans to drill two horizontal gas wells in 2012. ARC's goal is to establish and tie-in pilot production in this area to assess the long-term deliverability. ARC's first well tested 10 mmcf per day with 30 barrels of liquids per mmcf over five days. Two more horizontal wells have been drilled in 2011 and will be completed by year-end.

Sunrise/Groundbirch (Montney West)

ARC has drilled and tested gas in three different layers within the Montney formation at the Sunrise property, located directly west of Dawson. Sunrise currently produces 22 mmcf per day of natural gas consisting of 15 mmcf per day of operated production flowing through a third party processing facility and seven mmcf per day of non-operated production. During 2011, horizontal wells into all three of the zones were drilled, completed and brought on production. The opportunity to flow gas from all three zones through a third party facility has enabled ARC to experiment and optimize its well fracturing design before implementing a full scale development drilling program in anticipation of filling the planned 60 mmcf per day Sunrise gas plant.

ARC will drill one horizontal gas well at Sunrise in 2012 into the Upper Montney. ARC expects to maintain current production levels at approximately 22 mmcf per day in 2012. The 2012 budget also includes funding for the start of construction on the 60 mmcf per day Sunrise gas plant, currently slated to be on-stream in the fourth quarter of 2013.

With three wells drilled in 2011 and one horizontal well planned for 2012, ARC will continue to assess production information from all three layers within the Montney formation, the two zones of the Upper Montney and the Lower Montney. This will provide valuable information as we plan for future development of this large gas resource.

Dawson

ARC's Dawson property continues to outperform expectations with individual well production remaining flat at a restricted rate of five mmcf per day for longer than expected. ARC currently has 18 completed horizontal wells that are not on production as all facilities are operating at capacity. ARC will utilize this well inventory to maintain production at 165 mmcf per day in 2012, without additional horizontal drilling. ARC will drill one vertical gas well at Dawson in 2012 to hold acreage that would otherwise expire.

Redwater

At Redwater, in central Alberta, ARC plans to spend $14 million to drill 10 horizontal Leduc wells. ARC expects to be able to keep production flat on this low decline property in 2012.

ARC completed the injection of purchased CO₂at its Redwater CO₂ enhanced oil recovery pilot program during the fourth quarter of 2010, and following that conducted extensive technical analysis during 2011 to assess the extent to which the pilot was successful in mobilizing incremental volumes of oil. ARC was pleased with the results of the CO₂ pilot program and has concluded that while the injection of CO₂ does provide increased oil recoveries, the economic viability of the project is dependent upon the availability of a sufficient supply of CO₂ at the appropriate input cost. ARC will continue to operate the CO₂ enhanced oil pilot in the recycle CO₂ injection phase and actively monitor the political and economic environment including the availability of economic sources of CO₂.

Exploration

Approximately seven per cent of ARC's 2012 capital budget will be directed towards exploration opportunities to identify new projects for future development. ARC does not budget for land purchases or acquisitions but will evaluate opportunities as they arise.

Non-Operated Capital

In addition to the operated activities, the non-operated budgeted capital for 2012 is estimated to be $51 million and includes drilling 44 gross (six net) wells, dominated by oil drilling activity in the Swan Hills area of Alberta, Weyburn and Star Valley in Saskatchewan and gas drilling activity in the Montney area of northeast British Columbia.


Capital by Type
($ millions)	2010 (Actual)	2011 (Estimate)	2012 (Budget)
Development	352	395	524
Development - Facilities	72	100	86
Maintenance	15	20	31
Optimization	11	15	16
Exploration & Seismic	24	93	56
Enhanced Oil Recovery	17	19	28
Land	61	71	0
Other	39	17	19
Total Capital	$591	$730	$760

(1)	Other capital of $19 million comprises capitalized General and Administrative Expenses ("G&A") including a portion of Long-Term Incentive Plan ("LTIP" or the "Whole Unit Plan") expense, information technology and corporate office capital.


Capital by Core Area
($ millions)		2010 (Actual)⁽¹⁾	2011 (Estimate)⁽²⁾	2012 (Budget)⁽³⁾
Capital by Area:
	Northeast British Columbia & Northwest Alberta	294	247	186
	Northern Alberta	84	185	265
	Pembina	57	97	100
	Southern Alberta & Southwest Saskatchewan	34	56	18
	Southeast Saskatchewan & Manitoba	66	97	143
	Redwater	18	35	25
	Corporate	37	13	23
Total Capital		$591	$730	$760
Capital by Province:
	Alberta	233	340	423
	Saskatchewan and Manitoba	68	149	158
	British Columbia	290	241	179

(1)	Corporate capital of $23 million in 2012 comprises capitalized General and Administrative Expenses ("G&A") including a portion of Long-Term Incentive Plan ("LTIP" or the "Whole Unit Plan") expense, information technology, corporate office capital and certain seismic expenditures.
(2)	Includes land.
(3)	Excludes land.


Operated Wells Drilled (gross)	2010 (Actual)	2011 (Estimate)	2012 (Budget)
Natural gas wells	33	17	3
Oil wells	86	130	179
Liquid rich natural gas wells	58	19	13
Total operated wells drilled (gross)	177	166	195

The amount and allocation of capital expenditures for exploration and development activities by area and the number and types of wells to be drilled is dependent upon results achieved and is subject to review and modifications by management on an ongoing basis throughout the year. In addition, the Board of Directors regularly reviews the capital program during the year in light of prevailing economic conditions, commodity prices and changing industry regulation and conditions and may modify the 2012 Budget during the year.

Production Volumes

Targeted annual production volumes for 2012 are expected to be approximately 90,000 to 95,000 boe per day, including estimated downtime for unplanned outages. This is a 12 per cent increase over anticipated 2012 volumes of between 82,000 and 83,000 boe per day.

On a regular basis, ARC evaluates its asset portfolio with a view to selling assets that do not meet our retention guidelines. Through the normal course of business, minor acquisitions and dispositions could occur that would impact the forecasted volumes.

Royalties and Operating Costs

Through the first nine months of 2011, ARC's total corporate royalty rate was 14.7 per cent as compared to 16.5 per cent in 2010. A higher proportion of natural gas production, low natural gas prices and changes to provincial royalty regimes all contributed to a lower corporate royalty rate in 2011 relative to 2010.

In 2012, ARC expects to capitalize on changes to the Alberta and British Columbia royalty regimes. In B.C., new wells which meet certain drilling depth criteria are eligible for royalty credits. In Alberta, production from new wells is eligible for a reduced royalty rate of five per cent, subject to certain production caps and time restrictions. ARC expects that the 2012 total corporate royalty rate will be in the 13.5 to 16 per cent range depending upon commodity prices and the production profile of eligible wells, as illustrated in the following table.


	Corporate Royalty Rate - 2012 Estimated
WTI crude oil (US$/bbl) ⁽¹⁾		$	70.00	$	80.00	$	90.00	$84.00⁽⁴⁾
AECO natural gas (Cdn$/GJ) ⁽¹⁾		$	3.50	$	4.00	$	4.50	$3.50⁽⁴⁾
Corporate Royalty Rate ⁽²⁾⁽³⁾			13.5%		15.2%		16.0%	15.0%⁽⁴⁾

(1)	Prices are 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 and includes estimated royalty incentives.
(4)	Based on October forward prices of US$84.00 per barrel and Cdn$3.50 per GJ, for crude oil and natural gas, respectively, the corporate royalty rate will be approximately 15 per cent in 2012.

ARC expects operating costs to increase slightly on a per boe basis from 2011 estimated costs to approximately $9.55 to $9.95 per boe in 2012, based on full year 2012 production costs of approximately $330 million. Higher 2012 total operating costs are due to increased production volumes relative to 2011. Increased oil and liquids production in 2012, which carry a higher cost profile relative to natural gas production and higher average expected power costs relative to 2011 contributed to the slight increase in per boe operating costs in 2012.

General and Administrative ("G&A") Expense

ARC estimates total 2012 G&A expenses will be $80 million, unchanged from expected total G&A in 2011, as higher compensation expenditures are anticipated to be offset by increased operating recoveries in 2012. On a per boe basis, 2012 G&A expenses are expected to decrease approximately eight per cent to $2.30 - $2.50 per boe compared to estimated costs of $2.50 - $2.70 per boe in 2011. Higher expected production levels in 2012 are the primary reason for lower per boe G&A expenses.

ARC's 2012 budgeted G&A includes estimated cash payments of approximately $26 million under the Long-Term Incentive Plan compared to a cash payment of $20.3 million in 2011. The estimated cash payments are dependent on ARC's share price and three year total return relative to its peers, and therefore are subject to a high degree of volatility. If ARC is able to achieve top quartile total returns relative to its peers on grants vesting under the Long-Term Incentive Plan in 2012, the cash payments included in G&A expenses will increase to approximately $29 million.

Following is a breakdown of estimated 2012 G&A expenses:


G&A Expenses ($ millions, except per boe amounts)		2010 (Actual)		2011 (Estimate)	2012 (Budget)
G&A expense before Long-Term Incentive Plan		$	59.1	$58.0	$60.0
Long-Term Incentive Plan expense		$	32.5	$22.0	$20.0
	Total G&A expense	$	91.6	$80.0	$80.0
G&A expense before Long-Term Incentive Plan per boe		$	2.19	$1.90 - $2.05	$1.75 - $1.85
Long-Term Incentive Plan expense per boe		$	1.20	$0.60 - $0.65	$0.55 - $0.65
	G&A expense per boe	$	3.39	$2.50 - $2.70	$2.30 - $2.50

(1)

Long-Term Incentive Plan expense includes cash payments of $20.5 million ($0.76 per boe), $20.3 million ($0.67 per boe) and $26 million ($0.75 - $0.80 per boe), respectively, for payments under the Long-Term Incentive Plan in 2010, 2011 (Estimate) and 2012 (Budget); the remaining portion of Long-Term Incentive Plan expense is a non-cash "accrued" expense.

Risk Management

As part of its overall strategy to protect cash flow, ARC uses a variety of instruments to hedge crude oil, natural gas, foreign exchange rates, electrical power costs and interest rates.

ARC has hedges in place to protect prices on both crude oil and natural gas volumes through the fourth quarter of 2011. ARC has a strong hedging position in place for 2012 with approximately 30 per cent of expected 2012 production protected at prices that will support ARC's business plan. Approximately 50 per cent of expected 2012 oil and liquids production is currently hedged at an average floor price of US$90.00 per barrel and approximately 20 per cent of expected 2012 natural gas production is currently hedged at an average floor price of Cdn$4.50 per mcf. ARC will continue to watch for opportunities to protect the 2012 and 2013 cash flow and will take positions in natural gas and/or crude oil at levels that will provide significant certainty on rates of return. The following table summarizes ARC's positions as at October 31, 2011.


Hedge Positions Summary ⁽¹⁾ As at October 31, 2011		November - December 2011		2012		2013
Crude Oil ⁽²⁾		US$/bbl	bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day
	Bought Call	-	-	115.00	9,000	-	-
	Sold Call	89.19	20,000	90.00	16,000	100.04	4,000
	Bought Put	84.19	20,000	90.00	16,000	90.04	4,000
	Sold Put	60.76	12,000	63.93	14,000	-	-
Natural Gas ⁽³⁾		Cdn$/mcf	mcf/day	Cdn$/mcf	mcf/day	Cdn$/mcf	mcf/day
	Swap	5.76	137,955	4.50	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 crude oil, all put positions settle against the monthly average WTI price, providing protection against monthly volatility. Calls have been sold against either the monthly average or the annual average WTI price. For annual sold calls, volumes are based on full year and 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.
(3)	The natural gas price shown translates all NYMEX positions to an AECO equivalent price based on offsetting basis positions and the period end exchange rate. ARC currently has a NYMEX equivalent fixed price swap at $5.90 and $5.00 per mmbtu for 2011 and 2012, respectively.

Reclamation Activities

ARC has an active abandonment and reclamation program for inactive wells, pipelines and leases. During 2011, ARC estimates spending approximately $8 million on activities on 325 sites as we maintain our leadership position in environmental responsibility. ARC expects reclamation spending to approximate $15 million in 2012.

Funding of the 2012 Capital Budget

The $760 million capital budget was determined after examining financial forecasts based on the expectation that oil prices could be in the range of US$70 to US$90 per barrel, natural gas could be in the range of Cdn$3.50 to Cdn$4.50 per GJ and assuming the continuation of the $0.10 monthly dividend throughout 2012. ARC will pursue cost effective means of financing its 2012 capital program through a combination of funds from operations, DRIP proceeds, existing credit facilities and proceeds from potential property dispositions. The exact split of financing will be dependent on commodity prices, operational performance and potential acquisitions and dispositions. Management will review the 2012 capital program on a regular basis in the context of prevailing economic conditions and make adjustments as necessary to the program, subject to review by the Board of Directors. The monthly $0.10 dividend is primarily dependent upon commodity prices and prevailing economic conditions and will be reviewed regularly by the Board of Directors.

Corporate Taxation

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 the 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. ARC expects that it would be taxable in 2012 instead of 2013 as a result of the loss of the deferral on partnership income.

Cash taxes payable in 2012 will largely be based on 2011 taxable income as the partnership has a January 31 year-end. ARC expects to pay cash income taxes of approximately $40 million in 2012.

Corporate Guidance

The corporate guidance for 2012 is based on commodity price expectations of US$70 to US$90 per barrel of crude oil and Cdn$3.50 to $4.50 per GJ of natural gas. Certain guidance estimates may fluctuate with changes in commodity prices. The 2012 Guidance provides shareholders with information on Management's expectations for results of operations, excluding any acquisitions, for 2012. Readers are cautioned that the 2012 Guidance may not be appropriate for other purposes.


Corporate Guidance		2010 (Actual)	2011 (Estimate)	2012 (Budget)
Production:
	Oil (bbls/d)	27,341	27,500	31,000 - 32,000
	Condensate (bbls/d)	1,617	1,700	1,700 - 2,100
	Natural gas (mmcf/d)	254	305	330 - 350
	Natural Gas Liquids (bbls/d)	2,628	2,500	2,500 - 3,000
	Annual average production (boe/d)	73,954	82,000 - 83,000	90,000 - 95,000
Costs and Expenses ($/boe):
	Operating	9.70	9.40 - 9.70	9.55 - 9.95
	Transportation	1.10	1.10 - 1.20	1.00 - 1.10
	G&A including Long-Term Incentive Plan ⁽¹⁾	3.39	2.50 - 2.70	2.30 - 2.50
	Interest	1.57	1.25 - 1.40	1.10 - 1.20
Corporate taxes ⁽³⁾		-	-	1.10 - 1.25
Capital expenditures ($ millions)		591	730	760
Weighted average and diluted shares (millions) ⁽²⁾		264	286	293

(1)	The 2012 G&A expense before Long-Term Incentive Plan approximates $62 million ($1.90 - $1.75 per boe). Long-Term Incentive Plan expense includes cash payments of $20.5 million ($0.76 per boe), $20.3 million ($0.67 per boe) and $26 million ($0.75 - $0.80 per boe), respectively, for payments under the Long-Term Incentive Plan in 2010, 2011 (Estimate) and 2012 (Budget). The remaining portion of Long-Term Incentive Plan expense is a non-cash "accrued" expense.
(2)	Based on weighted average shares plus the dilutive impact of share options outstanding during the period.
(3)	The 2012 Corporate tax estimate will vary depending on level of commodity prices.

Forward-looking Information and Statements

This news release is primarily comprised of forward-looking statements as to ARC's internal projections, expectations or beliefs relating to future events or future performance, including ARC's Corporate Guidance for 2012 and the amount and type of 2012 budgeted capital expenditures for the 2012 Capital Program, production volumes, royalties and operating costs, general and administrative expenses, risk management, reclamation activities, funding and taxation. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expects", "projects", "plans", "anticipates" and similar expressions but are contained in virtually every paragraph of this news release. These statements represent management's expectations or beliefs concerning, among other things, future capital expenditures and future operating results and various components thereof or the economic performance of ARC. The projections, estimates and beliefs contained in such forward-looking statements are based on management's assumptions relating to the production performance of ARC's oil and gas assets, the cost and competition for services throughout the oil and gas industry in 2012, the results of exploration and development activities during 2012, the market price for oil and gas, expectations regarding the availability of capital, estimates as to the size of reserves and resources, and the continuation of the current regulatory and tax regime in Canada, and necessarily involve known and unknown risks and uncertainties inherent in exploration and development activities, geological, technical, drilling and processing problems and other risks and uncertainties, including the business risks discussed in management's discussion and analysis and ARC's annual information form, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. The internal projections, expectations or beliefs are based on the 2012 Capital Budget which is subject to change in light of ongoing results, prevailing economic circumstances, commodity prices and industry conditions and regulations. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted. ARC does not undertake to update any forward looking information in this document whether as to new information, future events or otherwise except as required by securities rules and regulations.

Note: Barrels of oil equivalent (BOEs) may be misleading, particularly if used in isolation. In accordance with NI 51-101, a BOE conversion ratio for natural gas of 6 Mcf:1bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Reports Third Quarter 2011 Results

Wed, 02 Nov 2011 18:02:00 -0400

Nov 2, 2011

CALGARY, Nov. 2, 2011 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") is pleased to report its third quarter operating and financial results. Third quarter production was a record 85,178 boe per day, funds from operations were $213.5 million ($0.74 per share) and net income was $120.8 million ($0.42 per share). The Board of Directors approved an increase to the 2011 capital expenditure budget to $730 million. The related unaudited Condensed Consolidated Financial Statements and Notes, as well as Management's Discussion and Analysis ("MD&A"), are available on ARC's website at www.arcresources.com and on SEDAR at www.sedar.com.

		Three Months Ended September 30		Nine Months Ended September 30
		2011	2010 ⁽¹⁾	2011	2010 ⁽¹⁾
FINANCIAL
(Cdn$ millions, except per share and per boe amounts)
Funds from operations ⁽²⁾		213.5	167.7	617.6	486.5
	Per share ⁽³⁾	0.74	0.63	2.15	1.89
Net income		120.8	90.3	336.0	299.0
	Per share ⁽³⁾	0.42	0.34	1.17	1.18
Operating income ⁽⁴⁾		68.2	62.8	217.4	189.0
	Per share ⁽³⁾	0.24	0.23	0.76	0.73
Dividends		86.2	80.3	257.5	230.6
	Per share ⁽³⁾	0.30	0.30	0.90	0.90
Capital expenditures		229.3	159.5	531.0	431.8
Net debt outstanding ⁽⁵⁾		870.1	871.1	870.1	871.1
Shares outstanding, weighted average and diluted ⁽⁶⁾		287.1	268.0	286.0	257.7
Shares outstanding, end of period		287.7	283.1	287.7	283.1
OPERATING
Production
	Crude oil (bbl/d)	26,024	26,959	26,716	27,315
	Condensate (bbl/d)	2,009	1,689	1,996	1,422
	Natural gas (mmcf/d)	327.4	275.0	295.5	234.9
	Natural gas liquids (bbl/d)	2,584	3,001	2,555	2,449
	Total (boe/d) ⁽⁷⁾	85,178	77,483	80,517	70,337
Average prices
	Crude oil ($/bbl)	85.97	71.07	88.31	73.10
	Condensate ($/bbl)	92.85	73.51	94.17	76.88
	Natural gas ($/mcf)	3.88	3.79	3.99	4.39
	Natural gas liquids ($/bbl)	47.90	35.41	46.56	39.86
	Oil equivalent ($/boe)	44.83	41.14	47.75	45.98
Operating netback ($/boe)
	Commodity and other sales	44.89	41.19	47.83	46.06
	Transportation costs	(1.24)	(1.07)	(1.20)	(1.11)
	Royalties	(6.90)	(6.51)	(7.05)	(7.59)
	Operating costs	(10.13)	(9.31)	(9.81)	(9.98)
	Netback before hedging	26.62	24.30	29.77	27.38
	Hedging gain (loss) ⁽⁸⁾	4.13	3.09	2.16	2.07
	Netback after hedging	30.75	27.39	31.93	29.45
TRADING STATISTICS ⁽⁹⁾
High price		26.23	21.11	28.67	22.89
Low price		19.81	18.77	19.81	18.77
Close price		22.56	20.55	22.56	20.55
Average daily volume (thousands)		1,108	1,160	1,245	1,163

(1)	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 Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2010 to comply with IFRS. See Note 16, "Explanation of Transition to International Financial Reporting Standards" in the unaudited Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2011 for information on ARC's transition to IFRS and a reconciliation of its affected financial information.
(2)	Funds from operations is not a recognized performance measure under Generally Accepted Accounting Principles ("GAAP") and does not have a standardized meaning prescribed by GAAP. Historically, management disclosed cash flow from operating activities. Funds from operations has been presented herein for comparative purposes. See the "Non-GAAP Measures" section in the MD&A for the three and nine months ended September 30, 2011 and 2010 for a reconciliation of net income to funds from operations.
(3)	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.
(4)	Operating income is a non-GAAP measure, which adjusts net income for significant items that are not indicative of operating performance and that management believes reduces the comparability of the financial performance between periods. See "Operating Income" section in this news release for a reconciliation of operating income to net income for the three and nine months ended September 30, 2011.
(5)	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 prior production periods. Working capital deficit is calculated as current liabilities less the current assets as they appear on the 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.
(6)	Based on weighted average shares plus the dilutive impact of share options outstanding during the period. See Note 12 "Shareholders' Capital" in the unaudited Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2011.
(7)	Boe may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion ratio of 6 Mcf : 1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(8)	Includes cash gains (losses) on risk management contracts and unrealized losses on annually settled call contracts relating to prior production periods.
(9)	Trading prices are stated in Canadian dollars and based on intra-day trading.

FINANCIAL AND OPERATIONAL HIGHLIGHTS

Third quarter production volumes were a record 85,178 boe per day, 10 per cent higher than in the third quarter of 2010 and up three per cent relative to the second quarter of 2011. Strong oil prices, augmented by gains on ARC's crude oil and natural gas hedges, had a positive impact on net income and funds from operations in the third quarter. Net income increased 34 per cent in the third quarter and funds from operations increased 27 per cent relative to 2010. ARC maintained a strong balance sheet with low debt levels and an extended four year credit facility with significant credit capacity available.

ARC's third quarter production was a record 85,178 boe per day, 10 per cent higher than the third quarter of 2010 and a three per cent increase relative to the second quarter of 2011. Production downtime attributed to flooding and forest fires in the second quarter was resolved and all production was back on-stream throughout the third quarter. Approximately 450 barrels per day of oil production was shut-in throughout the third quarter due to pipeline restrictions in northern Alberta, all production was back on-stream early in the fourth quarter. Year-to-date 2011 production averaged 80,517 boe per day, a 14 per cent increase from 2010 due to a successful drilling program and incremental production attributed to the acquisition of Storm Exploration Inc. ("Storm") in August 2010, offset by the sale of 3,400 boe per day of producing properties in January 2011. Full year 2011 production volumes are on target to average 82,000 - 83,000 boe per day and exit production is expected to be greater than 90,000 boe per day.
Third quarter production consisted of 36 per cent crude oil and liquids and 64 per cent natural gas. The increase in natural gas production is attributed to the 60 mmcf per day Dawson Phase 2 gas plant, which came on-stream in the second quarter of 2011. While oil and liquids production represented 36 per cent of third quarter production, it contributed approximately 67 per cent of sales revenue due to the strength of crude prices relative to natural gas prices. ARC will continue to exploit oil and liquids opportunities in 2011 and 2012 to capitalize on the near-term strength of crude prices. ARC's diversified production portfolio and an active hedging program serve to mitigate the impact of the low natural gas price environment.
Funds from operations of $213.5 million ($0.74 per share) in the third quarter of 2011 were up 27 per cent from $167.7 million ($0.63 per share) in the third quarter of 2010. Year-to-date 2011 funds from operations of $617.6 million ($2.15 per share) were up 27 per cent relative to the same period of 2010. Higher third quarter funds from operations were attributed to higher production volumes and crude oil prices and increased gains on ARC's commodity hedging program.
Net income was $120.8 million ($0.42 per share) in the third quarter of 2011, up 34 per cent from $90.3 million ($0.34 per share) in the third quarter of 2010. Year-to-date net income was $336 million ($1.17 per share), a 12 per cent increase from 2010. Third quarter and year-to-date net income increased due to unrealized mark-to-market ("MTM") gains on risk management contracts, partially offset by unrealized foreign exchange losses on revaluation of ARC's U.S. dollar denominated debt balance and a property impairment attributed to the decline in future natural gas prices in the quarter. Higher deferred tax expense, resulting from the conversion from a trust to a corporation, had a negative impact on third quarter and year-to-date net income.
Operating incomewas $68.2 million ($0.24 per share) in the third quarter of 2011, a nine per cent increase from operating income of $62.8 million ($0.23 per share) in the third quarter of 2010. Year-to-date 2011 operating incomewas $217.4 million ($0.76 per share), up 15 per cent from 2010. The increase in third quarter and year-to-date operating income was due to higher volumes and higher netbacks attributed to increased crude oil prices.
ARC's total realized price of $44.83 per boe in the third quarter of 2011 was up nine per cent from the $41.14 per boe in the third quarter of 2010. Crude oil prices averaged $85.97 per barrel in the third quarter, an increase of 21 per cent relative to 2010 prices. Natural gas prices, still depressed by high inventory levels and increased natural gas production in the United States, were up an average of two per cent relative to 2010 levels to $3.88 per mcf in the third quarter. ARC's year-to-date realized price of $47.75 per boe was up four per cent relative to 2010 due to a 21 per cent increase in average crude oil prices, which was partially offset by a nine per cent decrease in natural gas prices.
ARC realized cash hedging gains of $40.4 million on crude oil and natural gas hedges in the third quarter. ARC realized a cash gain of $26.8 million on natural gas hedges as 53 per cent of third quarter natural gas production was hedged at an average floor price of Cdn$5.31 per mcf, well above the average third quarter market price of Cdn$4.05 per mcf. ARC realized a $10.4 million cash gain on crude oil hedges, primarily due to the unwinding of a 2012 US$102 per barrel crude oil hedge on 2,000 barrels per day during the third quarter. Third quarter and year-to-date cash hedging gains were offset by unrealized losses of $4.8 million and $38.1 million, respectively on crude oil annually settled call contracts resulting in net hedging gains of $35.6 million ($4.56 per boe) and $53.6 million ($2.44 per boe), respectively, for the third quarter and year-to-date. The decline in crude oil forward prices at the end of the third quarter resulted in an unrealized MTM hedging gain of $138.3 million in the quarter.
ARC has protected the price on 20,000 barrels per day, approximately 60 per cent of expected fourth quarter oil and liquids production within the range of US$84 to US$90 per barrel. For 2012, ARC has hedged 16,000 barrels per day, approximately 45 per cent of estimated 2012 oil and liquids production, at an average floor price of US$90 per barrel. Approximately 169 mmcf per day (50 per cent) and 77 mmcf per day (25 per cent) of natural gas production for the fourth quarter of 2011 and full year 2012 is protected at average floor prices of $5.45 per mcf and $4.65 per mcf, respectively. ARC hedged additional crude oil volumes in 2013.
Capital expenditures for the third quarter totaled $229.3 million resulting in year-to-date capital expenditures of $531 million. ARC drilled 42 gross operated oil wells and seven gross operated natural gas wells with a 100 per cent success rate during the third quarter, bringing total wells drilled to 87 gross operated oil wells and 29 gross operated natural gas wells with a 100 per cent success rate for the first nine months of 2011. Third quarter capital activities ramped up following second quarter delays due to flooding and forest fires. Year-to-date capital spending includes $71 million for purchases of predominately oil-prone lands in and around our core areas. ARC's Board of Directors approved an increase in full year 2011 capital spending to approximately $730 million. The increase is attributed to previously unbudgeted crown land purchases and the acceleration of certain oil and liquids projects. ARC will continue to focus on oil and liquids-rich opportunities at Ante Creek, Pembina, Goodlands and Parkland and staged development of the Montney natural gas opportunities in northeast British Columbia.
ARC renegotiated and extended its syndicated revolving credit facility to a four year term during the third quarter. Borrowing costs under the credit facility decreased relative to previous levels with credit spreads ranging from 160 basis points to 325 basis points depending on ARC's ratio of debt to net income before non-cash items and interest expense. ARC has total credit capacity of $1.6 billion, total borrowings of $682 million and a working capital deficit of $188 million, leaving approximately $725 million of total available credit capacity. Net debt to annualized year-to-date funds from operations ratio was 1.1 times and net debt was approximately 12 per cent of ARC's total capitalization at the end of the third quarter; both well within ARC's target levels.
ARC declared and paid a dividend of $0.30 per share to shareholders for the third quarter of 2011 and has confirmed a dividend of $0.10 per share to shareholders for October 2011 to be paid on November 15, 2011. ARC has conditionally declared a dividend of $0.10 per share, payable monthly for November 2011, December, 2011 and January, 2012, subject to confirmation by monthly news release and subject to any further resolution of the Board of Directors. Including payments through October 15, ARC has maintained the current monthly dividend level of $0.10 per share for a period of 29 months.
ARC's board of directors has approved a $760 million capital program for 2012. Additional details can be found in the November 2, 2011 news release titled "ARC Resources Ltd. announces a $760 million capital budget for 2012, which includes a 12 per cent production growth target" filed on SEDAR at www.sedar.com.
ARC is pleased to announce it has been named to the 2011 Carbon Disclosure Leadership Index ("CDLI") in recognition of its leadership in such disclosure. It is the fourth consecutive year ARC has been included in the CDLI. ARC is one of 20 Canadian companies to be included, and one of four energy companies. The Carbon Disclosure Leadership Index is compiled by the Carbon Disclosure Project, which represents 551 investors and $71 trillion in assets.

ORGANIZATIONAL UPDATE

ARC is pleased to announce the appointment of Cam Kramer to the position of Senior Vice President, Operations. Mr. Kramer has over 20 years of experience in the North American oil and gas business. Prior to joining ARC Resources Ltd. in 2011, Mr. Kramer worked with a major oil and gas company as Senior Vice-President, North American Operations. Mr. Kramer brings a broad background in operations and leadership. He holds a B.Sc. in Chemical and Petroleum Engineering from the University of Calgary and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta.

FINANCIAL REVIEW

The positive financial impact of record production volumes and higher oil prices was partially offset by continued low natural gas prices during the third quarter. ARC exited the quarter with a strong balance sheet due to strong year-to-date funds from operations and the receipt of $170 million of proceeds from the sale of properties in the first quarter of 2011. ARC maintained a dividend of $0.30 per share in the third quarter of 2011.

Funds from operations

ARC's third quarter funds from operations of $213.5 million ($0.74 per share) were up 27 per cent compared to the third quarter of 2010 funds from operations of $167.7 million ($0.63 per share). Third quarter sales increased 20 per cent due to a 10 per cent increase in third quarter production and a nine per cent increase in realized price relative to 2010. Cash gains of $40.4 million on ARC's commodity hedging program positively impacted third quarter funds from operations in the quarter ($25.3 million cash gain in 2010).

Year-to-date 2011 funds from operations of $617.6 million ($2.15 per share) were up 27 per cent compared to the funds from operations of $486.5 million ($1.89 per share) for the same period of 2010. The increase in year-to-date funds from operations was due to the 14 per cent increase in production and four per cent increase in realized prices. Year-to-date cash gains of $91.7 million on ARC's commodity hedging program positively impacted funds from operations in 2011 ($45.4 million cash gain in 2010).

Third quarter and year-to-date 2011 funds from operations were reduced by $4.8 million and $38.1 million, respectively, for unrealized losses on crude oil annually settled call contracts pertaining to contracted volumes in the third quarter and first nine months of 2011.

Following is a reconciliation of net income to funds from operations for the third quarter and first nine months of 2011 and 2010.


		Three Months Ended September 30		Nine Months Ended September 30
		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)	-
	Unrealized losses on risk management contracts relating to January through September 2011 production ⁽¹⁾	(4.8)	-	(38.1)	-
	Other	0.7	9.8	1.4	13.2
Funds from operations		213.5	167.7	617.6	486.5
Funds from operations per share		$0.74	$0.63	$2.15	$1.89

(1)

Unrealized losses on crude oil annually settled call contracts pertaining to third quarter and year-to-date contracted volumes. The annually settled call contracts are commodity price risk management contracts, which pertain to production periods spanning the entire calendar year but that are cash settled at the end of the year based on the annual average benchmark crude oil price. The portion of total losses 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 the effect of all contracts used for economic hedging in the period, regardless of the timing of cash settlement.

The following table details the items contributing to the change in funds from operations for the third quarter and first nine months of 2011 relative to 2010.


		Three Months Ended September 30		Nine Months Ended September 30
		$ millions	$ per share	$ millions	$ per share
Funds from operations - 2010		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 relating to January through September 2011 production ⁽¹⁾		(4.8)	(0.02)	(38.1)	0.15)
Royalties		(7.7)	(0.03)	(9.2)	(0.04)
Expenses:
	Operating and transportation	(15.1)	(0.06)	(29.1)	(0.11)
	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		213.5	0.74	617.6	2.15

(1)

Operating Netbacks

ARC's operating netback, before hedging, increased 10 per cent to $26.62 per boe in the third quarter of 2011 compared to $24.30 per boe in the same period of 2010. The increase in pre-hedging netbacks is primarily due to the increase in crude oil prices. After hedging, ARC's third quarter netback was $30.75 per boe, a 12 per cent increase from the same period in 2010. The third quarter 2011 netback includes net gains recorded on ARC's crude oil and natural gas risk management contracts during the quarter of $32.4 million ($4.13 per boe) compared to a net gain of $22 million ($3.09 per boe) recorded for the same period in 2010. ARC's year-to-date 2011 netback after hedging was $31.93 per boe, an eight per cent increase from the same period in 2010 due primarily to higher crude oil prices.

ARC's 2011 third quarter and year-to-date total corporate royalty rates decreased to 15.4 per cent and 14.7 per cent, respectively compared to 15.8 per cent and 16.5 per cent, respectively in 2010. The higher proportion of natural gas production, low natural gas prices and changes to provincial royalty regimes resulted in lower total corporate royalty rates relative to 2010.

Third quarter operating costs increased nine per cent to $10.13 per boe relative to 2010. Higher operating costs were primarily attributed to significantly higher power costs with Alberta Power Pool prices averaging $95/MWh during the third quarter of 2011 compared to $35/MWh in the third quarter of 2010. Operating costs of $9.81 per boe for the first nine months of 2011 were slightly lower than 2010 due to the sale of higher cost properties in the first quarter of 2011 and a higher proportion of low cost natural gas production in 2011 offset by higher average power costs in 2011.

The following table details components of operating netbacks for the third quarter and first nine months of 2011.


Netbacks - Q3	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 before hedging	54.09	36.76	57.82	2.10	22.41	26.62	24.30
Hedging gain (loss) ⁽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


Netbacks - YTD	Crude Oil ($/bbl)	Heavy Oil ($/bbl)	Condensate ($/bbl)	Natural Gas ($/mcf)	NGL ($/bbl)	YTD 2011 Total ($/boe)	YTD 2010 Total ($/boe)
Average sales price	89.90	70.94	94.17	3.99	46.56	47.75	45.98
Other	-	-	-	-	-	0.08	0.08
Total sales	89.90	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 before 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 (loss) includes realized cash gain (loss) on risk management contracts including the settlement amounts for crude oil and natural gas contracts and unrealized loss on risk management contracts relating to third quarter and first nine months of 2011 of $4.8 million and $38.1 million, respectively. Foreign exchange, power and interest contracts are excluded from the netback calculation.

Net Income

Net income increased 34 per cent in the third quarter of 2011 to $120.8 million ($0.42 per share) from $90.3 million ($0.34 per share) in the third quarter of 2010. Third quarter net income included a $138.3 million unrealized MTM gain on risk management contracts, predominantly attributed to crude oil contracts wherein the crude oil futures price declined at the end of the third quarter relative to the second quarter ($23.8 million unrealized MTM gain in 2010). Net income was reduced by $31.3 million for an unrealized foreign exchange loss, which resulted from the revaluation of U.S. denominated debt balances caused by the devaluation of the Canadian dollar during the quarter ($13.4 million unrealized foreign exchange gain in 2010).

Year-to-date 2011 net income of $336 million ($1.17 per share) was up 12 per cent from net income of $299 million ($1.18 per share) in 2010. Net income included a $63.7 million unrealized MTM gain on risk management contracts ($114.1 million unrealized MTM gain in 2010) and a $92.7 million gain on disposal of producing properties (nil 2010). Net income was reduced by $19.1 million for an unrealized foreign exchange loss attributed to revaluation of U.S. denominated debt balances caused by the devaluation of the Canadian dollar during 2011 ($11.9 million unrealized foreign exchange gain in 2010).

Third quarter and year-to-date 2011 net income was reduced by $45.1 and $16.6 million, respectively, for a property impairment due to the decline in future natural gas prices during the period in accordance with International Financial Reporting Standards ("IFRS") (nil impairment in 2010). Under IFRS, an impairment is recorded when the property's recoverable value, based on future prices, is less than its carrying value. If the recoverable value increases in a subsequent period, a recovery of the impairment may be recorded up to the previous carrying value of the property less applicable depletion charges.

As a result of converting from a trust structure to a corporation in January 2011, ARC recorded higher deferred tax expense in the third quarter and first nine months of 2011.

Operating Income

Third quarter operating income was $68.2 million ($0.24 per share), up nine per cent from $62.8 million ($0.23 per share) in the third quarter of 2010. Year-to-date 2011 operating income of $217.4 million ($0.76 per share) increased 15 per cent relative to 2010. The increase in third quarter and year-to-date operating income was primarily due to higher production in 2011 and higher netbacks attributed to increased crude oil prices and higher hedging gains in 2011.

Following is a summary of operating income for the third quarter and first nine months of 2011 and 2010.



		Three Months Ended September 30		Nine Months Ended September 30
		2011	2010	2011	2010
Net income		120.8	90.3	336.0	299.0
Add (deduct) non-operating items, net of tax:
	Unrealized (gain) loss on risk management contracts relating to future production periods	(103.7)	(22.3)	(47.7)	(106.9)
	Unrealized loss on risk management contracts relating the third quarter and first nine months of 2011 ⁽¹⁾	(3.6)	-	(28.5)	-
	Unrealized (gain) loss on foreign exchange	23.4	(12.5)	14.3	(11.1)
	(Gains) on disposal of petroleum and natural gas properties	(3.6)	-	(69.4)	-
	Impairment of property, plant and equipment	33.8	-	12.5	-
	Unrealized gain on short-term investment	0.9	(0.8)	0.2	(0.8)
	(Gain) loss on revaluation of exchangeable shares	-	8.1	-	8.8
Operating Income - $ millions ⁽¹⁾		68.2	62.8	217.4	189.0
Operating Income - $ per share ⁽¹⁾		$0.24	$0.23	$0.76	$0.73

(1)

(2)

Debt Management

ARC closed the third quarter with a strong balance sheet with net debt to total capitalization of 12 per cent. Net debt to annualized funds from operations was 1.1 times, within the range of ARC's targeted limit of 1.0 - 1.5 times. Debt levels decreased slightly relative to year-end 2010 levels as a result of strong funds from operations and proceeds of $170 million from property sales early in 2011.

ARC successfully renegotiated and extended its syndicated revolving credit facility to a four year term through to August 2015 during the third quarter. ARC's total credit capacity is unchanged at $1.6 billion, consisting of the $1 billion revolving credit facility and $570 million of private notes. Borrowing costs under the new credit facility have decreased relative to previous levels with credit spreads ranging from 160 basis points to 325 basis points depending on ARC's ratio of debt to net income before non-cash items and interest expense.

At September 30, ARC had borrowings of $226 million under the credit facility, $456 million of private notes and a working capital deficit of $188 million, leaving approximately $725 million of total available credit capacity. Approximately 67 per cent of outstanding debt is fixed-rate with a weighted average remaining term of 5.5 years.

ARC expects to finance its 2011 and 2012 capital programs with funds from operations, proceeds from the Dividend Re-investment Plan ("DRIP"), the existing credit capacity and proceeds from rationalization of minor assets.

Risk Management

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

ARC realized cash hedging gains of $40.4 million in the third quarter and $91.7 million for the first nine months of 2011 on commodity hedges. ARC unwound a 2012 US$102 per barrel crude oil hedge on 2,000 barrels per day, recognizing a gain of $10.7 million in the third quarter of 2011. ARC realized cash gains on natural gas hedging contracts in the third quarter as 53 per cent of third quarter natural gas production was hedged at an average floor price of CDN$5.31 per mcf, well above the average market price of CDN$4.05 per mcf. Third quarter and year-to-date cash hedging gains were offset by unrealized losses of $4.8 million and $38.1 million, respectively, on crude oil annually settled call contracts to arrive at net hedging gains of $35.6 million ($4.56 per boe) and $53.6 million ($2.44 per boe), respectively, for the third quarter and year-to-date. Unlike the majority of ARC's risk management contracts that are settled monthly, these annually settled call contracts, which relate to production throughout 2011, will be cash-settled in their entirety in January 2012 based on the annual average price.

Floor prices on crude oil and natural gas hedged volumes for 2011 through 2013 provide a level of certainty on ARC's ability to execute its business plan over the next two years. Given the significant contribution of ARC's crude oil and natural gas liquids production to total sales and funds from operations, ARC management recognizes the risk associated with an unanticipated reduction in crude oil pricing. Accordingly, ARC has protected the selling price on a portion of crude oil production by establishing crude oil floor and ceiling prices through 2013. Likewise, ARC has partially mitigated the weak outlook for natural gas prices by establishing floor prices on a portion of natural gas production through 2013. In total, ARC currently has hedged approximately 50 per cent, 30 per cent, and less than five per cent of total production for 2011, 2012 and 2013, respectively, as summarized in the table below. For a complete listing and terms of ARC's hedging contracts, see Note 11 "Risk Management Contracts" in the unaudited Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2011.


Hedge Positions Summary ⁽¹⁾ As at September 30, 2011		October - December 2011		2012		2013
Crude Oil ⁽²⁾		US$/bbl	bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day
	Bought Call	-	-	115.00	9,000	-	-
	Sold Call	88.91	20,000	90.00	16,000	110.00	2,000
	Bought Put	83.91	20,000	90.00	16,000	90.00	2,000
	Sold Put	60.43	12,000	63.93	14,000	-	-
Natural Gas ⁽³⁾		Cdn$/mcf	mcf/day	Cdn$/mcf	mcf/day	Cdn$/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. Calls have been sold against either the monthly average or the annual average WTI price. For annual sold calls, volumes are based on full year and 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.
(3)	The natural gas price shown translates all NYMEX positions to an AECO equivalent price based on offsetting basis positions and the period end exchange rate. The equivalent hedged NYMEX price would be a floor of $5.73 per mmbtu and a ceiling of $5.92 per mmbtu for 2011. ARC currently has a NYMEX equivalent fixed price contract at $5.00 per mmbtu for 2012.

ARC's third quarter unrealized MTM gain of $138.3 million on commodity hedging contracts was due primarily to a reduction in crude oil forward prices as at September 30, 2011 compared to the previous quarter. The actual future cash settlements under the commodity hedge contracts will differ from the current unrealized MTM value with changes in commodity prices in future periods.

OPERATIONAL REVIEW

During the third quarter of 2011 ARC spent $229.3 million on drilling, facilities, optimization and exploration activities and the purchase of crown lands. ARC drilled 49 gross (46 net) operated wells comprising 42 gross (39 net) oil wells and seven gross (seven net) natural gas wells with a 100 per cent success rate in the third quarter. This brings the total wells drilled for the first nine months of 2011 to 87 gross (79 net) oil wells and 29 gross (29 net) natural gas wells with a 100 per cent success rate. Oil and liquids-rich natural gas wells represented 74 per cent of total wells drilled in the first nine months of 2011, reflecting ARC's strategy to capitalize on the strength of oil prices through acceleration of oil and liquids projects in 2011.

Third quarter production of 85,178 boe per day increased 10 per cent relative to the third quarter of 2010, and was three per cent higher than the second quarter of 2011. Third quarter production comprised 64 per cent natural gas and 36 per cent crude oil and liquids. Higher natural gas production was attributed to the start-up of the 60 mmcf per day Dawson Phase 2 gas plant in the second quarter of 2011.

Capital expenditures increased in the third quarter after being constrained by flooding in Manitoba and Saskatchewan and forest fires in Alberta during the second quarter. All production in the affected areas was back on-stream for the entire third quarter.

Dawson

Production from the Dawson property in the Montney region of northeast British Columbia averaged 154 mmcf per day of natural gas in the third quarter, up 48 per cent from 104 mmcf per day in the third quarter of 2010. With the start up of the Phase 2 gas plant in the second quarter of 2011, ARC's Dawson operated gas plant processing capacity increased to 120 mmcf per day, bringing total capacity to 165 mmcf per day including 45 mmcf per day of third-party processing capacity.

ARC's Dawson property continues to outperform expectations with individual well production remaining flat at a restricted rate of five mmcf per day for longer than expected. This has resulted in an inventory of 18 horizontal wells that are currently completed but are not on production as all facilities are operating at capacity. ARC will utilize this well inventory to maintain production at 165 mmcf per day in 2012, without additional horizontal drilling.

West Montney

ARC's West Montney region includes the Sunrise, Septimus and Sundown properties. In the first nine months of 2011, ARC drilled two horizontal wells and one vertical acid gas disposal well in anticipation of the Phase 1 Sunrise gas plant. Third quarter production averaged 10 mmcf per day of natural gas from the Sunrise area, up 54 per cent from the second quarter of 2011, with production coming from three different zones in the Montney. ARC brought on 15 mmcf per day of operated natural gas production through a third party facility late in the third quarter and exited the quarter with production of 22 mmcf per day. This production will aid in establishing an important production type curve for development of the Sunrise property.

ARC has received approval from the British Columbia Oil and Gas Commission to construct two, 60 mmcf per day gas plants at Sunrise. Current plans target the first 60 mmcf per day of capacity to be on-stream in the fourth quarter of 2013.

Parkland

Parkland is a liquids-rich area with third quarter 2011 production averaging 8,150 boe per day composed of 43 mmcf per day of natural gas and 1,025 barrels per day of natural gas liquids. Third quarter production was up eight per cent relative to the second quarter of 2011 as production returned to normal levels following a third party plant turnaround in the second quarter of 2011.

ARC drilled three horizontal, liquids-rich natural gas wells at Parkland during the third quarter. One horizontal well was drilled and completed into a lower section of the Upper Montney. ARC anticipates this placement will not communicate with the upper section of the Upper Montney; if no interference is observed, development of this portion of the reservoir could result in additional locations and incremental reserve recovery. Two horizontal wells were drilled in the liquids-rich Tower area. Test results from the first two wells were encouraging, and work is being done to tie the wells in so as to determine the productive potential of this area. The first wells are expected to be on production by year-end 2011.

ARC will continue to focus on further testing of the productive capacity in the liquids-rich Tower area and evaluate plans for facility expansion in the area for 2012 and 2013.

Attachie

ARC holds a prospective land base of 110 gross (110 net) sections in the Attachie property located northwest of Dawson. Currently there are no booked reserves or production at Attachie.

The first horizontal well at Attachie, completed in the second quarter, achieved a stabilized test production rate of 10 mmcf per day (30 barrels per mmcf of liquids) at a pressure of nine MPa. ARC will complete and test two additional horizontal wells in the fourth quarter to further delineate the potential at Attachie. Additionally, ARC will continue to collaborate with third parties regarding options for commercial development and infrastructure requirements for this new play.

Ante Creek

Third quarter production averaged 7,400 boe per day (49 per cent light crude oil and natural gas liquids, 51 per cent natural gas) at Ante Creek. The first five horizontal Montney oil wells drilled at Ante Creek in 2011 have averaged 30 day initial production rates of 420 boe per day compared to average rates of 100 boe per day for vertical wells. Given the favorable results from horizontal drilling, ARC believes that the Ante Creek property will provide a significant near-term growth opportunity with continued drilling and expansion of facility capacity.

During the third quarter, ARC drilled six horizontal oil wells into the Montney formation. To the end of the third quarter 2011, ARC has drilled 11 horizontal Montney oil wells at Ante Creek and completed seven wells with the remaining four wells to be completed by the end of 2011.

Construction of the new 30 mmcf per day gas plant continued in the third quarter. Major lease and road construction, including installation of approximately 20 per cent of major equipment and structural components, was completed. The plant is on schedule for start-up late in the first quarter of 2012 and is on budget with an expected total cost of $40 million.

ARC plans to drill eight horizontal Montney oil wells and continue with construction of the gas plant in the fourth quarter of 2011. ARC's fourth quarter Ante Creek drilling program was expanded as a result of favorable drilling results seen to date. ARC expects to grow liquids production to approximately 5,800 barrels per day and to increase total production at Ante Creek to approximately 12,000 boe per day through the course of 2012.

Pembina

ARC is the second largest operator in the Pembina area, operating approximately 25 per cent of the Pembina oil field with an average 65 per cent working interest in 166 gross sections (126 net sections). Third quarter production averaged 10,200 boe per day and comprised approximately 70 per cent light crude oil and liquids and 30 per cent natural gas, an increase of nine per cent from production of 9,400 boe per day in the comparable period of 2010. During the third quarter, ARC drilled 13 gross horizontal wells into the Cardium formation, bringing the total wells drilled in the first nine months of 2011 to 27 gross horizontal Cardium wells, 20 of which were completed and on-stream at the end of the third quarter.

ARC is pleased with results to date, with third month production average of 180 boe per day for its recent wells. Due to the areal extent of the field and the geologic complexity of the reservoir, each location needs to be evaluated individually. ARC will continue to evaluate this field in order to gain a better understanding of where the horizontal completion technology can be most effectively applied.

ARC plans to drill 10 gross horizontal Cardium locations in the fourth quarter to further develop this reservoir. ARC acquired a gas plant during the second quarter to alleviate solution gas handling constraints at Pembina. In addition, extensive work is also planned on waterflood management to optimize reservoir recoveries.

Southeast Saskatchewan and Manitoba

Southeast Saskatchewan and Manitoba was the hardest hit area as a result of the flooding in the second quarter. All production was back on-stream and capital programs resumed over the course of the third quarter. ARC contracted two additional drilling rigs during the third quarter in an effort to complete its original full year capital program following the delays in the second quarter. In the first nine months of 2011, ARC drilled 27 wells in this area; 19 wells were brought on-stream and eight wells will be completed in the fourth quarter of 2011.

The Goodlands property in Manitoba, provides some of the best drilling economics in ARC's portfolio due to the high netback, light crude oil. Third quarter production averaged 980 boe per day of light crude oil as production returned to normal levels following second quarter downtime and delays in execution of capital programs. ARC drilled 10 Goodlands oil wells during the third quarter, which will be completed in the fourth quarter.

ARC plans to drill 10 gross oil wells in southeast Saskatchewan and seven gross oil wells at Goodlands in the fourth quarter of 2011. A facility expansion at Goodlands is planned for the fourth quarter of 2011 to add oil capacity in response to active drilling programs in 2011 and 2012.

DIVIDENDS

ARC paid dividends totaling $0.30 per share for the second quarter of 2011 and $0.90 per share for the first nine months of 2011. The Board of Directors has confirmed a dividend of $0.10 per share for October 2011, payable on November 15, 2011, and has conditionally declared a monthly dividend of $0.10 per share for November 2011, December 2011 and January 2012, targeting a total dividend of $0.30 per share for the fourth quarter of 2011. The dividends have been designated as eligible dividends under the Income Tax Act (Canada) and are payable as follows:


Ex-dividend date	Record date	Payment date	Per share amount
October 27, 2011	October 29, 2011	November 15, 2011	$0.10 ⁽¹⁾
November 28, 2011	November 30, 2011	December 15, 2011	$0.10 ⁽²⁾
December 28, 2011	December 30, 2011	January 16, 2012	$0.10 ⁽²⁾
January 27, 2012	January 31, 2012	February 15, 2012	$0.10 ⁽²⁾

(1) Confirmed on October 17, 2011.
(2) Conditionally declared, subject to confirmation by news release and further resolution by the Board of Directors.

OUTLOOK

The pillar of ARC's business strategy is "risk-managed value creation". ARC's goal is to transform this value into shareholder returns through regular dividends and anticipated capital appreciation relating to future growth. ARC received approval from the 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.

ARC's 2011 capital program includes the drilling of 166 gross (156 net) wells on operated properties and 83 gross (10 net) non-operated wells are expected to be drilled by partners. ARC has a balanced portfolio of high-quality assets with current production of approximately 60 per cent natural gas and 40 per cent crude oil and natural gas liquids. The mix of liquids and natural gas in ARC's portfolio has enabled ARC to respond to the prolonged, low natural gas price environment effectively by redirecting a portion of capital to oil and liquids projects that generate significant returns and cash flow relative to near-term dry natural gas projects.

Given the strong outlook for crude oil prices, a significant portion of ARC's 2011 capital program has been allocated to oil and liquids projects, which will account for approximately 91 per cent of operated wells to be drilled in 2011. Ante Creek, Pembina and Goodlands will see significant oil drilling activity in 2011 as well as the construction of a new gas processing facility at Ante Creek to address current capacity constraints. ARC will continue to assess the liquids potential of the Montney at Parkland.

Despite continued low natural gas prices, ARC's Montney natural gas economics support staged development of this area at current natural gas prices. With the completion of the Phase 2 Dawson gas plant in the second quarter, ARC's operated processing capacity in Dawson doubled to 120 mmcf per day. Plans for two 60 mmcf per day gas plants at Sunrise will further expand capacity and set the stage for long-term growth in this area over the next two to five years.

ARC expects the fourth quarter to be very active and plans to spend approximately $200 million and drill 166 gross (156 net) operated wells. ARC believes that full year 2011 production volumes will average 82,000 - 83,000 boe per day and expects exit 2011 production to be greater than 90,000 boe per day. ARC's full year production guidance was revised to 82,000 - 83,000 boe per day from previous guidance of 80,000 - 85,000 boe per day and 2011 capital expenditure guidance was increased to $730 million, previously $690 million. All other 2011 guidance estimates are unchanged and are summarized in the following table.


		2011 Guidance	2011 YTD Actual	% Variance
Production (boe/d) ⁽¹⁾		82,000 - 83,000	80,517	(2)
Expenses ($/boe):
	Operating	9.40 - 9.70	9.81	(1)
	Transportation	1.10 - 1.20	1.20	-
	General and administrative ⁽²⁾	2.50 - 2.70	2.80	(4)
	Interest	1.25 - 1.40	1.35	-
Capital expenditures ($ millions) ⁽³⁾		730	531	-
Weighted average and diluted shares (millions) ⁽⁴⁾		286	286	-

(1)	Revised from previous guidance of 80,000 - 85,000 boe per day.
(2)	The 2011 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 and a recovery of ($0.04) per boe, respectively.
(3)	ARC's 2011 guidance for capital expenditures was increased to $730 million from previous guidance of $690 million.
(4)	Based on weighted average shares plus the dilutive impact of share options outstanding during the period.

Variances from full year guidance at the end of the third quarter are timing related; ARC expects that full year 2011 results will match guidance estimates.

CORPORATE TAX LEGISLATION

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 the 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. ARC expects that it would be taxable in 2012 instead of 2013 as a result of the loss of the deferral on partnership income.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

Effective January 1, 2011 all Canadian publicly accountable enterprises are required to prepare their financial statements in accordance with International Financial Reporting Standards ("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. 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 for the three and nine months ended September 30, 2011 and 2010 filed on SEDAR at www.sedar.com.

Forward-looking Information and Statements

This news release 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 news release contains forward-looking information and statements pertaining to the following: guidance as to the 2012 budget and capital expenditure program and plans relating to the construction of gas plants at Ante Creek and Sunrise under the heading "Financial and Operational Highlights" plans relating to the financing of its 2011 and 2012 capital programs under the heading "Debt Management" various plans, forecasts and estimates as to drilling operations and completions, production estimates, timing of building and completion of gas plants and other operational forecasts under the heading "Operational Review", and all matters including 2011 guidance under the heading "Outlook".

The forward-looking information and statements contained in this news release reflect 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 Funds from operations 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.

ARC Resources Ltd. ("ARC") is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC expects 2011 oil and gas production to average 82,000 to 83,000 barrels of oil equivalent per day from its properties in western Canada. ARC's Common Shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Confirms November 15, 2011 Dividend Amount

Mon, 17 Oct 2011 11:50:00 -0400

Oct 17, 2011

CALGARY, Oct. 17, 2011 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on November 15, 2011 to shareholders of record on October 31, 2011. The ex-dividend date is October 27, 2011.

As at October 17, 2011 the trailing twelve-month payments to investors, including the October 17, 2011 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $7.5 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Confirms October 17, 2011 Dividend amount

Fri, 16 Sep 2011 14:00:00 -0400

Sep 16, 2011

CALGARY, Sept. 16, 2011 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on October 17, 2011 to shareholders of record on September 30, 2011. The ex-dividend date is September 28, 2011.

As at September 16, 2011 the trailing twelve-month payments to investors, including the September 15, 2011 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $7.2 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. - Webcast from Peters & Co. 2011 North American Oil & Gas Conference - September 13, 2011

Mon, 12 Sep 2011 06:30:00 -0400

Sep 12, 2011

CALGARY, Sept. 12, 2011 /CNW/ - Notification of Peters & Co. 2011 North American Oil & Gas Conference event webcast:

ARC Resources Ltd. (TSX: ARX.)
Peters & Co. 2011 North American Oil & Gas Conference Webcast
September 13, 2011, 8:00 AM ET

To listen to this event, please enter http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=3644740 in your web browser.

For a complete program of the September 13th Conference webcasts please visit http://www.newswire.ca/webcast/pages/peters20110913/ or CNW's webcast events calendar at http://www.newswire.ca/en/webcast/index.cgi.

ARC Resources Ltd. Confirms September 15, 2011 Dividend Amount

Tue, 16 Aug 2011 09:39:00 -0400

Aug 16, 2011

CALGARY, Aug. 16, 2011 /CNW/ - (TSX: ARX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on September 15, 2011 to shareholders of record on August 31, 2011. The ex-dividend date is August 29, 2011.

As at August 16, 2011 the trailing twelve-month payments to investors, including the August 15, 2011 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Reports Second Quarter 2011 Results

Wed, 03 Aug 2011 19:41:00 -0400

Aug 3, 2011

CALGARY, Aug. 3, 2011 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") is pleased to report its second quarter operating and financial results. Second quarter production was 82,367 boe per day, funds from operations were $210.1 million ($0.73 per share) and net income was $150.1 million ($0.52 per share). The related unaudited Condensed Consolidated Financial Statements and Notes, as well as Management's Discussion and Analysis ("MD&A"), are available on ARC's website at www.arcresources.com and on SEDAR at www.sedar.com.

		Three Months Ended June 30		Six Months Ended June 30
		2011	2010 ⁽¹⁾	2011	2010 ⁽¹⁾
FINANCIAL
(Cdn$ millions, except per share and per boe amounts)
Funds from operations⁽²⁾		210.1	150.9	404.2	318.8
	Per share⁽³⁾	0.73	0.60	1.42	1.26
Net income		150.1	58.8	215.3	208.6
	Per share⁽³⁾	0.52	0.23	0.75	0.83
Operating income⁽⁴⁾		76.4	62.7	149.2	142.5
	Per share⁽³⁾	0.27	0.25	0.52	0.56
Dividends		85.8	75.3	171.4	150.3
	Per share⁽³⁾	0.30	0.30	0.60	0.60
Capital expenditures		144.5	144.0	301.7	272.3
Net debt outstanding⁽⁵⁾		744.8	728.8	744.8	728.8
Shares outstanding, weighted average and diluted⁽⁶⁾		286.0	253.2	285.4	252.5
Shares outstanding, end of period		286.5	253.6	286.5	253.6
OPERATING
Production
	Crude oil (bbl/d)	26,038	27,354	27,067	27,496
	Condensate (bbl/d)	2,105	1,325	1,989	1,286
	Natural gas (mmcf/d)	311.8	211.2	279.3	214.5
	Natural gas liquids (bbl/d)	2,250	2,330	2,540	2,169
	Total (boe/d)⁽⁷⁾	82,367	66,208	78,147	66,705
Average prices
	Crude oil ($/bbl)	97.11	71.98	89.45	74.12
	Condensate ($/bbl)	100.57	78.33	94.85	79.14
	Natural gas ($/mcf)	4.05	4.12	4.05	4.78
	Natural gas liquids ($/bbl)	48.40	38.62	45.86	42.99
	Oil equivalent ($/boe)	49.94	45.82	49.38	48.84
Operating netback ($/boe)
	Commodity and other sales	50.02	45.93	49.46	48.93
	Transportation costs	(1.25)	(1.28)	(1.18)	(1.14)
	Royalties	(7.40)	(7.89)	(7.13)	(8.24)
	Operating costs	(9.22)	(11.46)	(9.64)	(10.38)
	Netback before hedging	32.15	25.30	31.51	29.17
	Hedging gain (loss)⁽⁸⁾	0.44	3.08	1.06	1.53
	Netback after hedging	32.59	28.38	32.57	30.70
TRADING STATISTICS⁽⁹⁾
High price		26.79	22.33	28.40	22.49
Low price		23.89	19.20	23.89	19.20
Close price		25.01	19.73	25.01	19.73
Average daily volume (thousands)		998	1,043	1,314	1,164

(1)	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 six months ended June 30, 2011 under IFRS and has restated its unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2010 to comply with IFRS. See Note 16, "Explanation of Transition to International Financial Reporting Standards" in the unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011 for information on ARC's transition to IFRS and a reconciliation of its affected financial information.
(2)	Funds from operations is not a recognized performance measure under Generally Accepted Accounting Principles ("GAAP") and does not have a standardized meaning prescribed by GAAP. Historically, management disclosed cash flow from operating activities. Funds from operations has been presented herein for comparative purposes. See the "Non-GAAP Measures" section in the MD&A for the three and six months ended June 30, 2011 and 2010 for a reconciliation of net income to funds from operations.
(3)	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.
(4)	Operating income is a non-GAAP measure, which adjusts net income for significant items that are not indicative of operating performance and that management believes reduces the comparability of the financial performance between periods. See "Operating Income" section in this news release for a reconciliation of operating income to net income for the three and six months ended June 30, 2011.
(5)	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 prior production periods. Working capital deficit is calculated as current liabilities less the current assets as they appear on the 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.
(6)	Based on weighted average shares plus the dilutive impact of share options outstanding during the period. See Note 12 "Shareholders' Capital" in the unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011.
(7)	Boe may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion ratio of 6 Mcf : 1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(8)	Includes cash gains (losses) on risk management contracts and unrealized losses on annually settled call contracts relating to prior production periods.
(9)	Trading prices are stated in Canadian dollars and based on intra-day trading.

FINANCIAL AND OPERATIONAL HIGHLIGHTS

Production volumes for the second quarter were 82,367 boe per day, up 11 per cent relative to the first quarter of 2011, despite operational challenges posed by the flooding in southern Saskatchewan and Manitoba and forest fires and pipeline restrictions in northern Alberta. High oil prices throughout the quarter had a positive impact on operating income, net income and funds from operations. ARC maintained a strong financial position with debt levels reduced from year-end 2010 levels. To capitalize on the near-term strength of oil prices, ARC accelerated certain crude oil and liquids projects in its 2011 capital program while continuing to develop its natural gas prospects in the Montney play in northern British Columbia.

ARC's second quarter production was 82,367 boe per day, an 11 per cent increase relative to the first quarter of 2011 and 24 per cent higher than the second quarter of 2010. Higher second quarter production at Dawson was partially offset by production downtime attributed to flooding, forest fires, pipeline restrictions and a third party plant turnaround, which contributed to a combined production loss of approximately 4,300 boe per day during the second quarter. Second quarter production was reduced by approximately 6 mmcf per day (1,000 boe per day) as a result of the Dawson Phase 1 gas plant operating at reduced capacity for approximately three weeks in April due to mechanical issues that were resolved in the quarter. Flooding in southern Saskatchewan and Manitoba and forest fires and pipeline restrictions in northern Alberta reduced second quarter production by approximately 2,600 boe per day. Shut-in production was predominantly oil production and the most significant impact was in southeast Saskatchewan and Manitoba. With the exception of approximately 200 boe per day in southeast Saskatchewan, all shut-in production in flood areas was back on-stream by the end of the second quarter. Approximately 350 boe per day of production in northern Alberta remains shut-in due to pipeline restrictions. First half 2011 production averaged 78,147 boe per day, a 17 per cent increase from the first half of 2010. ARC expects full year 2011 production volumes to average 80,000 - 85,000 boe per day with exit production of approximately 90,000 boe per day.
The Dawson Phase 2 gas plant came on-stream at full capacity of 60 mmcf per day in April and operational issues impacting the Dawson Phase 1 gas plant were resolved in the quarter. Total Dawson production, including third party processed gas, averaged 149 mmcf per day in the second quarter, up 103 per cent from 73 mmcf per day in the first quarter. Current production from Dawson is approximately 165 mmcf per day, with all facilities operating at planned capacity.
Funds from operations of $210.1 million ($0.73 per share) in the second quarter of 2011 were up 39 per cent from $150.9 million ($0.60 per share) in the second quarter of 2010. First half 2011 funds from operations of $404.2 million ($1.42 per share) were up 27 per cent relative to the same period of 2010. Higher production volumes and crude oil prices were partially offset by lower natural gas prices and increased total royalties, transportation and operating costs in the second quarter and first half of 2011.
Net income was $150.1 million ($0.52 per share) in the second quarter of 2011, up significantly from $58.8 million ($0.23 per share) in the second quarter of 2010. The increase was mainly due to an unrealized gain on risk management contracts of $74 million ($55.5 million net of tax) in the second quarter of 2011 relative to an unrealized gain of $6.6 million ($5 million net of tax) in 2010. Net income for the first six months of 2011 was $215.3 million ($0.75 per share), a three per cent increase from 2010 as higher sales on increased production and prices in 2011 were partially offset by unrealized losses on risk management contracts.
Operating incomewas $76.4 million ($0.27 per share) in the second quarter of 2011, a 22 per cent increase from operating income of $62.7 million ($0.25 per share) in the second quarter of 2010. First half 2011 operating incomewas $149.2 million ($0.52 per share), up five per cent from 2010. The increase in operating income was due to higher volumes and increased crude oil prices, offset by lower natural gas prices and increases in total royalties, transportation, operating and general and administrative costs associated with higher production in 2011.
ARC's total realized price was $49.94 per boe in the second quarter of 2011, up nine per cent from the $45.82 per boe realized in the second quarter of 2010. ARC's second quarter 2011 crude oil price of $97.11 per barrel increased 35 per cent relative to 2010. Natural gas prices, still depressed by high inventory levels and increased natural gas production in the United States, were down two per cent relative to 2010 levels to average $4.05 per mcf. While crude oil and liquids accounted for 37 per cent of second quarter production, they contributed 69 per cent of second quarter sales revenue due to strong crude oil prices.
ARC realized cash hedging gains of $25.5 million in the second quarter, primarily associated with the hedging of natural gas. The second quarter cash hedging gains were offset by a $21.3 million unrealized loss on crude oil annually settled call contracts to arrive at net hedging gains of $4.2 million ($0.56 per boe) in the quarter. First half cash hedging gains of $51.3 million were offset by a $33.3 million unrealized loss on crude oil annually settled call contracts to arrive at net hedging gains of $18 million ($1.27 per boe). The second quarter unrealized mark-to-market ("MTM") hedging gain of $74 million was mainly attributed to a reduction in average forward prices for crude oil relative to the first quarter of 2011. ARC has protected the price on 20,000 barrels per day in 2011 and 18,000 barrels per day in 2012 at an average price of US$91 per barrel. Approximately 55 per cent of expected 2011 total production is currently hedged with additional volumes hedged for 2012 and 2013.
Capital expenditures for the second quarter totaled $144.5 million. On a year-to-date basis, capital expenditures are $301.7 million. ARC drilled 11 gross operated oil wells and 13 gross operated natural gas wells with a 100 per cent success rate during the second quarter, bringing total wells drilled to 44 gross operated oil wells and 23 gross operated natural gas wells with a 100 per cent success rate for the first half of 2011. Year-to-date capital spending includes $44.8 million for unbudgeted purchases of predominately oil-prone lands in and around our core areas. Restricted access in areas affected by floods and forest fires resulted in delays in the execution of capital programs in the second quarter; however ARC anticipates that all programs will be back on schedule during the second half of 2011.
ARC's Board approved an increase in the 2011 capital budget to $690 million. The higher budget allows ARC to execute all original capital plans for 2011 and invest in new growth opportunities. Approximately $50 million of the increased capital budget is allocated to land purchases of which $44.8 million was spent in the first half of 2011. A portion of the increased 2011 capital budget will be allocated to the purchase of long lead-time equipment and materials for the Phase 1 Sunrise gas plant. ARC received regulatory approval for the construction of the Phase 1 Sunrise gas plant in the second quarter of 2011 and currently expects to have it on-line in the first half of 2013. The 2011 capital expenditure budget continues to focus on oil and liquids rich opportunities at Ante Creek, Pembina and Parkland and supports paced development of the Montney natural gas opportunities in northeast British Columbia along with exploitation of new areas to assess future development potential.
ARC has a strong balance sheet with a net debt to annualized first half funds from operations ratio of 0.9 times, with net debt representing approximately nine per cent of ARC's total capitalization; both well within ARC's target levels.
ARC declared and paid a dividend of $0.30 per share to shareholders for the second quarter of 2011 and has confirmed a dividend of $0.10 per share to shareholders for July 2011 to be paid on August 15, 2011. ARC has conditionally declared a dividend of $0.10 per share, payable monthly, for August, September and October of 2011 subject to confirmation by monthly news release and further resolution of the Board of Directors.

LEADERSHIP TEAM APPOINTMENTS

ARC is pleased to announce the following promotions:

Terry Anderson has been promoted to Senior Vice President, Engineering. Terry started with ARC in 2000 as an Operations Engineer, progressed to Manager of Operations and was promoted to Vice President Operations in 2005. In May 2010, Terry took on responsibility as Vice President Engineering. During his time with ARC, Terry has worked on almost all of ARC's assets.

Van Dafoe has been promoted to Senior Vice President, Finance. Van joined ARC in 1999 and has 25 years of business experience with various companies in the finance and accounting areas of the oil and gas industry. At ARC, he has held the positions of Controller, Treasurer and Vice President, Finance.

Wayne Lentz has been appointed Vice President, Strategic Planning. Wayne joined ARC 12 years ago starting out as a Senior Operations Engineer and has taken on various assignments of increasing responsibility over the years, most recently as Manager, Strategic Planning.

Jay Billesberger has been appointed Vice President, Information Technology. In his new role, Jay will be responsible for leading the information and data integrity for all systems within ARC. Jay joined ARC in 2000 and over the years he has been instrumental in creating a strong information technology platform at ARC.

FINANCIAL REVIEW

ARC had a solid second quarter with higher production and higher sales on the strength of crude oil prices, which partially mitigated the effect of continued low natural gas prices. ARC exited the quarter with lower debt levels relative to year-end 2010 due to strong first half funds from operations and the receipt of $170 million of proceeds from the sale of properties in the first quarter. ARC maintained a dividend of $0.30 per share in the second quarter.

Funds from operations

ARC's second quarter funds from operations of $210.1 million ($0.73 per share) were up 39 per cent compared to the second quarter of 2010 funds from operations of $150.9 million ($0.60 per share). Second quarter sales increased 35 per cent due to a 24 per cent increase in second quarter production and a nine per cent increase in realized price relative to 2010. Higher total royalties, operating costs and transportation costs on higher second quarter volumes reduced the gains in production volumes and commodity prices.

First half 2011 funds from operations of $404.2 million ($1.42 per share) were up 27 per cent compared to the first half of 2010 funds from operations of $318.8 million ($1.26 per share). The increase in first half funds from operations was due to higher production and realized prices offset by higher royalties, operating costs and transportation costs.

Second quarter and first half 2011 funds from operations were reduced by $21.3 million and $33.3 million, respectively, for unrealized losses on crude oil annually settled call contracts pertaining to contracted volumes in the second quarter and first half of 2011.

Following is a reconciliation of net income to funds from operations for the second quarter and first half of 2011 and 2010.


		Three Months Ended June 30		Six Months Ended June 30
		2011	2010	2011	2010
Net income		150.1	58.8	215.3	208.6
Adjusted for the following non-cash items:
	Depletion, depreciation and amortization	106.2	85.1	172.2	170.1
	Accretion of asset retirement obligation	3.3	3.0	6.8	6.0
	Deferred tax expense (recovery)	48.8	(3.9)	67.9	19.5
	Unrealized (gains) losses on risk management contracts	(73.9)	(6.6)	74.7	(90.3)
	Other	(0.5)	1.5	1.6	3.4
	Foreign exchange (gain) loss on revaluation of debt	(2.6)	13.0	(12.2)	1.5
	Gains on disposals of petroleum and natural gas properties	-	-	(87.9)	-
	Unrealized losses on risk management contracts related to prior production periods ⁽¹⁾	(21.3)	-	(33.3)	-
Funds from operations		210.1	150.9	404.2	318.8
Funds from operations per share		$0.73	$0.60	$1.42	$1.26

(1)

Unrealized losses on crude oil annually settled call contracts pertaining to second quarter and first half contracted volumes. The annually settled call contracts are commodity price risk management contracts, which pertain to production periods spanning the entire calendar year but that are cash settled at the end of the year based on the annual average benchmark crude oil price. The portion of total losses on these contracts that relates to production periods for the three and six months ended June 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 the effect of all contracts used for economic hedging in the period, regardless of the timing of cash settlement.

The following table details the items contributing to the change in funds from operations for the second quarter and first half of 2011 relative to 2010.


		Three Months Ended June 30		Six Months Ended June 30
		$ millions	$ per share	$ millions	$ per share
Funds from operations - 2010		150.9	0.60	318.8	1.26
Volume variance
	Crude oil and liquids	(3.8)	(0.02)	8.5	0.03
	Natural gas	37.7	0.15	56.1	0.22
Price variance
	Crude oil and liquids	66.4	0.26	80.9	0.32
	Natural gas	(2.0)	(0.01)	(36.7)	(0.15)
Realized gains on risk management contracts		6.7	0.03	31.2	0.12
Unrealized losses on risk management contracts related to prior production periods ⁽¹⁾		(21.3)	(0.08)	(33.3)	(0.13)
Royalties		(8.0)	(0.03)	(1.4)	(0.01)
Expenses:
	Operating and transportation	(2.2)	(0.01)	(14.1)	(0.05)
	General and administrative	(11.9)	(0.05)	(5.3)	(0.02)
	Interest	(1.7)	(0.01)	(0.6)	-
	Realized foreign exchange gain	(0.7)	-	0.1	-
Diluted shares		-	(0.10)	-	(0.17)
Funds from operations - 2011		210.1	0.73	404.2	1.42

(1)

Operating Netbacks

ARC's operating netback, before hedging, increased 27 per cent to $32.15 per boe in the second quarter of 2011 compared to $25.30 per boe in the same period of 2010. The increase in pre-hedging netbacks is due to the increase in commodity prices, a significant reduction in per boe operating costs, and slightly lower royalty and transportation costs. After hedging, ARC's second quarter netback was $32.59 per boe, a 15 per cent increase from the same period in 2010. The second quarter 2011 netback includes net gains recorded on ARC's crude oil and natural gas risk management contracts during the quarter of $3.3 million ($0.44 per boe) compared to a net gain of $3.08 per boe recorded for the same period in 2010. ARC's first half 2011 netback after hedging was $32.57 per boe, a six per cent increase from the same period in 2010.

Lower operating costs in 2011 were attributed to the sale of higher cost properties in the first quarter of 2011 along with a higher proportion of low cost natural gas production in 2011 relative to 2010.

The following table details components of operating netbacks for the second quarter and first half of 2011.


Netbacks - Q2	Crude Oil ($/bbl)	Heavy Oil ($/bbl)	Condensate ($/bbl)	Natural Gas ($/mcf)	NGL ($/bbl)	Q2 2011 Total ($/boe)	Q2 2010 Total ($/boe)
Average sales price	97.75	78.59	100.57	4.05	48.40	49.94	45.82
Other	-	-	-	-	-	0.08	0.11
Total sales	97.75	78.59	100.57	4.05	48.40	50.02	45.93
Royalties	(18.17)	(9.20)	(25.57)	(0.22)	(10.95)	(7.40)	(7.89)
Transportation	(0.43)	(2.23)	(0.24)	(0.29)	(0.32)	(1.25)	(1.28)
Operating costs ⁽¹⁾	(14.45)	(12.18)	(7.43)	(1.10)	(12.16)	(9.22)	(11.46)
Netback before hedging	64.70	54.98	67.33	2.44	24.97	32.15	25.30
Hedging gain (loss) ⁽²⁾	(9.62)	-	-	0.89	-	0.44	3.08
Netback after hedging	55.08	54.98	67.33	3.33	24.97	32.59	28.38


Netbacks - YTD	Crude Oil ($/bbl)	Heavy Oil ($/bbl)	Condensate ($/bbl)	Natural Gas ($/mcf)	NGL ($/bbl)	YTD 2011 Total ($/boe)	YTD 2010 Total ($/boe)
Average sales price	90.00	73.41	94.85	4.05	45.86	49.38	48.84
Other	-	-	-	-	-	0.08	0.09
Total sales	90.00	73.41	94.85	4.05	45.86	49.46	48.93
Royalties	(15.64)	(8.36)	(24.74)	(0.22)	(11.61)	(7.13)	(8.24)
Transportation	(0.46)	(1.81)	(0.34)	(0.28)	(0.39)	(1.18)	(1.14)
Operating costs ⁽¹⁾	(15.07)	(14.29)	(7.09)	(1.10)	(10.84)	(9.64)	(10.38)
Netback before hedging	58.83	48.95	62.68	2.45	23.02	31.51	29.17
Hedging gain (loss) ⁽²⁾	(6.99)	-	-	0.95	-	1.06	1.53
Netback after hedging	51.84	48.95	62.68	3.40	23.02	32.57	30.70

(1)

(2)

Hedging gain (loss) includes realized cash gain (loss) on risk management contracts including the settlement amounts for crude oil and natural gas contracts and unrealized loss on risk management contracts relating to prior production periods of $21.3 million and $33.3 million, respectively, for the second quarter and first half of 2011. Foreign exchange, power and interest contracts are excluded from the netback calculation.

Net Income

Net income increased 155 per cent in the second quarter to $150.1 million ($0.52 per share) from $58.8 million ($0.23 per share) in the second quarter of 2010. Second quarter net income included a $74 million unrealized MTM gain on risk management contracts, predominantly attributed to crude oil contracts where the futures price declined at the end of the second quarter relative to the first quarter. This $74 million unrealized MTM gain compared to an unrealized MTM gain of $6.6 million in the second quarter of 2010. Second quarter net income also included an unrealized foreign exchange gain of $2.6 million due to the strengthening of the Canadian dollar and associated revaluation of U.S. denominated debt balances ($13 million unrealized foreign exchange loss in 2010).

First half 2011 net income of $215.3 million ($0.75 per share) was up three per cent from net income of $208.6 ($0.83 per share) million for the first half of 2010. First half 2011 net income included an $87.9 million gain on disposal of producing properties (nil 2010) and an unrealized foreign exchange gain of $12.2 million due to the strengthening of the Canadian dollar and associated revaluation of U.S. denominated debt balances ($1.5 million unrealized loss in 2010).

Operating Income

Operating income increased 22 per cent in the second quarter to $76.4 million ($0.27 per share) from $62.7 million ($0.25 per share) in the second quarter of 2010. Higher sales volumes from the increased production and higher crude oil prices were offset by higher total royalties and depletion expense on the increased second quarter volumes as well as higher general and administrative expense.

First half 2011 operating income increased five per cent relative to the first half of 2010 and was attributed to the same factors as noted for the increase in second quarter operating income offset by higher total operating costs on increased production volumes in 2011.

Following is a summary of operating income for the second quarter and first half of 2011 and 2010.


		Three Months Ended June 30		Six Months Ended June 30
		2011	2010	2011	2010
Net income		150.1	58.8	215.3	208.6
Add (deduct) non-operating items, net of tax:
	Unrealized (gain) loss on risk management contracts relating to future production periods	(55.5)	(5.0)	56.0	(67.7)
	Unrealized loss on risk management contracts relating to prior production periods ⁽¹⁾	(16.0)	-	(25.0)	-
	Unrealized (gain) loss on foreign exchange	(2.0)	9.8	(9.2)	1.1
	(Gains) on disposal of petroleum and natural gas properties	-	-	(65.9)	-
	Recovery on property, plant and equipment	-	-	(21.3)	-
	Unrealized gain on short-term investment	(0.2)	-	(0.7)	-
	(Gain) loss on revaluation of exchangeable shares	-	(0.9)	-	0.5
Operating Income ⁽¹⁾		76.4	62.7	149.2	142.5
Operating Income per share ⁽¹⁾		$0.27	$0.25	$0.52	$0.56

(1)

(2)

Debt Management

ARC's balance sheet remains strong with net debt to total capitalization of nine per cent. At June 30, ARC had total credit capacity of $1.6 billion with $610 million of borrowings, of which $184.3 million was drawn under a credit facility and $425.7 million of private notes were outstanding, leaving $951.2 million of available credit capacity. Approximately 70 per cent of outstanding debt is fixed-rate with a weighted average remaining term of 5.7 years.

Strong funds from operations in the first half of 2011 along with proceeds of $170 million received from the sale of properties in the first quarter of 2011 resulted in a reduction of debt levels relative to year-end 2010. ARC's net debt to annualized funds from operations was 0.9 times, well below ARC's targeted limit of two times. Net debt to capitalization of nine per cent was also well below ARC's targeted limit of 20 per cent.

ARC expects to finance its 2011 capital program with funds from operations, proceeds from the Dividend Re-investment Plan ("DRIP"), proceeds from asset divestitures, and existing credit capacity.

Risk Management

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

Given the significant contribution of ARC's crude oil and natural gas liquids production to total sales and funds from operations, ARC management recognizes the risk associated with an unanticipated reduction in crude oil pricing. Accordingly, approximately 61 per cent and 51 per cent of ARC's total crude oil and liquids production for the balance of 2011 and 2012, respectively, has been hedged through the use of a variety of crude oil risk management contracts.

During the second quarter of 2011, ARC realized a cash gain of $25.5 million, primarily attributed to natural gas swap contracts on approximately 52 per cent of second quarter natural gas production hedged at an average of Cdn$5.35 per mcf. For the first half of 2011, ARC realized a cash gain of $51.3 million primarily attributed to natural gas contracts. The second quarter and first half cash hedging gains were offset by $21.3 million and $33.3 million, respectively, for unrealized losses on crude oil annually settled call contracts relating to second quarter and first half contracted volumes. Unlike the majority of ARC's risk management contracts that are settled monthly, these annually settled call contracts, which relate to production throughout 2011, will be cash-settled in their entirety in January 2012.

An unrealized MTM gain of $74 million was recorded in the second quarter due primarily to a reduction in crude oil and natural gas forward prices relative to the previous quarter. Average crude oil forward prices for 2011 and 2012 of US$96.90 and US$100.04, respectively, currently exceed ARC's average ceiling prices of US$89.46 and US$91.39, respectively. Average AECO natural gas forward prices of Cdn$3.88 per mcf and Cdn$4.14 per mcf for 2011 and 2012, respectively, are lower than ARC's average floor prices of Cdn$5.13 per mcf and Cdn$4.28 per mcf. At June 30, ARC's total MTM position on crude oil and natural gas hedge contracts was a loss of $50.1 million compared to a loss of $130 million at March 31, 2011. The actual future cash settlements under the commodity hedge contracts will differ from the current unrealized MTM value with changes in commodity prices in future periods.

Average floor prices on hedged volumes for 2011 through 2012 provide a level of certainty to ARC's ability to execute its business plan over the next two years. ARC has partially mitigated the weak outlook for natural gas prices by protecting the selling price on 206 mmcf per day of natural gas production at Cdn$5.13 per mcf for the remainder of 2011. On the liquids side, ARC has protected 20,000 barrels of crude oil per day at an average floor price of US$84.46 per barrel and an average ceiling price of US$89.46 per barrel for the remainder of 2011. ARC currently has hedged 53 per cent, 33 per cent, and two per cent of total production for 2011, 2012 and 2013, respectively, as summarized in the table below. For a complete listing of ARC's hedging contracts, see Note 11 "Risk Management Contracts" in the unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011.


Hedge Positions Summary ⁽¹⁾ As at June 30, 2011	July - December 2011		2012		2013
Crude Oil ⁽²⁾	US$/bbl	bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day
Sold Call	89.46	20,000	91.39	18,000	110.00	2,000
*Bought Put*	84.46	20,000	91.39	18,000	90.00	2,000
Sold Put	61.09	12,000	60.00	5,000	-	-
Natural Gas ⁽³⁾	Cdn$/mcf	mcf/day	Cdn$/mcf	mcf/day	Cdn$/mcf	mcf/day
Sold Call	5.45	161,352	4.28	76,680	-	-
*Bought Put*	5.13	205,755	4.28	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. Calls have been sold against either the monthly average or the annual average WTI price. For annual sold calls, volumes are based on full year and 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.
(3)	The natural gas price shown translates all NYMEX positions to an AECO equivalent price based on offsetting basis positions and the period end exchange rate. The equivalent hedged NYMEX price would be approximately a floor of $5.86 per mmbtu and a ceiling of $6.19 per mmbtu for 2011. ARC has a fixed price of $5.00 per mmbtu for 2012.

OPERATIONAL REVIEW

During the second quarter of 2011 ARC spent $144.5 million on drilling, facilities, optimization and exploration activities and the purchase of crown lands. ARC drilled 24 gross (23 net) operated wells comprising 11 gross (10 net) oil wells and 13 gross (13 net) natural gas wells with a 100 per cent success rate, bringing total wells drilled for the first half of 2011 to 44 gross (40 net) oil wells and 23 gross (22 net) natural gas wells with a 100 per cent success rate. Oil and liquids-rich natural gas wells represented 85 per cent of total wells drilled in the first half of 2011, reflecting ARC's strategy to capitalize on the strength of oil prices through acceleration of oil and liquids projects in 2011.

Second quarter production of 82,367 boe per day, consisting of 63 per cent natural gas and 37 per cent crude oil and liquids, was up 11 per cent relative to the first quarter of 2011. Higher second quarter production was due primarily to the Dawson Phase 2 gas plant coming on-stream at full capacity of 60 mmcf per day in mid-April. Second quarter production was reduced by approximately 6 mmcf per day (1,000 boe per day) as a result of the Dawson Phase 1 gas plant operating at reduced capacity for approximately three weeks in April due to mechanical issues. Adverse weather conditions in southern Saskatchewan, Manitoba along with northern Alberta forest fires and pipeline restrictions resulted in a second quarter production loss of approximately 2,600 boe per day as production, predominantly oil, was shut-in at the affected areas. Also, a third party plant turnaround resulted in a reduction of second quarter production of approximately 1,700 boe per day. The higher percentage of natural gas production in the second quarter was attributed to higher natural gas production at Dawson and lower oil production was attributed to the shut-in of wells due to flooding and fires.

Second quarter capital programs were delayed in areas affected by flooding and fires with the most significant impact in southeastern Saskatchewan and Manitoba and northern Alberta. ARC expects to resume capital programs in the affected areas in the second half of 2011.

Dawson

Production from the Dawson property in the Montney region of northeast British Columbia averaged 149 mmcf per day of natural gas in the second quarter, up 103 per cent from 73 mmcf per day in the first quarter of 2011. The Dawson Phase 2 gas plant commenced full operations at its 60 mmcf per day design capacity in mid-April and the Phase 1 gas plant resumed full capacity operations in late April following tie-in of the Phase 2 plant and repair of a motor that failed at the re-start of the plant. With the completion of the Phase 2 gas plant, ARC's Dawson operated gas plant processing capacity increased to 120 mmcf per day, bringing total capacity to 165 mmcf per day counting 45 mmcf per day of third-party processing capacity. ARC's Dawson production exited the quarter at full capacity of 165 mmcf per day of natural gas.

In the first half of 2011, ARC drilled and completed five horizontal wells and one vertical well at Dawson.

During the second half of 2011, ARC plans to drill 12 operated natural gas wells. ARC forecasts 2011 full year Dawson production to average approximately 140 mmcf per day with an exit production rate of 165 mmcf per day.

West Montney

ARC's West Montney region includes the Sunrise, Septimus and Sundown properties. Second quarter production averaged 6.5 mmcf per day of natural gas from the Sunrise non-operated property. In the first six months of 2011, ARC drilled two horizontal wells. In anticipation of the Phase 1 Sunrise gas plant, ARC drilled a vertical acid gas disposal well during the second quarter of 2011. ARC currently has seven horizontal wells cased and completed at Sunrise waiting on the facility tie-in and one horizontal well at Sundown awaiting completion and tie-in. ARC plans to bring 15 mmcf per day of operated production on-stream through a third party facility by the start of the fourth quarter.

During the second half of 2011, ARC plans to tie-in existing wells to third party facilities. ARC expects to exit 2011 with West Montney production of approximately 22 mmcf per day from the Sunrise property.

Parkland

Parkland is a liquids rich property located just ten kilometers northwest of the Dawson field. Second quarter 2011 production averaged 39.5 mmcf per day of natural gas and 1,000 boe per day of natural gas liquids. Second quarter production of 7,600 boe per day was down four per cent relative to the first quarter of 2011 primarily due to a third party plant turnaround, originally scheduled for the third quarter, which resulted in a production loss of approximately 1,700 boe per day in the second quarter.

ARC drilled six horizontal, liquids rich natural gas wells at Parkland in the second quarter. One horizontal well was drilled into a lower section of the Upper Montney, which ARC believes not to be accessed by existing well bores. The well will be brought on production in the third quarter to determine if there is any interference with other wells. If no interference is observed, development of this portion of the reservoir could require numerous additional locations. To date in 2011, ARC has drilled 10 liquids-rich, natural gas wells (nine horizontal and one vertical) at Parkland, including one horizontal well, which targeted the Upper Montney in the liquids-rich Tower area (north of the main producing pool). Five of the ten wells drilled in 2011 have been completed and the remaining wells will be completed in the third quarter.

Two additional horizontal wells will be drilled and completed in the liquids-rich Tower area by year-end to further evaluate the opportunity.

Attachie

ARC holds a prospective land base of 106 sections in the Attachie property located north and west of Dawson. Currently there are no booked reserves or production at Attachie. ARC's assessment of the block commenced in the first quarter of 2011. ARC completed its first horizontal well at Attachie during the second quarter. Two additional wells, one vertical and one horizontal, were drilled and are awaiting completion, which will commence in the second half of 2011.

The first horizontal well at Attachie achieved a stabilized test production rate of 10 mmcf per day (30 bbls per mmcf of liquids) at a pressure of 9 MPa within a seven day test period. ARC plans to seek contracts to tie-in wells in the Attachie block into third party facilities to help determine the potential of this area for commercial development in the future.

Ante Creek

Second quarter production averaged 7,300 boe per day (42 per cent light crude oil and natural gas liquids, 58 per cent natural gas) at Ante Creek. Successful horizontal, multi-stage completions at Ante Creek average 30 day production rates of 360 boe per day compared to average rates of 100 boe per day for vertical wells. Given the favorable results from horizontal drilling, ARC believes that the Ante Creek property will provide a significant near-term growth opportunity once facility capacity is expanded.

ARC drilled two horizontal oil wells into the Montney formation at Ante Creek during the second quarter. In the first half of 2011, ARC drilled five horizontal Montney oil wells at Ante Creek - four were completed in the first half of 2011 and the remaining well will be completed in the second half.

In response to current capacity constraints, ARC has committed to build a new, 30 mmcf per day gas plant to process solution gas, enabling an increase in liquids production. ARC has completed the engineering and design for the gas plant and has received ERCB approval to construct the plant. The sales pipeline to TCPL has been installed, major equipment has been ordered and pipeline debottlenecking within the field is progressing. The new plant is expected to come on-stream late in the first quarter of 2012. The total cost of the gas plant is expected to be $40 million.

During the second half of 2011, ARC plans to spend $43 million to drill 11 horizontal wells and continue with construction of the gas plant. ARC expects to grow liquids production to approximately 5,000 barrels per day and to increase total production at Ante Creek to approximately 11,000 boe per day over the course of 2012.

Pembina

ARC is the second largest operator in the Pembina area, operating approximately 25 per cent of the Pembina oil field with an average 65 per cent working interest in 166 gross sections (126 net sections). Pembina second quarter production averaged 10,300 boe per day, consisting of approximately 72 per cent light crude oil and liquids and 28 per cent natural gas, an increase of 14 per cent from 9,000 boe per day in the comparable period of 2010. During the second quarter, ARC drilled three gross horizontal wells into the Cardium formation, bringing the total wells drilled in the first six months of 2011 to 14 gross horizontal Cardium wells, 10 of which were completed and on-stream in the first half. ARC is encouraged by results that indicate an initial 30-day production average of 150 barrels of oil per day per well.

ARC is optimistic about the opportunity for increased recovery at Pembina from the application of horizontal drilling and completion technology. Pembina is an extensive area with geological variability, which adds complexity to ARC's efforts to access additional resources using horizontal drilling and completion techniques. ARC will continue to evaluate this field in order to gain a better understanding of where the horizontal completion technology can be most effectively applied.

During the second half of 2011, ARC plans to drill 28 gross horizontal Cardium locations in order to further develop this reservoir. ARC acquired a gas plant during the second quarter to alleviate solution gas handling constraints at Pembina. In addition, extensive work is also planned on waterflood management in order to optimize reservoir recoveries.

Southeast Saskatchewan and Manitoba

Southeast Saskatchewan and Manitoba was the hardest hit area as a result of the flooding in the second quarter, resulting in an approximate 1,200 boe per day production loss in the quarter. ARC had planned to drill 12 wells in southeast Saskatchewan and Manitoba (including four at Goodlands) in the second quarter; however as a result of the flooding none of the wells were drilled. In the first six months of 2011, ARC drilled 15 wells in this area with 12 wells being brought on-stream and eight wells to be completed in the second half of 2011. Two of the Parkman wells brought on-stream had initial production rates of 500 boe per day.

The Goodlands property in Manitoba provides some of the best drilling economics in ARC's portfolio because of the high netback, light crude oil. Second quarter production averaged 930 boe per day of light crude oil, down from 1,400 boe per day in the first quarter of 2011 as a result of shut-in production attributed to flooding and natural decline. Four wells planned at Goodlands for the second quarter were not drilled because of access restrictions.

During the second half of 2011, ARC plans to spend $47 million in this area to drill 36 wells and explore for additional opportunities. ARC is exploring options to contract two additional drilling rigs so as to complete its original full year capital program following delays in the second quarter. The Goodlands battery is running at full capacity and plans are underway to expand oil capacity during the second half of 2011.

DIVIDENDS

ARC paid dividends totaling $0.30 per share for the second quarter of 2011 and $0.60 per share for the first six months of 2011. The Board of Directors has confirmed a dividend of $0.10 per share for July 2011 and has conditionally declared a monthly dividend of $0.10 per share for August, September and October 2011, targeting a total dividend of $0.30 per share for the third quarter of 2011. The dividends have been designated as eligible dividends under the Income Tax Act (Canada) and are payable as follows:


Ex-dividend date	Record date	Payment date	Per share amount
July 27, 2011	July 29, 2011	August 15, 2011	$0.10⁽¹⁾
August 29, 2011	August 31, 2011	September 15, 2011	$0.10⁽²⁾
September 28, 2011	September 30, 2011	October 17, 2011	$0.10⁽²⁾
October 27, 2011	October 31, 2011	November 15, 2011	$0.10⁽²⁾

(1) Confirmed on July 15, 2011.

(2) Conditionally declared, subject to confirmation by news release and further resolution by the Board of Directors.

The declaration of the dividends is conditional upon confirmation by news release and further resolution of the Board of Directors. Dividends are subject to change in accordance with ARC's dividend policy depending on a variety of factors and conditions existing from time-to-time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of solvency tests imposed by the Business Corporations Act (Alberta) for the declaration and payment of dividends.

OUTLOOK

The pillar of ARC's business strategy is "risk-managed value creation". ARC's goal is to transform this value into shareholder returns through regular dividends and, when appropriate, growth in 2011 and beyond. ARC received Board approval to increase its 2011 capital program to $690 million from $625 million. Approximately $50 million of the increased 2011 capital is allocated to land acquisitions in oil prone areas in and around ARC's existing operations. Additional 2011 capital will be allocated to the purchase of long lead-time equipment and materials for the Sunrise Phase 1 gas plant for which ARC received regulatory approval in the second quarter and for general service cost increases. ARC's 2011 capital program includes the drilling of 166 gross (148 net) wells on operated properties with horizontal wells accounting for 86 per cent. In addition, ARC expects to participate in the drilling of 83 gross (10 net) non-operated wells in 2011.

ARC has a balanced portfolio of high-quality assets with current production of approximately 60 per cent natural gas and 40 per cent crude oil and natural gas liquids. The mix of liquids and natural gas in ARC's portfolio has enabled ARC to respond to the prolonged, low natural gas price environment effectively by redirecting a portion of capital to oil and liquids projects that generate significant returns and cash flow relative to near-term natural gas projects.

Given the strong outlook for crude oil prices, a significant portion of ARC's 2011 capital program has been allocated to oil and liquids projects, which will account for approximately 84 per cent of operated wells to be drilled in 2011. Ante Creek, Pembina and Goodlands will see significant oil drilling activity in 2011 as well as the construction of a new gas processing facility at Ante Creek to address current capacity constraints. ARC will continue to assess the liquids potential of the Montney at Parkland.

ARC will direct considerable resources and capital on the Montney assets in northeast British Columbia in order to set the stage for long-term growth in this area over the next three to five years. Despite continued low natural gas prices, ARC's Montney natural gas economics support development of this area at current natural gas prices. With the completion of the Phase 2 Dawson gas plant in the second quarter, ARC's processing capacity in Dawson has doubled to 120 mmcf per day. Plans for two 60 mmcf per day gas plants at Sunrise will further expand capacity and production in this area over the next five years.

With the increase in the 2011 capital budget to $690 million, ARC plans to spend approximately $390 million in the second half of the year. ARC believes that full year 2011 volumes may average 80,000 - 85,000 boe per day and exit 2011 production is expected to be approximately 90,000 boe per day. ARC's guidance for full year 2011 general and administrative expense increased slightly in relation to higher compensation costs. Variances from full year guidance at the end of the second quarter are timing related and ARC expects that full year 2011 results will match guidance estimates as the year progresses. All other 2011 full year guidance estimates remain unchanged and are summarized in the following table.


	2011 Guidance	2011 YTD Actual	% Variance
Production (boe/d)	80,000 - 85,000	78,147	(2)
Expenses ($/boe):
Operating	9.40 - 9.70	9.64	-
Transportation	1.10 - 1.20	1.18	-
General and administrative⁽¹⁾	2.50 - 2.70	2.96	10
Interest	1.25 - 1.40	1.34	-
Capital expenditures ($ millions)	690	301.7	-
Diluted shares (millions)⁽²⁾	286	285	-

(1)

Full year 2011 G&A guidance increased from previous guidance of $2.45 - $2.60 per boe. 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 six months ended June 30, 2011 were $2.10 per boe, $0.73 per boe and a $0.13 per boe, respectively.

(2)

Based on weighted average shares plus the dilutive impact of share options outstanding during the period.

On June 6, 2011 the Federal Government reintroduced the budget from March 22, 2011, which included a 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. ARC Resources Ltd.'s oil and natural gas properties are directly owned and operated by ARC Resources General Partnership, which has a January 31 year-end. The Department of Finance has not yet released the legislation to enact this proposal. However, it is expected that the proposal related to the elimination of the partnership deferral will be enacted this year. When the proposal is enacted, ARC expects that it would be taxable in 2012 instead of 2013 as a result of the loss of the deferral on partnership income.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

Effective January 1, 2011 all Canadian publicly accountable enterprises are required to prepare their financial statements in accordance with International Financial Reporting Standards ("IFRS"). ARC has prepared its unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011 under IFRS and has restated its unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2010 to comply with IFRS. For further information on ARC's transition to IFRS and a reconciliation of its affected financial information for the three and six months ended June 30, 2010, please refer to Note 16, "Explanation of Transition to International Financial Reporting Standards" in the unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011 and 2010 filed on SEDAR at www.sedar.com.

Forward-looking Information and Statements

This news release 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 news release contains forward-looking information and statements pertaining to the following: guidance as to the 2011 production, timing of execution of capital programs and plans relating to the construction of gas plants at Sunrise under the heading "Financial and Operational Highlights", various plans, forecasts and estimates as to drilling operations and completions, production estimates, timing of building and completion of gas plants and other operational forecasts under the heading "Operational Review", and all matters including 2011 guidance under the heading "Outlook".

The forward-looking information and statements contained in this news release reflect 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 Funds from operations 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.

ARC Resources Ltd. ("ARC") is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $7.7 billion. ARC expects 2011 oil and gas production to average 80,000 to 85,000 barrels of oil equivalent per day from its properties in western Canada. ARC's Common Shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC Resources Ltd. Confirms August 15, 2011 Dividend Amount

Fri, 15 Jul 2011 12:56:00 -0400

Jul 15, 2011

CALGARY, July 15, 2011 /CNW/ - (TSX: ARX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on August 15, 2011 to shareholders of record on July 29, 2011. The ex-dividend date is July 27, 2011.

As at July 15, 2011 the trailing twelve-month payments to investors, including the July 15, 2011 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer

ARC RESOURCES LTD. ANNOUNCES NEW DIRECTOR APPOINTMENT

Thu, 23 Jun 2011 17:00:00 -0400

Jun 23, 2011

CALGARY, June 23, 2011 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") is pleased to announce the appointment of Mr. Tim Hearn to ARC's board of directors. Mr. Hearn is presently the Chairman of Hearn and Associates and has over 40 years experience in the oil and gas industry with Imperial Oil. During Mr. Hearn's career with Imperial Oil he gained experience in marketing, refining and systems and computer services, prior to serving as the President of Exxon Chemical, Asia Pacific, and then Vice President of Human Resources for Exxon Mobil Corporation. Following his service with Exxon Mobil, he returned to Canada where served as Chairman, President and Chief Executive Officer of Imperial Oil Limited from 2002 until his retirement in 2008.

Mr. Hearn is the immediate past Chairman of the board of directors of the C.D. Howe Institute, a member of the board of directors of the Royal Bank of Canada and Viterra Inc., a past member of the Canadian Council of Chief Executives and serves on a North American Trilateral Commission involving NAFTA and the environment. Mr. Hearn is the current Chair of the board of directors of the Calgary Homeless Foundation. He is also the Chair of the Advisory Board of the Public Policy School and a member of the Dean's Medical School Advisory Board, both at the University of Calgary.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,

Chief Executive Officer

ARC RESOURCES LTD. CONFIRMS JULY 15, 2011 DIVIDEND AMOUNT

Thu, 16 Jun 2011 11:20:00 -0400

Jun 16, 2011

CALGARY, June 16, 2011 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on July 15, 2011 to shareholders of record on June 30, 2011. The ex-dividend date is June 28, 2011.

As at June 16, 2011 the trailing twelve-month payments to investors, including the June 15, 2011 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC's common shares trade on the TSX under the symbol ARX.

ADVISORY - In the interests of providing ARC shareholders and potential investors with information regarding ARC, including management's assessment of ARC's future plans and operations, certain information contained in this document are forward-looking statements within the meaning of the "safe harbour" provisions of the United States Private Securities Litigation Reform Act of 1995 and the Ontario Securities Commission. Forward-looking statements in this document relate to the expected oil and gas production for 2011. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, including those risks and uncertainties contained in ARC Resources Ltd.'s Annual Information Form filed at www.sedar.com, which may cause ARC's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements.

ARC RESOURCES LTD.

John P. Dielwart,

Chief Executive Officer

ARC RESOURCES LTD. REPORTS FIRST QUARTER 2011 RESULTS

Tue, 17 May 2011 18:43:00 -0400

May 17, 2011

CALGARY, May 17 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") is pleased to report its first quarter operating and financial results. First quarter production was 73,880 boe per day, funds from operations were $194.1 million ($0.68 per share) and net income was $65.2 million ($0.23 per share). The related unaudited Condensed Consolidated Financial Statements and Notes, as well as Management's Discussion and Analysis ("MD&A"), are available on ARC's website at www.arcresources.com and on SEDAR at www.sedar.com.

    <<
                                               Three Months Ended
                                                   March 31
                                                2011      2010(1)   % Change
    -------------------------------------------------------------------------
    FINANCIAL
    (Cdn$ millions, except per share
     and per boe amounts)
    Funds from operations(2)                   194.1       167.9          16
      Per share(3)                              0.68        0.67           1
    Net income                                  65.2       149.8         (56)
      Per share(3)                              0.23        0.59         (61)
    Operating income(4)                         81.8        79.2           3
      Per share(3)                              0.29        0.31          (6)
    Dividends                                   85.5        75.0          14
      Per share(3)                              0.30        0.30           -
    Capital expenditures                       157.2       128.3          23
    Net debt outstanding(5)                    731.9       678.3           8
    Shares outstanding, diluted(6)             284.9       251.8          13
    Shares outstanding, end of period          285.4       252.8          13
    OPERATING
    Production
      Crude oil (bbl/d)                       28,108      27,640           2
      Condensate (bbl/d)                       1,872       1,245          50
      Natural gas (mmcf/d)                     246.4       217.9          13
      Natural gas liquids (bbl/d)              2,834       2,006          41
      Total (boe/d)                           73,880      67,207          10
    Average prices
      Crude oil ($/bbl)                        82.27       76.26           8
      Condensate ($/bbl)                       88.34       80.00          10
      Natural gas ($/mcf)                       4.05        5.42         (25)
      Natural gas liquids ($/bbl)              43.83       48.12          (9)
      Oil equivalent ($/boe)                   48.75       51.85          (6)
    Operating netback ($/boe)
      Commodity and other sales                48.83       51.93          (6)
      Transportation costs                     (1.10)      (0.99)         11
      Royalties                                (6.81)      (8.58)        (21)
      Operating costs                         (10.12)      (9.29)          9
      Netback before hedging                   30.80       33.07          (7)
      Realized gain (loss) on risk
       management contracts                     3.58       (0.01)          -
      Netback after hedging                    34.38       33.06           4
    -------------------------------------------------------------------------
    TRADING STATISTICS(7)
    High price                                 28.40       22.49          26
    Low price                                  24.05       19.80          21
    Close price                                26.35       20.50          29
    Average daily volume (thousands)           1,636       1,287          27
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) 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 months ended March 31, 2011 under IFRS and
        has restated its unaudited Condensed Consolidated Financial
        Statements for the three months ended March 31, 2010 to comply with
        IFRS. See Note 16, "Explanation of Transition to International
        Financial Reporting Standards" in the unaudited Condensed
        Consolidated Financial Statements for the three months ended
        March 31, 2011 for information on ARC's transition to IFRS and a
        reconciliation of its affected financial information.
    (2) Funds from operations is not a recognized performance measure under
        Generally Accepted Accounting Principles ("GAAP") and does not have a
        standardized meaning prescribed by GAAP. Historically, management
        disclosed cash flow from operating activities. All references to 2010
        cash flow from operating activities throughout this news release have
        been restated for comparative purposes to reflect funds from
        operations. See the "Non-GAAP Measures" section in the MD&A for the
        three months ended March 31, 2011 and 2010 for a reconciliation of
        net income to funds from operations.
    (3) 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.
    (4) Operating income is a non-GAAP measure that adjusts net income for
        significant items that are not indicative of operating performance
        and that management believes reduces the comparability of the
        financial performance between periods. See "Operating Income" section
        in this news release for a reconciliation of operating income to net
        income.
    (5) Net debt excludes current unrealized amounts pertaining to risk
        management contracts, assets held for sale and asset retirement
        obligations associated with assets held for sale.
    (6) Based on weighted average shares plus the dilutive impact of share
        options outstanding during the period see Note 12 "Shareholders'
        Capital" in the unaudited Condensed Consolidated Financial Statements
        for the three months ended March 31, 2011.
    (7) Trading prices are stated in Canadian dollars and based on intra-day
        trading.
    >>

FINANCIAL AND OPERATIONAL HIGHLIGHTS

High oil prices positively impacted first quarter operating income, net income and funds from operations. ARC exited the quarter with a strong financial position with debt levels reduced from year-end 2010 levels. To capitalize on the near-term strength of oil prices, ARC accelerated certain crude oil and liquids projects in its 2011 capital program and continued to develop its natural gas prospects in the Montney play in northern British Columbia.

    <<
    -   On December 31, 2010, ARC completed its conversion from a trust to a
        dividend paying corporation after receiving security holders' and
        legal and regulatory approval in December 2010. ARC's business
        strategy is unchanged and all officers and directors remain the same.
        The common shares of ARC trade on the Toronto Stock Exchange under
        the symbol ARX.

    -   ARC's first quarter average production of 73,880 boe per day,
        consisting of 44 per cent crude oil and natural gas liquids and 56
        per cent natural gas, was up 10 per cent relative to the first
        quarter of 2010 (crude oil and liquids production was up six per
        cent and natural gas production was up 13 per cent).  First quarter
        volumes were reduced by approximately 3,000 barrels of oil
        equivalent ("boe") per day primarily as a result of the Dawson gas
        plant being completely shut-down for approximately four weeks longer
        than planned and due to adverse winter weather conditions impacting
        certain properties.  The additional Dawson downtime was attributed
        to complex electrical issues and severe winter weather encountered
        during the tie-in of the Phase 2 gas plant (see "Dawson Operational
        Update" news release dated April 20, 2011).  First quarter
        production was down 13 per cent relative to the fourth quarter of
        2010 as a result of the facilities shut-down at Dawson, the
        disposition of 3,400 boe per day during the quarter and adverse
        winter weather conditions impacting operations in certain areas.

    -   Funds from operations of $194.1 million ($0.68 per share) in the
        first quarter of 2011 were up 16 per cent from $167.9 million ($0.67
        per share) in the first quarter of 2010. Higher production volumes,
        crude oil prices and cash gains on risk management contracts were
        partially offset by lower natural gas prices and increased total
        royalties, transportation and operating costs in the quarter.

    -   Net income was $65.2 million ($0.23 per share) in the first quarter
        of 2011, down from $149.8 million ($0.59 per share) in the first
        quarter of 2010. The decrease was largely due to an unrealized loss
        on risk management contracts of $148.6 million ($111.5 million net of
        tax) in the first quarter of 2011 relative to an unrealized gain of
        $83.8 million ($63.5 million net of tax) in 2010. First quarter 2011
        net income included an $87.9 million gain on the sale of properties
        ($65.9 million net of tax).

    -   Operating income was $81.8 million in the first quarter of 2011, a
        marginal increase from the same period of 2010. The increase was due
        to higher first quarter volumes, increased crude oil prices and cash
        gains on risk management contracts, offset by lower natural gas
        prices and increases in total royalties, transportation and operating
        costs in the quarter.

    -   ARC's total realized price was $48.75 per boe in the first quarter of
        2011, down six per cent from the $51.85 per boe realized in the first
        quarter of 2010. ARC's first quarter 2011 crude oil price of $82.27
        per barrel increased eight per cent relative to 2010 prices. Natural
        gas prices, still depressed by high inventory levels and increased
        natural gas production in the United States, were down 25 per cent
        relative to 2010 levels to average $4.05 per mcf. While crude oil and
        liquids accounted for 44 per cent of first quarter production, they
        contributed 72 per cent of first quarter sales due to the strength of
        crude oil prices.

    -   ARC realized cash hedging gains of $25.7 million in the first quarter
        of 2011, primarily associated with the hedging of natural gas. The
        first quarter unrealized mark-to-market ("MTM") hedging loss of
        $148.6 million was mainly attributed to crude oil hedges in which ARC
        has "locked in" the ceiling price on 20,000 barrels per day through
        2011 and 18,000 barrels per day through 2012 at an average price of
        $91 per barrel. Approximately 55 per cent of expected 2011 total
        production is currently hedged with additional volumes hedged for
        2012 and 2013.

    -   Capital expenditures for the first quarter totaled $157.2 million.
        ARC drilled 33 gross operated oil wells and 10 gross operated natural
        gas wells with a 100 per cent success rate. ARC's 2011 capital
        expenditure budget of $625 million focuses on oil and liquids rich
        opportunities at Ante Creek and Pembina in Alberta, Parkland in
        British Columbia and Goodlands in Manitoba and supports paced
        development of the Montney natural gas opportunities in northeast
        British Columbia.

    -   ARC completed construction on the 60 mmcf per day Phase 2 gas plant
        in Dawson early in the second quarter, effectively doubling ARC's
        operated processing capacity to 120 mmcf per day. ARC's Phase 1 gas
        plant returned to normal operations on May 1, after operating at a
        reduced capacity following a motor failure early in the second
        quarter. Including third party processed gas, Dawson production is
        currently approximately 155 mmcf per day and is expected to increase
        to 165 mmcf per day by the end of the second quarter as the
        throughput at the plants increases.

    -   ARC has a strong balance sheet with a net debt to annualized first
        quarter funds from operations ratio of 0.9 times, with net debt
        representing approximately nine per cent of ARC's total
        capitalization.

    -   ARC declared and paid a dividend of $0.30 per share to shareholders
        for the first quarter of 2011 and a dividend of $0.10 per share to
        shareholders for April 2010. ARC has confirmed a dividend of $0.10
        per share to be paid on June 15, 2011 to shareholders of record on
        May 31, 2011, and has conditionally declared a dividend of $0.10 per
        share, payable monthly, for June and July of 2011 subject to
        confirmation by monthly news release and further resolution of the
        Board of Directors.

    -   On January 31, 2011, ARC completed the previously announced
        disposition of approximately 3,400 boe per day and approximately 14.7
        million boe of proved plus probable reserves associated with non-core
        properties in central Alberta for proceeds of $170 million. Proceeds
        from the sale were used to reduce indebtedness. In accordance with
        IFRS, first quarter net income included a $65.9 million gain, net of
        tax, as a result of the disposition.

    -   This spring has seen severe flooding in parts of Saskatchewan and
        Manitoba, and parts of northern Alberta have recently been
        devastated by wildfires.  These events have impacted the lives of
        thousands of Canadians, and ARC's employees and operations have not
        been immune.  At this time, it is very difficult to assess the full
        impact that these events will have on ARC's full year production.
        Currently, approximately 5,000 boe per day of production is shut-in,
        consisting predominately of oil production.  ARC is uncertain when
        electricity will be restored to the affected fields in Alberta and
        when both the areas impacted by wildfires and flooding will be
        accessible to resume normal operations and continue the execution of
        the capital program.  ARC will monitor these situations,
        assess the impact on its full year budget production and will
        provide details in its mid-year review.  Production volumes in 2011
        may average in the 80,000 - 85,000 boe per day range with
        exit production expected to be in excess of 90,000 boe per
        day.
    >>

FINANCIAL REVIEW

ARC had a solid first quarter with higher production and higher sales on the strength of crude oil prices, which partially mitigated the effect of low natural gas prices. ARC exited the quarter with lower debt levels relative to year-end 2010 due to strong funds from operations and the receipt of $170 million of proceeds from the sale of properties in the first quarter. ARC maintained a dividend of $0.30 per share in the first quarter, unchanged from distribution levels prior to the conversion to a corporation.

Funds from operations

ARC's first quarter funds from operations of $194.1 million ($0.68 per share) were up 16 per cent compared to the first quarter of 2010 funds from operations of $167.9 million ($0.67 per share). First quarter sales increased three per cent due to a 10 per cent increase in first quarter production and an eight per cent increase in crude oil pricing, partially offset by a 25 per cent decrease in natural gas prices. Higher total royalties, operating costs and transportation costs attributed to higher first quarter volumes reduced the impact of the gains in volume. Cash gains on risk management contracts of $25.7 million increased first quarter 2011 funds from operations relative to 2010, when cash gains were just $1.3 million.

Following is a reconciliation of net income to funds from operations for the first quarters of 2011 and 2010.

    <<
    -------------------------------------------------------------------------
                                                         Q1 2011     Q1 2010
    -------------------------------------------------------------------------
    Net income                                              65.2       149.8
    Adjusted for the following non-cash items:
      Depletion, depreciation and amortization              66.0        85.0
      Accretion of asset retirement obligation               3.5         3.1
      Deferred tax expense                                  19.1        23.4
      Loss on revaluation on exchangeable shares               -         1.8
      Unrealized (gains) and losses on risk management
       contracts related to future production periods      136.6       (83.7)
      Unrealized (gain) on short-term investment            (0.7)          -
      Non-cash lease inducement                              1.9           -
      Foreign exchange (gain) on revaluation of debt        (9.6)      (11.5)
      (Gains) on disposals of petroleum and natural
        gas properties                                     (87.9)          -
    -------------------------------------------------------------------------
    Funds from operations                                  194.1       167.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    >>

The following table details the items contributing to the change in funds from operations for the first quarter of 2011 relative to 2010.

    <<
    -------------------------------------------------------------------------
                                                      $ millions  $ per share
    -------------------------------------------------------------------------
    Funds from operations - Q1 2010                        167.9        0.67
    -------------------------------------------------------------------------
    Volume variance
      Crude oil and liquids                                 11.3        0.04
      Natural gas                                           13.9        0.06
    Price variance
      Crude oil and liquids                                 15.6        0.06
      Natural gas                                          (30.3)      (0.12)
    Realized gains on risk management contracts             24.5        0.10
    Loss on annual settled risk management contracts(1)    (12.0)      (0.05)
    Royalties                                                6.6        0.03
    Expenses:
     Operating and transportation                          (11.9)      (0.05)
     General and administrative                              6.6        0.03
     Interest                                                1.1           -
     Realized foreign exchange gain                          0.8           -
    Diluted shares                                             -       (0.09)
    -------------------------------------------------------------------------
    Funds from operations - Q1 2011                        194.1        0.68
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents first quarter unrealized MTM loss on annual call contracts
        which cash settle on an annual basis.
    >>

Net Income

Net income decreased 56 per cent in the first quarter to $65.2 million ($0.23 per share) from $149.8 million ($0.59 per share) in 2010. First quarter net income was reduced by a $148.6 million unrealized MTM loss on risk management contracts, predominantly crude oil contracts, compared to an unrealized MTM gain of $83.8 million in the first quarter of 2010. First quarter net income included an $87.9 million gain on disposal of producing properties (nil 2010) and an unrealized foreign exchange gain of $9.6 million ($11.5 million unrealized gain in 2010) due to the strengthening of the Canadian dollar and associated revaluation of U.S. denominated debt balances.

Operating Income

Operating income increased marginally to $81.8 million from $79.2 million in the first quarter of 2010. Higher sales attributed to increased production and crude oil prices were offset by higher total royalties, operating costs and depletion expense on the increased first quarter volumes. Following is a summary of operating income for the first quarters of 2011 and 2010.

    <<
    -------------------------------------------------------------------------
                                                         Q1 2011     Q1 2010
    -------------------------------------------------------------------------
    Net income                                              65.2       149.8
    -------------------------------------------------------------------------
    Add (deduct) non-operating items:
      Unrealized (gain) loss on risk management
       contracts, net of tax                               111.5       (63.0)
      Unrealized (gain) on foreign exchange, net of tax     (7.2)       (8.6)
      (Gains) on disposal of petroleum and natural
        gas properties, net of tax                         (65.9)          -
      Impairments (recovery) on property, plant and
       equipment, net of tax                               (21.3)          -
      Unrealized (gain) on short-term investment,
       net of tax                                           (0.5)          -
      Loss on revaluation of exchangeable shares,
       net of tax                                              -         1.0
    -------------------------------------------------------------------------
    Operating Income(1)                                     81.8        79.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Operating income is not a recognized performance measure under GAAP
        and does not have a standardized meaning prescribed by GAAP. The term
        "operating income" is defined as net income excluding the impact of
        after-tax loss on unrealized gains and losses on risk management
        contracts, after-tax unrealized gains and losses on foreign exchange,
        after-tax gains and losses on short term investments, after-tax gains
        and losses on revaluation of exchangeable shares, after-tax
        impairment (recovery) on property, plant and equipment, after-tax
        gains on disposal of petroleum and natural gas properties and the
        effect of changes in statutory income tax rates. ARC believes that
        adjusting net income for these non-operating items presents a better
        measure of financial performance that is more comparable between
        periods. The most directly comparable measure of operating income
        calculated in accordance with GAAP is net income.
    >>

Debt Management

ARC's balance sheet remains strong with approximately 67 per cent of outstanding debt being fixed-rate with a weighted average remaining term of 5.9 years. At March 31, ARC had total credit facilities of $1.6 billion with $646.7 million of borrowings under the credit facilities, leaving $924.1 million of available credit capacity. Proceeds of $170 million from the sale of non-core properties in Central Alberta along with strong funds from operations in the first quarter resulted in a reduction of debt levels relative to year-end. ARC's net debt to annualized first quarter funds from operations was 0.9 times, well below ARC's targeted limit of two times. Net debt to capitalization of nine per cent was also well below ARC's targeted limit of 20 per cent.

ARC expects to finance its 2011 capital program with funds from operations, proceeds from the Dividend Re-investment Plan ("DRIP") and existing credit capacity.

Risk Management

ARC maintains a risk management program to reduce the volatility of sales, increase the certainty of cash flow and to protect acquisition and development economics. ARC currently limits the amount of total forecast production that can be hedged to a maximum 55 per cent over the next two years with the remaining 45 per cent of production being sold at market prices.

During the first quarter of 2011, ARC realized a cash gain of $25.7 million primarily attributed to natural gas swap contracts on approximately 52 per cent of first quarter natural gas production hedged at Cdn$5.85 per mcf.

An unrealized MTM loss of $148.6 million loss was recorded in the first quarter due to the increase in the loss position on liquids hedge contracts. At March 31, 2010, ARC's liquids hedge contracts were in a loss position of $199 million, based on average 2011 and 2012 WTI crude oil forward pricing estimated at US$107 per barrel relative to the hedged (ceiling) price of approximately US$91 per barrel on contracted volumes. While the unrealized MTM loss had a negative impact on net income in the quarter, the average floor price of approximately US$88 per barrel on hedged volumes for 2011 through 2013 provides a level of certainty for ARC to execute on its business plans over the next two years. Partially offsetting the loss position on crude oil hedge contracts, ARC's natural gas hedge contracts were in a gain position of $69 million at March 31, 2011 based on average 2011 and 2012 natural gas forward pricing estimated at Cdn$4.14 per mcf.

The actual future cash settlements under the commodity hedge contracts will differ from the current unrealized MTM value with changes in commodity prices in future periods. Subsequent to quarter end, average crude oil forward prices decreased to approximately US$100 per barrel for 2011 and 2012 and average natural gas forward prices decreased to approximately Cdn$4.11 per mcf for 2011 and 2012 relative to forward prices at March 31, 2011. Due to the reduction in forward commodity prices subsequent to quarter end, ARC's unrealized MTM position on oil and natural gas contracts decreased from a loss of $130 million at March 31, 2011 to a loss of approximately $60 million at May 16, 2011.

ARC has partially mitigated the weak outlook for natural gas prices by protecting the selling price on 163 mmcf per day of natural gas at Cdn$5.44 per mcf for the remainder of 2011. On the liquids side, ARC has protected 20,000 barrels of crude oil per day at an average floor price of US$84.61 per barrel and an average ceiling price of US$89.61 per barrel for the remainder of 2011. Additional volumes are hedged for 2012 and 2013 as summarized in the following table. For a complete listing of ARC's hedging contracts, see Note 11 "Risk Management Contracts" in the unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011.

    <<
    -------------------------------------------------------------------------
    Hedge Positions
     Summary(1)
    As at             April - December
     March 31, 2011         2011               2012               2013
    -------------------------------------------------------------------------
    Crude Oil(2)      US$/bbl  bbl/day   US$/bbl  bbl/day   US$/bbl  bbl/day
    -------------------------------------------------------------------------
      Sold Call         89.61   20,000     91.39   18,000    110.00    2,000
      Bought Put        84.61   20,000     91.39   18,000     90.00    2,000
      Sold Put          61.27   12,000     60.00    5,000         -        -
    -------------------------------------------------------------------------
    Natural Gas(3)   Cdn$/mcf  mcf/day  Cdn$/mcf  mcf/day  Cdn$/mcf  mcf/day
    -------------------------------------------------------------------------
      Sold Swap          5.44  162,973      4.30   67,978         -        -
    -------------------------------------------------------------------------
    (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.
    (2) For 2011 and 2012, all put positions settle against the monthly
        average WTI price, providing protection against monthly volatility.
        Calls have been sold against either the monthly average or the annual
        average WTI price. For annual sold calls, volumes are based on full
        year and 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.
    (3) The natural gas price shown translates all NYMEX positions to an AECO
        equivalent price based on offsetting basis positions and the period
        end exchange rate. The equivalent hedged NYMEX price would
        approximate $6.12 per mmbtu and $5.00 per mmbtu for 2011 and 2012,
        respectively.
    >>

OPERATIONAL REVIEW

During the first quarter of 2011 ARC spent $157.2 million of capital on drilling, facilities, optimization and exploration activities. ARC drilled 43 gross (39 net) operated wells comprising 33 gross (30 net) oil wells and 10 gross (9 net) natural gas with a 100 per cent success rate. Of the nine net natural gas wells, five of the wells were liquids rich. Oil and liquids-rich natural gas wells represented 90 per cent of total wells drilled - a reflection of ARC's strategy to capitalize on the strength of oil prices through acceleration of oil and liquids projects in 2011.

First quarter production averaged 73,880 boe per day consisting of 56 per cent natural gas and 44 per cent crude oil and liquids. The start-up of the 60 mmcf per day Phase 1 Dawson gas plant in the second quarter of 2010, the acquisition of Storm Exploration Inc. on August 17, 2010 and a successful drilling program all contributed to higher production in the first quarter of 2011 relative to 2010.

First quarter production was down 13 per cent relative to the fourth quarter of 2010 due to the disposition of properties, adverse winter weather conditions impacting certain properties, and downtime at Dawson of 5,000 boe per day to tie-in the Phase 2 Dawson gas plant. The Phase 1 gas plant was down for four weeks longer than planned during the quarter due to complex electrical issues and severe winter weather. The Dawson Phase 1 gas plant was running above design capacity in the fourth quarter, contributing an additional 2,700 boe per day through the fourth quarter. The Dawson Phase 1 gas plant throughput was reduced to design capacity in the first quarter to ensure long-term optimal equipment reliability and performance.

Dawson

Production from the Dawson property in the Montney region of northeast British Columbia averaged 73 mmcf per day of natural gas during the first quarter of 2011, accounting for approximately 16 per cent of total first quarter production. First quarter volumes were impacted by the complete shut-down of the Phase 1 Dawson gas plant for six weeks to tie-in the new Phase 2 gas plant. During the quarter, ARC drilled three horizontal wells at Dawson.

The Phase 2 gas plant commenced full operations at its 60 mmcf per day design capacity in mid-April. With the completion of the Phase 2 gas plant, ARC's Dawson operated gas plant processing capacity increased to 120 mmcf per day, complementing the 45 mmcf per day of third-party processing capacity. ARC expects Dawson production to increase to 165 mmcf per day by the end of the second quarter after throughput is increased at both plants and behind-pipe production is brought on-stream.

During 2011, ARC plans to spend $98 million at Dawson to drill 14 operated wells. ARC forecasts 2011 full year Dawson production to average approximately 145 mmcf per day with a 2011 exit production rate of approximately 165 mmcf per day.

West Montney

ARC's West Montney region includes the Sunrise, Septimus and Sundown properties. First quarter production averaged 6.8 mmcf per day from the Sunrise non-operated property. ARC plans on bringing 15 mmcf per day of operated production on stream through a third party facility by the start of the fourth quarter. ARC currently has five horizontal wells cased and completed at Sunrise waiting on the facility tie-in. During the first quarter, ARC drilled one horizontal well at Sundown.

ARC received approval from the British Columbia Oil and Gas Commission to construct two 60 mmcf per day gas plants at Sunrise. Current plans target the first 60 mmcf per day of capacity to be on stream in 2013. In anticipation of the Sunrise gas plant, a vertical well is being drilled, which will be evaluated for acid gas disposal potential.

During 2011, ARC plans to spend $25 million on the West Montney assets to drill two horizontal wells and one acid gas disposal well. In addition, ARC will complete the tie-in of existing Sunrise wells during the second quarter of 2011.

Parkland

Parkland is a liquids rich property located just ten kilometers east of the Dawson field. First quarter 2011 production averaged 40.5 mmcf per day of natural gas and 1,125 boe per day of natural gas liquids. Production from new wells and added compression in early March increased average volumes at the Parkland field in the first quarter by 300 boe per day relative to fourth quarter 2010 volumes.

ARC drilled four horizontal wells at Parkland during the first quarter. One of the four horizontal wells targeted the Upper Montney in the liquids-rich Tower area (north of the main producing pool) and will be completed in the third quarter. Two more horizontal wells will be drilled in this area by year-end to further delineate the opportunity.

During 2011, ARC plans to spend $67 million on the drilling of 11 horizontal wells. ARC also plans to test a lower interval in the upper Montney A zone as well as complete three horizontal wells to determine the oil and liquids potential of the Tower area.

Attachie

ARC holds a prospective land base of 104 sections in the Attachie property located west of Dawson. Currently there are no booked reserves or production at Attachie. Assessment of the block commenced in the first quarter with two wells being drilled in Attachie during the first quarter. Completion operations will commence in the second half of 2011.

During 2011, ARC intends to continue drilling at Attachie to assess the potential for commercial production.

Ante Creek

Ante Creek production is facility constrained, with first quarter averaging 7,900 boe per day (43 per cent light crude oil and natural gas liquids, 57 per cent natural gas). Successful horizontal multi-stage completions at Ante Creek average 30 day production rates of 360 boe per day compared to average rates of 100 boe per day for vertical wells. Given the favorable results from horizontal drilling, ARC believes that the Ante Creek property will provide a significant near-term growth opportunity once facility capacity is expanded.

During the first quarter ARC drilled three oil wells into the Montney formation at Ante Creek.

In response to current capacity constraints, ARC has committed $30 million of 2011 capital to build a new, 30 mmcf per day gas plant to process solution gas, enabling an increase in liquids production. ARC has completed the engineering and design for the gas plant and has recently received ERCB approval to construct the plan. The sales pipeline to TCPL has been installed, major equipment has been ordered and pipeline debottlenecking within the field is progressing. The new plant is expected to come on-stream late in the first quarter of 2012. The total cost of the gas plant is expected to be $40 million.

During 2011, ARC plans to spend $55 million to drill 14 horizontal and two vertical wells at Ante Creek. ARC expects liquids production to grow to approximately 5,000 barrels per day and total production at Ante Creek to increase to approximately 11,000 boe per day over the course of 2012.

Pembina

ARC is the second largest operator in the Pembina area, operating approximately 25 per cent of the Pembina oil field with an average 65 per cent working interest in 166 gross sections (126 net sections). Pembina first quarter production averaged 10,440 boe per day of light crude oil, an increase of 16 per cent from 9,000 boe per day in the comparable period of 2010. During the first quarter, ARC drilled nine net horizontal wells into the Cardium formation. ARC is encouraged by results that indicate an initial 30-day production average of 150 barrels of oil per day for the six horizontal wells put on production in the first quarter of 2011.

During 2011, ARC plans to spend $90 million to drill 42 horizontal Cardium locations in order to further develop this reservoir. In addition, extensive work is also planned on waterflood management in order to optimize reservoir recoveries.

Goodlands

The Goodlands property in Manitoba provides some of the best drilling economics in ARC's portfolio due to the high netback, light crude oil. First quarter production averaged 1,400 boe per day of light crude oil, significantly higher than first quarter 2010 average production of 879 boe per day, as a result of ARC's robust 2010 drilling program. The Goodlands battery is running at full capacity and plans are being executed to expand oil capacity. During the first quarter, ARC drilled seven net horizontal wells.

During 2011, ARC plans to spend $58 million in southeast Saskatchewan and Manitoba to drill 48 wells and explore for additional opportunities.

DIVIDENDS

ARC paid dividends totaling $0.30 per share for the first quarter of 2011, consistent with distributions levels prior to the conversion to a corporation. A dividend of $0.10 per share was declared and paid for the month of April 2011. The Board of Directors has confirmed a dividend of $0.10 per share for May and has conditionally declared a monthly dividend of $0.10 per share for June and July 2011, targeting a total dividend of $0.30 per share for the second quarter of 2011. The dividends have been designated as eligible dividends under the Income Tax Act (Canada) and are payable as follows:

    <<
    -------------------------------------------------------------------------
    Ex-dividend date      Record date      Payment date    Per share amount
    -------------------------------------------------------------------------
    April 27, 2011     April 29, 2011      May 16, 2011             $0.10
    May 27, 2011         May 31, 2011     June 15, 2011             $0.10(1)
    June 28, 2011       June 30, 2011     July 15, 2011             $0.10(2)
    July 27, 2011       July 29, 2011   August 15, 2011             $0.10(2)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Confirmed on May 16, 2011.
    (2) Conditionally declared, subject to confirmation by news release and
        further resolution by the Board of Directors.
    >>

The declaration of the dividends is conditional upon confirmation by news release and further resolution of the Board of Directors. Dividends are subject to change in accordance with ARC's dividend policy depending on a variety of factors and conditions existing from time-to-time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of solvency tests imposed by the Business Corporations Act (Alberta) for the declaration and payment of dividends.

OUTLOOK

The pillar of ARC's business strategy is "risk-managed value creation". ARC's goal is to transform this value into shareholder returns through regular dividends and, when appropriate, growth in 2011 and beyond. During 2011, ARC will continue to execute its $625 million capital program targeting growth in 2011. Defined projects such as Dawson and Sunrise in the Montney region of British Columbia and Ante Creek in northern Alberta will provide near-term growth. ARC's 2011 capital program includes the drilling of 166 wells on operated properties with horizontal wells accounting for 86 per cent.

Given the strong outlook for crude oil prices, a significant portion of ARC's 2011 capital program has been allocated to oil and liquids projects with oil and liquids wells accounting for approximately 87 per cent of operated wells to be drilled in 2011 and representing approximately 45 per cent of the $625 million 2011 capital program. Ante Creek, Pembina and Goodlands will see significant oil drilling activity in 2011 as well as the construction of a new gas processing facility at Ante Creek to address current capacity constraints. ARC will continue to assess the liquids potential in the northern region of the Montney at Parkland.

ARC will direct considerable resources and capital on the Montney in northeast British Columbia in order to set the stage for long-term growth in this area over the next three to five years. Despite continued low natural gas prices, ARC's Montney natural gas economics still support development of this area at current natural gas prices. With the recent completion of the Phase 2 gas plant, ARC's processing capacity in Dawson has doubled to 120 mmcf per day.

Severe flooding in parts of Saskatchewan and Manitoba and devastating wildfires in northern Alberta are currently having an impact on ARC's operations in the affected areas. At the present time, approximately 5,000 boe per day, predominantly oil production, is shut-in. ARC is uncertain when electricity will be restored and when the fields will be accessible to resume normal operations and continue the execution of the capital program in the affected locations. ARC will continue to monitor these situations, assess the impact on its full year, budgeted production and will provide details in its mid-year review. ARC believes that full year 2011 volumes may average in the 80,000 - 85,000 boe per day range, a reduction from previous guidance of 84,000 - 87,000 boe per day. Exit 2011 production is expected to be in excess of 90,000 boe per day, a reduction from previous exit guidance of 93,000 boe per day, due to the timing of certain projects in 2011. Variances from full year guidance at the end of the first quarter are timing related and ARC expects that full year 2011 results will match guidance estimates as the year progresses. All other 2011 full year guidance estimates remain unchanged and are summarized in the following table.

    <<
    -------------------------------------------------------------------------
                                 2011 Guidance   Q1 2011 Actual   % Variance
    -------------------------------------------------------------------------
    Production (boe/d)         80,000 - 85,000           73,880          (10)
    Expenses ($/boe):
      Operating                    9.40 - 9.70            10.12           (6)
      Transportation               1.10 - 1.20             1.10            4
      General and
       administrative(1)           2.45 - 2.60             2.48            2
      Interest                     1.25 - 1.40             1.49          (13)
    Capital expenditures
     ($ millions)                          625              157            -
    Diluted shares
     (millions)(2)                         286              285            -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The 2011 annual Guidance for general and administrative cost per boe
        is based on a range of $1.65 - $1.70 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 $0.20-$0.25 per boe associated with accrued compensation
        under ARC's long term incentive plan. Actual per boe costs for each
        of these components for the three months ended March 31, 2011 were
        $2.37 per boe, $1.53 per boe and a recovery of $(1.42) per boe,
        respectively.
    (2) Based on weighted average shares plus the dilutive impact of share
        options outstanding during the period.
    >>

On March 22, 2011 the Federal Government presented a budget, which included a 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. ARC Resources Ltd.'s oil and natural gas properties are directly owned and operated by ARC Resources General Partnership, which has a January 31 year-end. These proposals were not enacted but are expected to be reintroduced in the next federal budget. If these proposals are enacted, ARC currently expects that it would be taxable in 2012 instead of 2013 as a result of the loss of the deferral on partnership income.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

Effective January 1, 2011 all Canadian publicly accountable enterprises are required to prepare their financial statements in accordance with International Financial Reporting Standards ("IFRS"). ARC has prepared its unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011 under IFRS and has restated its unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2010 to comply with IFRS. For further information on ARC's transition to IFRS and a reconciliation of its affected financial information for the three months ended March 31, 2010, please refer to Note 16, "Explanation of Transition to International Financial Reporting Standards" in the unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011 and 2010 filed on SEDAR at www.sedar.com.

Forward-looking Information and Statements

This news release 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 news release contains forward-looking information and statements pertaining to the following: all of the matters under the heading "Outlook" which contains guidance for 2011, the expectations related to the transition from Canadian GAAP to IFRS under the heading "International Financial Reporting Standards", and a number of other matters, including future liquidity and financial capacity under the heading "Debt Management"; 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 under the heading "Operational Review".

ARC Resources Ltd. ("ARC") is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC expects 2011 oil and gas production to average 80,000 to 85,000 barrels of oil equivalent per day from six core areas in western Canada. ARC's Common Shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

    <<
    John P. Dielwart,
    Chief Executive Officer
    >>

ARC RESOURCES LTD. CONFIRMS JUNE 15, 2011 DIVIDEND AMOUNT

Mon, 16 May 2011 15:35:00 -0400

May 16, 2011

CALGARY, May 16 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") confirms that a dividend of $0.10 per share designated as an eligible dividend will be paid on June 15, 2011 to shareholders of record on May 31, 2011. The ex-dividend date is May 27, 2011.

As at May 16, 2011 the trailing twelve-month payments to investors, including the May 16, 2011 payment, total $1.20 per share.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC's common shares trade on the TSX under the symbol ARX.

ADVISORY - In the interests of providing ARC shareholders and potential investors with information regarding ARC, including management's assessment of ARC's future plans and operations, certain information contained in this document are forward-looking statements within the meaning of the "safe harbour" provisions of the United States Private Securities Litigation Reform Act of 1995 and the Ontario Securities Commission. Forward-looking statements in this document relate to the expected oil and gas production for 2011. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, including those risks and uncertainties contained in ARC Energy Trust's Annual Information Form filed at www.sedar.com, which may cause ARC's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements.

ARC RESOURCES LTD.

John P. Dielwart,

Chief Executive Officer

ARC Resources Ltd. - Annual General Meeting Webcast - May 18, 2011

Mon, 16 May 2011 08:00:00 -0400

May 16, 2011

CALGARY, May 16 /CNW/ - (TSX: ARX) Notification of Annual General Meeting Webcast:

ARC Resources Ltd.
Annual General Meeting Webcast
May 18, 2011, 5:30 PM ET

To listen to this event, please enter http://w.on24.com/r.htm?e=304225&s=1&k=6022BCB0B7A29E107A62B2CD86C95907 in your web browser.

For a complete listing of upcoming and archived webcasts available through CNW Group, please visit our events calendar at http://www.newswire.ca/en/webcast/index.cgi.

ARC RESOURCES LTD. - DAWSON OPERATIONAL UPDATE

Wed, 20 Apr 2011 17:05:00 -0400

Apr 20, 2011

CALGARY, April 20 /CNW/ - (TSX: ARX) ARC Resources Ltd. announced today that the Dawson Phase 2 gas plant expansion has been completed and that the plant is now operating at its 60 mmcf per day design capacity. Phase 2 construction was completed on budget and on schedule. A planned shut-down of the Dawson Phase 1 gas plant was carried out in the first quarter of 2011 to integrate the new Phase 2 gas plant. Due to several complex electrical issues and severe winter weather, the plant was completely shut down for approximately four weeks longer than planned resulting in first quarter volumes being down by approximately 3,000 barrels of oil equivalent ("boe") per day.

Production for the first quarter of 2011 averaged 73,880 boe per day (29,980 barrels per day of oil and condensate, 2,834 barrels per day of NGLs and 246 mmcf per day of natural gas).

Early in the second quarter a part failed in a 3750 horsepower motor in the Phase 1 plant. This part is under warranty and the failure was unusual so no spare parts were available. As of this date, the Phase 2 plant is operating normally and the Phase 1 plant is operating at 50 per cent of capacity. Production from the Phase 1 gas plant will be approximately 30 mmcf per day until motor repairs are completed. Current corporate production is approximately 84,000 boe per day, with Dawson production in the range of 135 mmcf per day (90 mmcf per day through our own facilities and 45 mmcf per day through a third-party gas plant).

We expect to resume normal operation of the Phase 1 gas plant upon receipt of warranted parts from Asia. Our best estimate for the Phase 1 plant to operate at normal capacity is in mid-May, with expected production of 120 mmcf per day of natural gas being processed through both Phase 1 and 2 plants. We believe we will exit fourth quarter 2011 with production of approximately 93,000 boe per day.

ARC is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC's common shares trade on the TSX under the symbol ARX.

ARC RESOURCES LTD.

John P. Dielwart,

Chief Executive Officer

Note: Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion ratio for natural gas of 6 mcf:1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

ADVISORY - In the interests of providing ARC shareholders and potential investors with information regarding ARC, including management's assessment of ARC's future plans and operations, certain information contained in this document are forward-looking statements within the meaning of the "safe harbour" provisions of the United States Private Securities Litigation Reform Act of 1995 and the Ontario Securities Commission. Forward-looking statements in this document relate to the expected oil and gas production for the first half of 2011, which is dependent upon estimated delivery times from Asia of warranted parts, which estimates are based upon currently available information. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, including those risks and uncertainties contained in ARC Energy Trust's Annual Information Form filed at www.sedar.com, which may cause ARC's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements.