Arc Resources (AETUF) 6-K Current report (foreign)

MANAGEMENT’S DISCUSSION AND ANALYSIS

This management’s discussion and analysis (“MD&A”) of ARC Resources Ltd. (“ARC” or the “Company”) is Management’s analysis of the financial performance and significant trends or external factors that may affect future performance. It is dated November 4, 2015 and should be read in conjunction with the unaudited condensed interim consolidated financial statements (the "financial statements") as at and for the three and nine months ended September 30, 2015, and the MD&A and audited consolidated financial statements as at and for the year ended December 31, 2014, as well as ARC’s Annual Information Form that is filed on SEDAR at www.sedar.com. All financial information is reported in Canadian dollars, unless otherwise noted.

This MD&A contains additional generally accepted accounting principles ("GAAP") measures, non-GAAP measures and forward-looking statements. Readers are cautioned that the MD&A should be read in conjunction with ARC’s disclosure under the headings “Non-GAAP Measures,” “Additional GAAP Measures,” “Forward-looking Information and Statements” and "Glossary" included at the end of this MD&A.

ABOUT ARC RESOURCES LTD.

ARC is a dividend-paying Canadian oil and gas company headquartered in Calgary, Alberta. ARC’s activities relate to the exploration, development and production of conventional oil and natural gas in Canada with an emphasis on the development of properties with a large volume of hydrocarbons in place commonly referred to as “resource plays.”

ARC’s vision is to be a leading energy producer, focused on delivering results through its strategy of risk-managed value creation.ARC is committed to providing superior long-term financial returns for its shareholders, creating a culture where respect for the individual is paramount and action and passion are rewarded. ARC runs its business in a manner that protects the safety of employees, communities and the environment. ARC’s vision is realized through the four pillars of its strategy:

1. High quality, long-life assets – ARC’s unique suite of assets include both growth and base assets. ARC’s growth assets consist of world-class resource play properties, primarily concentrated in the Montney geological formation in northeast British Columbia and northern Alberta, and the Cardium formation in the Pembina area of Alberta. These assets provide substantial growth opportunities, which ARC will pursue to create value through long-term profitable development. ARC’s base assets consist of core properties located throughout Alberta, Saskatchewan and Manitoba. The base assets deliver stable production and contribute significant cash flow to fund future development and support ARC's dividend.

2. Operational excellence – ARC is focused on capital discipline and cost management to extract the maximum return on its investments while operating in a safe and environmentally responsible manner. Production from individual oil and natural gas wells naturally declines over time. In any one year, ARC approves a budget to drill new wells with the intent to first replace production declines and second to potentially increase production volumes. At times, ARC may also acquire strategic producing or undeveloped properties to enhance current production and reserves or to provide potential future drilling locations. Alternatively, it may strategically dispose of non-core assets that no longer meet its investment criteria.

3. Financial flexibility –ARC provides returns to shareholders through a combination of a monthly dividend, currently $0.10 per share per month, and the potential for capital appreciation. ARC’s goal is to fund dividend payments and capital expenditures necessary for the replacement of production declines using funds from operations ⁽¹⁾. ARC will finance value-creating activities through a combination of sources including funds from operations, proceeds from ARC’s Dividend Reinvestment Program (“DRIP”), reduced funding required under the Stock Dividend Program ("SDP"), proceeds from property dispositions, debt capacity, and if necessary, equity issuance. ARC chooses to maintain prudent debt levels, targeting its net debtto be one to 1.5 times annualized funds from operations and less than 20 per cent of total capitalizationover the long-term ⁽¹⁾.

4. Top talent and strong leadership culture – ARC is committed to the attraction, retention and development of the best and brightest people in the industry. ARC’s employees conduct business every day in a culture of trust, respect, integrity and accountability. Building leadership talent at all levels of the organization is a key focus. ARC is also committed to corporate leadership through community investment, environmental reporting practices and open communication with all stakeholders. As of the end of September 2015, ARC had 566 employees with 322 professional, technical and support staff in the Calgary office, and 244 individuals located across ARC’s operating areas in western Canada.

(1) Funds from operations, net debt, and total capitalization are additional GAAP measures which may not be comparable to similar additional GAAP measures used by other entities. Refer to the section entitled “Additional GAAP Measures” contained within this MD&A. Also refer to the "Funds from Operations" section within this MD&A for a reconciliation of ARC’s net income to funds from operations and cash flow from operating activities.

ARC Resources Ltd. 1

Total Return to Shareholders

Despite the headwinds of a challenging commodity price environment, ARC's business plan has resulted in significant operational success and has contributed to a trailing five year annualized total return per share of 1.7 per cent (Table 1).

Table 1

Total Returns (1)	Trailing One Year		Trailing Three Year		Trailing Five Year
Dividends per share ($)	1.20		3.60		6.00
Capital appreciation (depreciation) per share ($)	(11.91	)	(6.26	)	(2.91	)
Total return per share (%)	(37.0	)	(15.2	)	8.9
Annualized total return per share (%)	(37.0	)	(5.3	)	1.7
S&P/TSX Exploration & Producers Index annualized total return (%)	(52.2	)	(17.2	)	(12.9	)

(1) Non-GAAP measure which may not be comparable to similar non-GAAP measures used by other entities. Refer to the section entitled "Non-GAAP Measures" contained within this MD&A. Calculated as at September 30, 2015.

Since 2011, ARC’s production has grown by 29,041 boe per day, or 35 per cent, while its proved plus probable reserves have grown by 100.3 MMboe, or 18 per cent. Table 2 highlights ARC’s production and reserves for the first nine months of 2015 and over the past four years:

Table 2

	2015 YTD	2014	2013	2012	2011
Production (boe/d) (1)	112,457	112,387	96,087	93,546	83,416
Daily production per thousand shares (2)(6)	0.33	0.35	0.31	0.31	0.29
Proved plus probable reserves (MMboe) (3)(4)(5)	n/a	672.7	633.9	607.0	572.4
Proved plus probable reserves per share (boe) (6)	n/a	2.1	2.0	2.0	2.0

(1) Reported production amount is based on company interest before royalty burdens.

(2) Daily production per thousand shares represents average daily production for the nine months ended September 30, 2015 and annual average daily production for the full years ended December 31, 2014, 2013, 2012 and 2011, divided by the diluted weighted average common shares for the respective periods.

(3) As determined by ARC’s independent reserve evaluator solely at December 31.

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

(5) Company gross reserves. For more information, see ARC’s Annual Information Form as filed on SEDAR at www.sedar.com and the news release entitled “ARC Resources Ltd. Announces 210 Per Cent Produced Reserves Replacement in 2014” dated February 11, 2015.

(6) Per share amounts are based on weighted average shares, diluted.

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ECONOMIC ENVIRONMENT

ARC’s third quarter 2015 financial and operating results were impacted by commodity prices and foreign exchange rates which are outlined in Table 3 below:

Table 3

Selected Benchmark Prices and Exchange Rates (1)	Three Months Ended				Nine Months Ended
	September 30				September 30
	2015	2014	% Change		2015	2014	% Change
Brent (US$/bbl)	51.30	103.46	(50	)	56.60	106.99	(47	)
WTI oil (US$/bbl)	46.50	97.25	(52	)	51.01	99.62	(49	)
Edmonton Par (Cdn$/bbl)	56.27	97.20	(42	)	58.63	100.81	(42	)
Henry Hub NYMEX (US$/MMbtu) (2)	2.77	4.06	(32	)	2.80	4.54	(38	)
AECO natural gas (Cdn$/Mcf)	2.80	4.22	(34	)	2.81	4.55	(38	)
Cdn$/US$ exchange rate	1.31	1.09	20		1.26	1.09	16

(1) The benchmark prices do not reflect ARC's realized sales prices. For average realized sales prices, refer to Table 13 in this MD&A. Prices and exchange rates presented above represent averages for the respective periods.

(2) NYMEX Henry Hub "Last Day" Settlement.

Global energy prices further deteriorated during the third quarter of 2015, reaching levels not seen since the 2009 financial crisis. Persistent oversupply, risks of slowing demand growth from China and other emerging economies, and a strong US dollar all contributed to downward pressure on crude oil prices. The WTI benchmark price averaged 52 per cent lower than the third quarter of 2014 and 20 per cent lower than the second quarter of 2015. ARC’s crude oil price is primarily referenced to the Edmonton Par benchmark price, which also decreased 42 per cent compared to the third quarter of 2014 and 17 per cent from the second quarter of 2015. Edmonton Par prices were impacted by unplanned production outages as well as anticipation surrounding the National Energy Board's final approval of the Enbridge Line 9B Reversal project. The differential between WTI and Edmonton Par narrowed year-over-year to an average discount of US$3.51, a 56 per cent decrease from the third quarter of 2014. Compared to the second quarter of 2015, third quarter differentials were impacted by the weaker continental demand and experienced a slight widening during the third quarter to US$3.51 per barrel from an average of US$2.87 per barrel in the second quarter of 2015. As oversupply is expected to be a continued concern in the North American crude oil market, prices are not expected to realize meaningful improvement for the remainder of 2015.

North American natural gas prices were flat in the third quarter of 2015 compared to the second quarter, though significantly lower in the third quarter when compared to the same period in 2014. The third quarter NYMEX Henry Hub price averaged 32 per cent lower compared to the third quarter of 2014 and five per cent higher compared to the second quarter of 2015. ARC’s realized natural gas price is primarily referenced to the AECO hub, which was 34 per cent lower in the third quarter of 2015 compared to the third quarter of 2014 and five per cent higher compared to the second quarter of 2015. Strong demand from increased power generation and increased Mexican exports were impeded by an oversupplied market as US production levels remained high. As a result, US inventory levels trended above the five-year average during the third quarter and are expected to end the injection season at record levels. This signals continued weakness in the natural gas markets for the remainder of 2015 and into 2016.

During the third quarter of 2015, the Canadian dollar continued to weaken relative to the US dollar, averaging US$0.76 (Cdn$/US$1.31). The Bank of Canada's current monetary policy and the overall weakness in the Canadian economy as a result of reduced exports and low energy prices impacted the Cdn$/US$ exchange rate. In addition, continued economic recovery in the United States resulted in a further strengthened US dollar. The devaluation of the Canadian dollar relative to the US dollar serves to partially offset the impact of lower US dollar-denominated crude oil and natural gas prices.

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Annual Guidance and Financial Highlights

Table 4 is a summary of ARC’s 2015 annual guidance and a review of 2015 year-to-date actual results.

Table 4

	2015 Guidance (1)(2)	2015 Revised Guidance(1)(2)	2015 YTD		% Variance from Guidance
Production
Crude oil (bbl/d)	33,500 - 34,500	33,500 - 34,500	32,379		(3	)
Condensate (bbl/d)	3,400 - 3,800	3,400 - 3,800	3,363		(1	)
Natural gas (MMcf/d)	430 - 440	435 - 440	436.7		—
NGLs (bbl/d)	4,500 - 4,900	3,700 - 3,900	3,918		(13	)
Total (boe/d)	113,000 - 116,000	113,000 - 115,000	112,457		—
Expenses ($/boe)
Operating (3)	8.20 - 8.50	7.50 - 7.70	7.49		(9	)
Transportation	2.00 - 2.20	2.30 - 2.50	2.38		8
G&A (4)	2.00 - 2.30	2.00 - 2.30	1.78		(11	)
Interest	1.10 - 1.30	1.10 - 1.30	1.23		—
Current income tax (per cent of funds from operations) (5)	0 - 5	0 - 2	—		—
Capital expenditures before land purchases and net property dispositions ($ millions)	550	550	392.1		N/A
Land purchases and net property dispositions ($ millions)	—	—	(30.4	)	N/A
Weighted average shares, diluted (millions)	339	339	339		N/A

(1) Incorporates impact of approximately 3,600 boe per day of divested non-core assets throughout 2015 (75 per cent natural gas), which has resulted in an annual volume impact of approximately 2,200 boe per day of production.

(2) ARC expects an increase in fourth quarter 2015 production to a range of 118,000 to 122,000 boe per day following commissioning of the new Sunrise gas processing facility and expanded Tower oil battery.

(3) Year-to-date actual results incorporates an impact of approximately $0.50 per boe due to a revision of estimates for prior period operating costs.

(4) G&A expenses per boe are based on a range of $1.65 - $1.70 per boe prior to the recognition of any expense associated with ARC’s share-based compensation plans and $0.35 - $0.60 per boe associated with ARC’s share-based compensation plans. Actual per boe costs for each of these components for the nine months ended September 30, 2015 were $1.57 and $0.21 per boe, respectively.

(5) The 2015 corporate tax estimate will vary depending on level of commodity prices.

Production for the nine months ended September 30, 2015 is just below the guidance range despite the commissioning of the new gas processing facility at Sunrise, as several turnarounds were planned and executed during the third quarter and as expected, third quarter production decreased from the first half of 2015 to 107,261 boe per day. Going forward, ARC expects an increase in fourth quarter production to a range of 118,000 to 122,000 boe per day with a full quarter of production from the Sunrise facility as well as additional production from the expanded Tower battery which is expected to be on-stream midway through the fourth quarter. ARC's full-year 2015 average production guidance has been revised to a range of 113,000 to 115,000 boe per day from the previously guided range of 113,000 to 116,000 boe per day. The revised full-year production guidance takes into account reduced 2015 capital spending and the divestment of approximately 3,600 boe per day of non-core assets throughout 2015 (75 per cent natural gas), which has resulted in an annual volume impact of approximately 2,200 boe per day of production.

On a per boe basis, operating costs have trended lower than originally anticipated with higher than expected production volumes for the first half of the year coupled with lower average electricity rates and diligent cost control over turnaround and maintenance activities completed during the year. Accordingly, ARC expects its full year operating costs per boe to fall in the range of $7.50 to $7.70. Year-to-date transportation expense exceeds the guidance range, as ARC has incurred additional trucking costs during the first quarter of 2015. During the second and third quarters, trucking activity has been reduced as more production has become pipeline connected, though pipeline tariffs costs have increased, partially offsetting reduced trucking costs. Various pipeline disruptions affecting some service providers have occurred throughout 2015 and ARC has responded with the contracting of additional service where appropriate to ensure it transports its products to market. For the full year, ARC has revised its guidance range for transportation costs to be in the range of $2.30 to $2.50. Year-to-date, ARC’s G&A expenses have trended lower than the guidance range due primarily to decreases to expenses under ARC’s share-based compensation plans. ARC has revised its guidance range for current

ARC Resources Ltd. Page 4

income tax to be in the range of 0 - 2 per cent of funds from operations reflecting lower expected taxable income for 2015 related to decreased commodity prices.

ARC incurred $392.1 million of capital expenditures during the first nine months of 2015. In addition, ARC spent $2.1 million on land purchases during the period and completed net dispositions of $32.5 million. The 2015 planned capital program focuses primarily on profitable development in the British Columbia Montney region as these projects provide the highest rates of return at current commodity prices. ARC continues to see significant long-term value throughout its asset base and has resumed development activities in some areas due to reduced service costs and will resume elsewhere as economic conditions improve.

The guidance information presented is intended to provide shareholders with information on Management’s expectations for results from operations. Readers are cautioned that the guidance may not be appropriate for other purposes.

2015THIRD QUARTER FINANCIAL AND OPERATING RESULTS

Financial Highlights

Table 5

	Three Months Ended					Nine Months Ended
	September 30					September 30
($ millions, except per share and volume data)	2015		2014	% Change		2015		2014	% Change
Funds from operations (1)	174.9		284.2	(38	)	572.7		872.3	(34	)
Funds from operations per share (1)(2)	0.51		0.89	(43	)	1.69		2.76	(39	)
Net income (loss)	(235.0	)	90.3	(360	)	(287.7	)	267.1	(208	)
Dividends per share (2)	0.30		0.30	—		0.90		0.90	—
Average daily production (boe/d)	107,261		115,530	(7	)	112,457		110,501	2

(1) Refer to the sections entitled "Funds from Operations" and “Additional GAAP Measures” contained within this MD&A.

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

Funds from Operations

ARC reports funds from operations in total and on a per share basis. Funds from operations does not have a standardized meaning prescribed by Canadian GAAP. Refer to the section entitled “Additional GAAP Measures” contained within this MD&A.

Table 6 is a reconciliation of ARC’s net income (loss) to funds from operations and cash flow from operating activities:

Table 6

	Three Months Ended				Nine Months Ended
	September 30				September 30
($ millions)	2015		2014		2015		2014
Net income (loss)	(235.0	)	90.3		(287.7	)	267.1
Adjusted for the following non-cash items:
DD&A and impairment	472.9		168.9		802.4		479.1
Accretion of ARO	3.3		3.6		10.1		11.2
Intangible E&E expenses	2.5		28.2		46.9		29.9
Deferred tax expense (recovery)	(48.1	)	20.6		(10.0	)	35.6
Unrealized loss (gain) on risk management contracts	(93.9	)	(67.1	)	(110.4	)	7.3
Unrealized loss on foreign exchange	72.2		37.8		143.6		41.1
Gain on disposal of petroleum and natural gas properties	—		1.9		(23.3	)	1.9
Other	1.0		—		1.1		(0.9	)
Funds from operations	174.9		284.2		572.7		872.3
Net change in other liabilities	(8.1	)	(6.2	)	(18.0	)	(20.8	)
Change in non-cash working capital	(1.4	)	(10.5	)	(41.5	)	10.3
Cash flow from operating activities	165.4		267.5		513.2		861.8

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Details of the change in funds from operations from the three and nine months ended September 30, 2014 to the three and nine months ended September 30, 2015 are included in Table 7 below:

Table 7

	Three Months Ended				Nine Months Ended
	September 30				September 30
	$ millions		$/Share (1)		$ millions		$/Share (1)
Funds from operations – 2014	284.2		0.89		872.3		2.76
Volume variance
Crude oil and liquids	(65.1	)	(0.20	)	(116.6	)	(0.36	)
Natural gas	0.2		—		53.6		0.17
Price variance
Crude oil and liquids	(135.2	)	(0.42	)	(445.1	)	(1.41	)
Natural gas	(55.9	)	(0.16	)	(238.1	)	(0.75	)
Other Revenue	0.3		—		0.4		—
Realized gain or loss on risk management contracts	47.0		0.14		188.0		0.59
Royalties	49.3		0.14		154.3		0.49
Expenses (recoveries)
Transportation	1.8		0.01		(8.7	)	(0.03	)
Operating	23.8		0.07		41.6		0.13
G&A	(1.1	)	—		4.3		0.01
Interest	(1.5	)	—		(3.3	)	(0.01	)
Current tax	27.1		0.08		70.0		0.22
Diluted shares	—		(0.04	)	—		(0.12	)
Funds from operations – 2015	174.9		0.51		572.7		1.69

(1) Per share amounts are based on weighted average shares, diluted.

Funds from operations decreased by 38 per cent in the third quarter of 2015 to $174.9 million from $284.2 million generated in the third quarter of 2014. The decrease reflects lower revenue due primarily to significantly lower realized commodity prices and reduced crude oil and liquids production in the third quarter of 2015 as compared to the third quarter of 2014. Increased realized gains on risk management contracts relative to the third quarter of the prior year along with reduced royalties, current taxes and operating costs partially offset the reduction in commodity prices.

For the year-to-date, funds from operations decreased by $299.6 million from $872.3 million for the first nine months of 2014 to $572.7 million for the first nine months of 2015. This decrease is also due primarily to decreased revenue from significantly lower commodity prices as well as reduced crude oil and liquids production, partially offset by increased natural gas production, increased realized gains on risk management contracts, lower royalties, taxes and operating costs.

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2015 Funds from Operations Sensitivity

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

Table 8

					Impact on Annual Funds from Operations(6)
	Assumption		Change		$/Share
Business Environment (1)
Crude oil price (US$ WTI/bbl) (2)(3)	51.01		1.00		0.029
Natural gas price (Cdn$ AECO/Mcf) (2)(3)	2.81		0.10		0.031
Cdn$/US$ exchange rate (2)(3)(4)	1.26		0.01		0.012
Interest rate on floating-rate debt (2)	2.8	%	1.0	%	—
Operational
Crude oil and liquids production volumes (bbl/d) (5)	39,660		1.0	%	0.014
Natural gas production volumes (MMcf/d) (5)	436.7		1.0	%	0.009
Operating expenses ($/boe) (5)	7.49		1.0	%	0.007
G&A expenses ($/boe) (5)	1.78		10.0	%	0.021

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

(2) Prices and rates are indicative of published prices for the first nine months of 2015. See Table 13 of this MD&A for additional details. The calculated impact on funds from operations would only be applicable within a limited range of these amounts.

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

(4) Includes impact of foreign exchange on crude oil, condensate, and NGLs prices that are presented in US dollars.

(5) Operational assumptions are based upon results for the nine months endedSeptember 30, 2015.

(6) Refer to the sections entitled "Funds from Operations" and “Additional GAAP Measures” contained within this MD&A.

Net Income (Loss)

A net loss of $235 million ($0.69 per share) was incurred in the third quarter of 2015, a $325.3 million ($0.97 per share) decrease compared to net income of $90.3 million ($0.28 per share) in the third quarter of 2014. ARC recorded increased depletion, depreciation, amortization and impairment charges of $304 million in the third quarter of 2015. This was primarily driven by impairment charges to PP&E of $326.6 million ($240.4 million net of deferred tax recovery) as a result of the low commodity price environment, partially offset by lower depreciation expense in the third quarter of 2015. Additionally, ARC's revenue net of royalties decreased $206.4 million due to a significant decrease in prices realized for crude oil and natural gas during the third quarter of 2015 compared to those in the third quarter of 2014, partially offset by reduced royalties. Also decreasing net income in the third quarter of 2015 was an increase to foreign exchange losses of $34.4 million. Partially offsetting these decreases in net income were higher third quarter gains on risk management contracts of $73.8 million, lower operating costs of $23.8 million, lower intangible E&E expenses of $25.7 million and lower current and deferred income taxes of $95.8 million.

During the nine months ended September 30, 2015, ARC incurred a net loss of $287.7 million ($0.85 per share), $554.8 million ($1.70 per share) less than net income of $267.1 million ($0.85 per share) recorded during the nine months ended September 30, 2014. Lower commodity prices during the period resulted in lower revenue net of royalties of $591.5 million, however, the impact of falling prices was partially offset by increased gains on risk management contracts of $305.7 million. Also decreasing net income during the year to date was an aggregate impairment to PP&E of $338.3 million ($249.1 million net of deferred tax recovery), an increase to foreign exchange losses of $102.5 million and increased intangible E&E expenses of $17 million. These items are partially offset by lower operating costs of $41.6 million, gains on disposal of petroleum and natural gas properties of $25.2 million and lower current and deferred taxes of $115.6 million.

For further information regarding the impairment charge for September 30, 2015, refer to Note 6 "Impairment" in the financial statements for the three and nine months ended September 30, 2015.

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Production

Table 9

	Three Months Ended				Nine Months Ended
	September 30				September 30
Production	2015	2014	% Change		2015	2014	% Change
Light and medium crude oil (bbl/d)	28,516	34,713	(18	)	31,390	35,194	(11	)
Heavy oil (bbl/d)	881	1,158	(24	)	989	1,022	(3	)
Condensate (bbl/d)	3,361	3,862	(13	)	3,363	3,741	(10	)
Natural gas (MMcf/d)	425.1	424.5	—		436.7	397.3	10
NGLs (bbl/d)	3,653	5,056	(28	)	3,918	4,331	(10	)
Total production (boe/d)	107,261	115,530	(7	)	112,457	110,501	2
% Natural gas production	66	61	8		65	60	8
% Crude oil and liquids production	34	39	(13	)	35	40	(13	)

ARC’s crude oil production consists predominantly of light and medium crude oil while heavy oil accounts for approximately three per cent of total oil production. During the third quarter of 2015, crude oil and liquids production decreased 19 per cent from the third quarter of the prior year. The decrease in crude oil and liquids production primarily reflects downtime due to turnaround and maintenance activity as well as production decline in areas with little drilling activity in the current year. For the nine months ended September 30, 2015, crude oil and liquids volumes decreased by ten per cent as compared to the same period in 2014 due to natural declines associated with reduced drilling activity and due to significant planned turnarounds in the third quarter.

Natural gas production was 425.1 MMcf per day in the third quarter of 2015, a slight increase from the 424.5 MMcf per day produced in the third quarter of 2014. The increase is mainly attributed to new production from drilling throughout 2015 in northeastern British Columbia, particularly at Sunrise and is largely offset by major turnarounds completed during the third quarter of 2015 at Dawson and Ante Creek as well as the disposition of non-core assets in South Central Alberta in the second quarter of 2015 which had been producing approximately 2,400 boe per day prior to disposal. ARC's newest 60 MMcf per day gas processing facility at Sunrise was commissioned part-way through the third quarter of 2015. For the nine months ended September 30, 2015, natural gas production increased by ten per cent as new production was brought on later in 2014 and throughout 2015 at Sunrise and Parkland served to offset the impact of lost production due to the turnarounds and the second quarter disposition.

During the third quarter of 2015, ARC drilled 18 wells (100 per cent ARC) on operated properties consisting of eleven oil wells, three natural gas wells, three liquids-rich natural gas wells, and one service well. For the nine months ended September 30, 2015, ARC drilled 55 gross wells (54 net wells) on operated properties consisting of 33 gross (32 net) oil wells,16 gross (16 net) natural gas wells, five gross (five net) liquids-rich natural gas wells, and one gross (one net) service well.

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Table 10 summarizes ARC’s production by core area for the third quarter of 2015 and 2014:

Table 10

	Three Months Ended September 30, 2015
Production	Total	Crude Oil	Condensate	Natural Gas	NGLs
Core Area (1)	(boe/d)	(bbl/d)	(bbl/d)	(MMcf/d)	(bbl/d)
Northeast BC	62,265	1,587	2,375	340.1	1,611
Northern AB	19,591	6,679	749	64.8	1,358
Pembina	10,547	7,848	173	12.6	433
South Central AB (2)	5,253	3,978	7	6.6	164
Southeast SK & MB	9,605	9,305	57	1.0	87
Total	107,261	29,397	3,361	425.1	3,653

	Three Months Ended September 30, 2014
Production	Total	Crude Oil	Condensate	Natural Gas	NGLs
Core Area (1)	(boe/d)	(bbl/d)	(bbl/d)	(MMcf/d)	(bbl/d)
Northeast BC	62,629	4,315	2,732	316.7	2,822
Northern AB	23,312	9,086	856	71.0	1,531
Pembina	11,002	8,460	154	11.9	402
South Central AB (2)	8,266	4,014	71	23.8	206
Southeast SK & MB	10,321	9,996	49	1.1	95
Total	115,530	35,871	3,862	424.5	5,056

(1) Provincial references: "AB" is Alberta, "BC" is British Columbia, "SK" is Saskatchewan, "MB" is Manitoba.

(2) During the second quarters of 2015 and 2014, ARC disposed of certain non-core assets in this district. Each disposition included assets that had been producing approximately 2,400 boe per day prior to disposal. An additional 500 boe per day were disposed from this district toward the end of the third quarter of 2015.

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Table 10a summarizes ARC’s production by core area for the nine months ended September 30, 2015 and 2014:

Table 10a

	Nine Months Ended September 30, 2015
Production	Total	Crude Oil	Condensate	Natural Gas	NGLs
Core Area (1)	(boe/d)	(bbl/d)	(bbl/d)	(MMcf/d)	(bbl/d)
Northeast BC	63,347	2,416	2,389	341.0	1,704
Northern AB	21,120	7,532	712	68.4	1,473
Pembina	11,203	8,432	169	12.9	450
South Central AB (2)	6,619	4,131	42	13.4	211
Southeast SK & MB	10,168	9,868	51	1.0	80
Total	112,457	32,379	3,363	436.7	3,918

	Nine Months Ended September 30, 2014
Production	Total	Crude Oil	Condensate	Natural Gas	NGLs
Core Area (1)	(boe/d)	(bbl/d)	(bbl/d)	(MMcf/d)	(bbl/d)
Northeast BC	55,646	3,051	2,634	286.8	2,168
Northern AB	23,593	9,901	832	68.3	1,471
Pembina	11,163	8,593	162	12.1	392
South Central AB (2)	9,374	4,247	73	29.0	223
Southeast SK & MB	10,725	10,424	40	1.1	77
Total	110,501	36,216	3,741	397.3	4,331

(1) Provincial references: "AB" is Alberta, "BC" is British Columbia, "SK" is Saskatchewan, "MB" is Manitoba.

(2) During the second quarters of 2015 and 2014, ARC disposed of certain non-core assets in this district. Each disposition included assets that had been producing approximately 2,400 boe per day prior to disposal. An additional 500 boe per day were disposed from this district toward the end of the third quarter of 2015.

Sales of Crude Oil, Natural Gas, Condensate, NGLs and Other Income

Sales revenue from crude oil, natural gas, condensate, NGLs and other income was $279.5 million in the third quarter of 2015, a decrease of $255.7 million from $535.2 million for the same period in the prior year. The decrease reflects a decrease in average commodity pricing which lowered revenue by $191.1 million, as well as decreased crude oil and liquids production volumes that reduced revenue by $65.1 million. Crude oil, condensate and NGLs revenue accounted for $160.1 million or 58 per cent of third quarter sales revenue.

For the nine months ended September 30, 2015, sales revenue from crude oil, natural gas, condensate, NGLs and other income was $907.8 million, a decrease of $745.8 million from $1,653.6 million for the same period in the prior year. The decrease reflects a decrease in average commodity pricing which lowered revenue by $683.2 million, as well as decreased crude oil and liquids production volumes that reduced revenue by $116.6 million. The decrease was partially offset by increased natural gas production volumes that contributed additional revenue of $53.6 million.

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

Table 11

	Three Months Ended				Nine Months Ended
	September 30				September 30
Sales revenue by product ($ millions)	2015	2014	% Change		2015	2014	% Change
Crude oil	141.8	308.1	(54	)	486.6	958.7	(49	)
Condensate	16.4	34.0	(52	)	50.8	102.1	(50	)
Natural gas	118.4	174.0	(32	)	356.2	540.6	(34	)
NGLs	1.9	18.4	(90	)	11.4	49.8	(77	)
Total sales revenue from crude oil, natural gas, condensate and NGLs	278.5	534.5	(48	)	905.0	1,651.2	(45	)
Other income	1.0	0.7	43		2.8	2.4	17
Total sales revenue	279.5	535.2	(48	)	907.8	1,653.6	(45	)

While ARC’s production mix on a per boe basis is weighted more heavily to natural gas than to oil, ARC's revenue contribution is more heavily weighted to crude oil and liquids production as shown by the table below:

Table 12

	Three Months Ended		Nine Months Ended
	September 30		September 30
Revenue by Product Type	2015	2014	2015	2014
	% of Total Revenue	% of Total Revenue	% of Total Revenue	% of Total Revenue
Crude oil and liquids	58	67	60	67
Natural gas	42	33	40	33
Total sales revenue	100	100	100	100

Commodity Prices Prior to Hedging

Table 13

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2015	2014	% Change		2015	2014	% Change
Average Benchmark Prices
AECO natural gas (Cdn$/Mcf) (1)	2.80	4.22	(34	)	2.81	4.55	(38	)
WTI oil (US$/bbl)	46.50	97.25	(52	)	51.01	99.62	(49	)
Cdn$/US$ exchange rate	1.31	1.09	20		1.26	1.09	16
WTI oil (Cdn$/bbl)	60.92	105.91	(42	)	64.27	109.01	(41	)
Edmonton par (Cdn$/bbl)	56.27	97.20	(42	)	58.63	100.81	(42	)
ARC Realized Prices Prior to Hedging
Crude oil ($/bbl)	52.43	93.34	(44	)	55.05	96.96	(43	)
Condensate ($/bbl)	53.00	95.55	(45	)	55.32	99.96	(45	)
Natural gas ($/Mcf)	3.03	4.46	(32	)	2.99	4.98	(40	)
NGLs ($/bbl)	5.68	39.61	(86	)	10.69	42.13	(75	)
Total commodity price prior to other income and hedging ($/boe)	28.22	50.28	(44	)	29.48	54.74	(46	)
Other income ($/boe)	0.09	0.08	13		0.09	0.08	13
Total commodity price prior to hedging ($/boe)	28.31	50.36	(44	)	29.57	54.82	(46	)

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

In the third quarter of 2015, WTI decreased 52 per cent to US$46.50 per barrel as compared to US$97.25 per barrel in the same period in 2014. Similarly, ARC’s realized crude oil price decreased by 44 per cent over the same time period,

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averaging $52.43 per barrel. During the third quarter of 2015, the differential between WTI and Edmonton posted prices narrowed to an average discount of US$3.51 per barrel compared to US$7.97 per barrel in the same period in 2014. During the same period, the average exchange rate for the Canadian dollar as compared to the US dollar weakened from $1.09 to $1.31. The narrowing of the differential combined with a weaker Canadian dollar served to mitigate somewhat the overall impact of the decrease in WTI on ARC's realized prices.

For the nine months ended September 30, 2015, ARC's realized crude oil price fell by 43 per cent as compared to the nine months ended September 30, 2014. This price decrease is primarily attributed to the 49 per cent decrease in WTI over the same time period, partially offset by the effect of a narrowed differential between WTI and Edmonton Par crude oil prices and a weakened Canadian dollar.

Natural gas prices decreased in the third quarter and first nine months of 2015 as compared to the same periods in 2014 as year-over-year North American supply exceeded demand, leaving inventory levels much higher than in the prior year. ARC's average realized natural gas prices for the three and nine months ended September 30, 2015 of $3.03 per Mcf and $2.99 per Mcf, respectively, were higher than the average AECO monthly index price during the same periods due in part to ARC's higher than average heat content in its natural gas. Approximately 20 per cent of ARC's natural gas production is sold at Station 2 which has experienced volatile pricing over the quarter primarily due to maintenance on all Western Canadian pipelines. ARC has been able to mitigate the impact of Station 2 pricing through the physical diversification of its sales points. ARC maintains a diversified sales portfolio that allows some flexibility on a portion of its natural gas sales between monthly average and daily spot pricing at sales hubs in western Canada and the mid-western United States.

Risk Management

ARC maintains a risk management program to reduce the volatility of revenues, increase the certainty of funds from operations, and to protect acquisition and development economics. ARC’s risk management program is governed by certain guidelines approved by the Board of Directors (the "Board"). These guidelines currently restrict risk management contracts to a maximum of 55 per cent of total forecast production whereby a specific commodity (crude oil or natural gas) cannot exceed a maximum of 70 per cent of forecast production for that commodity over the next two years, and with a maximum of 25 per cent of forecast natural gas production in risk management contracts beyond two years and up to five years. ARC’s risk management program guidelines allow for further risk management contracts on anticipated volumes associated with new production arising from specific capital projects and acquisitions or to further protect cash flows for a specific period with approval of the Board.

Gains and losses on risk management contracts are composed of both realized gains and losses, representing the portion of risk management contracts that have settled in cash during the period, and unrealized gains or losses that represent the change in the mark-to-market position of those contracts throughout the period. ARC does not employ hedge accounting for any of its risk management contracts currently in place. ARC considers all of its risk management contracts to be effective economic hedges of its underlying business transactions.

Table 14 summarizes the total gain or loss on risk management contracts for the third quarter of 2015 compared to the same period in 2014:

Table 14

Risk Management Contracts ($ millions)	Crude Oil & Liquids	Natural  Gas	Foreign Currency		Power		Q3 2015 Total	Q3 2014 Total
Realized gain (loss) on contracts (1)	7.8	34.6	(2.8	)	(0.9	)	38.7	(8.3	)
Unrealized gain (loss) on contracts (2)	52.6	42.9	0.9		(2.5	)	93.9	67.1
Gain (loss) on risk management contracts	60.4	77.5	(1.9	)	(3.4	)	132.6	58.8

(1) Represents actual cash settlements or receipts under the respective contracts.

(2) Represents the change in fair value of the contracts during the period.

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Table 14a summarizes the total gain or loss on risk management contracts for the nine months ended September 30, 2015 compared to the same period in 2014:

Table 14a

Risk Management Contracts ($ millions)	Crude Oil & Liquids	Natural  Gas	Foreign Currency		Power		2015 YTD Total	2014 YTD Total
Realized gain (loss) on contracts (1)	43.1	98.0	(6.7	)	(0.3	)	134.1	(53.9	)
Unrealized gain (loss) on contracts (2)	19.4	91.0	0.2		(0.2	)	110.4	(7.3	)
Gain (loss) on risk management contracts	62.5	189.0	(6.5	)	(0.5	)	244.5	(61.2	)

(1) Represents actual cash settlements or receipts under the respective contracts.

(2) Represents the change in fair value of the contracts during the period.

During the three and nine months ended September 30, 2015, ARC recorded gains of $132.6 million and $244.5 million, respectively, on its risk management contracts comprising realized gains of $38.7 million and unrealized gains of $93.9 million for the third quarter and a realized gain of $134.1 million and an unrealized gain of $110.4 million for the year-to-date. The realized gains reflect positive cash settlements received on crude oil contracts with an average floor price of US$90/bbl for the first and second quarters of 2015, swaps with an average price of C$74.77 in the third quarter and on natural gas contracts with an average floor price of $3.94/MMbtu throughout the period. These gains are partially offset by losses on forward foreign currency and power contracts.

ARC's third quarter 2015 unrealized gains on crude oil contracts reflect lower Canadian WTI prices in the forward price curve. During the same period, unrealized gains on natural gas contracts reflect lower NYMEX Henry Hub prices, offset by slightly narrower AECO basis through 2019. Year-to-date, ARC's unrealized gains on natural gas contracts primarily reflect lower NYMEX Henry Hub prices. Third quarter and year-to-date losses on electricity contracts reflect lower power prices in the forward price curve.

ARC’s risk management contracts provide protection from natural gas prices on 215,000 MMbtu per day for the fourth quarter of 2015. ARC has also executed long-term natural gas contracts on 176,650 MMbtu per day for 2016, 145,000 MMbtu per day for 2017, 90,000 MMbtu per day for 2018 and 40,000 MMbtu per day for 2019. In addition, ARC has AECO basis swap contracts in place, fixing the AECO price received on a portion of its natural gas volume throughout 2015 to 2019.

For crude oil, ARC has 15,000 barrels per day of crude oil production hedged for the fourth quarter of 2015. In addition, ARC has hedged 10,000 barrels per day of production for 2016 and 3,000 barrels per day of production for the first half of 2017. ARC also has MSW basis swap contracts in place for the balance of 2015 and through 2016, fixing the discount between WTI and the mixed sweet crude grade price at Edmonton.

Table 15 summarizes ARC’s average crude oil and natural gas hedged volumes for 2015 through 2019 as at the date of this MD&A. For a complete listing and terms of ARC’s hedging contracts at September 30, 2015, see Note 9 “Financial Instruments and Market Risk Management” in the financial statements as at and for the three and nine months ended September 30, 2015. Updates to the following table are posted to ARC’s website at www.arcresources.com.

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Table 15

Hedge Positions Summary (1)
As at November 4, 2015	Q4 2015			2016			2017		2018		2019
Crude Oil - Cdn$ WTI (2)	Cdn$/bbl		bbl/d	Cdn$/bbl		bbl/d	Cdn$/bbl	bbl/d	Cdn$/bbl	bbl/d	Cdn$/bbl	bbl/d
Ceiling	81.27		10,000	83.38		3,000	83.38	1,488	—	—	—	—
Floor	61.80		10,000	70.00		3,000	70.00	1,488	—	—	—	—
Swap	74.77		5,000	77.20		7,000	—	—	—	—	—	—
Crude Oil - MSW (Differential to WTI) (3)	US$/bbl		bbl/d	US$/bbl		bbl/d	US$/bbl	bbl/d	US$/bbl	bbl/d	US$/bbl	bbl/d
Swap	(4.81	)	5,000	(3.78	)	9,000	—	—	—	—	—	—
Natural Gas - NYMEX (4)	US$/MMbtu		MMbtu/d	US$/MMbtu		MMbtu/d	US$/MMbtu	MMbtu/d	US$/MMbtu	MMbtu/d	US$/MMbtu	MMbtu/d
Ceiling	4.51		215,000	4.79		105,000	4.81	145,000	4.92	90,000	5.00	40,000
Floor	3.94		215,000	4.00		105,000	4.00	145,000	4.00	90,000	4.00	40,000
Swap	—		—	4.00		40,000	—	—	—	—	—	—
Natural Gas - AECO (5)	Cdn$/GJ		GJ/d	Cdn$/GJ		GJ/d	Cdn$/GJ	GJ/d	Cdn$/GJ	GJ/d	Cdn$/GJ	GJ/d
Swap	—		—	2.99		30,000	—	—	—	—	—	—
Natural Gas - AECO Basis(6)	AECO/NYMEX		MMbtu/d	AECO/NYMEX		MMbtu/d	AECO/NYMEX	MMbtu/d	AECO/NYMEX	MMbtu/d	AECO/NYMEX	MMbtu/d
Swap (percentage of NYMEX)	89.5		160,000	90.3		140,000	90.2	140,000	85.3	85,000	83.7	40,000
Foreign Exchange	Cdn$/US$		US$ Millions Total	Cdn$/US$		US$ Millions Total	Cdn$/US$	US$ Millions Total	Cdn$/US$	US$ Millions Total	Cdn$/US$	US$ Millions Total
Ceiling	1.0725		12	—		—	—	—	—	—	—	—
Floor	1.0463		12	—		—	—	—	—	—	—	—

(1) The prices and volumes in this table represent averages for several contracts representing different periods. 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. All positions are financially settled against the benchmark prices disclosed in Note 9 “Financial Instruments and Market Risk Management” in the financial statements for the three and nine months ended September 30, 2015.

(2) Crude oil prices referenced to WTI, multiplied by the Bank of Canada monthly average noon day rate.

(3) MSW differential refers to the discount between WTI and the mixed sweet crude grade at Edmonton, calculated on a monthly weighted average basis in US$.

(4) Natural gas prices referenced to NYMEX Henry Hub.

(5) Natural gas prices referenced to AECO 7(a) index.

(6) ARC sells the majority of its natural gas production based on AECO pricing. To reduce the risk of weak basis pricing (AECO relative to NYMEX Henry Hub), ARC has hedged a portion of production by tying ARC's price to a percentage of the NYMEX Henry Hub natural gas price.

The fair value of ARC’s risk management contracts at September 30, 2015 was a net asset of $368.4 million, representing the expected market price to buy out ARC’s contracts at the balance sheet date after any adjustments for credit risk. This may differ from what will eventually be settled in future periods.

Operating Netbacks

ARC’s 2015 third quarter and year-to-date netbacks prior to hedging were $16.10 per boe and $17.06 per boe, respectively, representing decreases of 50 per cent and 52 per cent as compared to the same periods in 2014.

ARC’s 2015 third quarter and year-to-date netbacks, including realized hedging gains and losses, were $20.03 per boe and $21.43 per boe, respectively, representing decreases of 36 per cent and 37 per cent as compared to the same periods in 2014.

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The components of operating netbacks for the third quarter of 2015 compared to the same period in 2014 are summarized in Table 16:

Table 16

Netbacks(1)	Crude Oil		Heavy Oil		Condensate		Natural Gas		NGLs		Q3 2015 Total		Q3 2014 Total
	($/bbl)		($/bbl)		($/bbl)		($/Mcf)		($/bbl)		($/boe)		($/boe)
Average sales price	52.81		40.00		53.00		3.03		5.68		28.22		50.28
Other income	—		—		—		—		—		0.09		0.08
Total sales	52.81		40.00		53.00		3.03		5.68		28.31		50.36
Royalties	(6.08	)	0.19		(8.87	)	(0.16	)	(2.24	)	(2.59	)	(7.05	)
Transportation	(2.30	)	(0.58	)	(3.32	)	(0.37	)	(7.99	)	(2.44	)	(2.44	)
Operating expenses (2)	(13.68	)	(6.41	)	(5.09	)	(0.79	)	(6.30	)	(7.18	)	(8.91	)
Netback prior to hedging	30.75		33.20		35.72		1.71		(10.85	)	16.10		31.96
Hedging gain (loss) (3)	2.67		—		—		0.81		—		3.93		(0.56	)
Netback after hedging	33.42		33.20		35.72		2.52		(10.85	)	20.03		31.40
% of total netback	45		1		6		50		(2	)	100		100

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

(2) Composed of direct costs incurred to operate crude oil and natural gas wells. A number of assumptions have been made in allocating these costs between crude oil, heavy oil, condensate, natural gas and NGLs production.

(3) Includes realized cash gains and losses on risk management contracts.

The components of operating netbacks for the nine months ended September 30, 2015 compared to the same period in 2014 are summarized in Table 16a:

Table 16a

Netbacks(1)	Crude Oil		Heavy Oil		Condensate		Natural Gas		NGLs		2015 YTD Total		2014 YTD Total
	($/bbl)		($/bbl)		($/bbl)		($/Mcf)		($/bbl)		($/boe)		($/boe)
Average sales price	55.46		41.93		55.32		2.99		10.69		29.48		54.74
Other income	—		—		—		—		—		0.09		0.08
Total sales	55.46		41.93		55.32		2.99		10.69		29.57		54.82
Royalties	(5.75	)	(0.83	)	(9.43	)	(0.17	)	(2.18	)	(2.64	)	(7.80	)
Transportation	(2.58	)	(0.54	)	(2.96	)	(0.33	)	(7.91	)	(2.38	)	(2.13	)
Operating expenses (2)	(13.24	)	(9.68	)	(5.61	)	(0.86	)	(6.07	)	(7.49	)	(9.00	)
Netback prior to hedging	33.89		30.88		37.32		1.63		(5.47	)	17.06		35.89
Hedging gain (loss) (3)	4.85		—		—		0.78		—		4.37		(1.71	)
Netback after hedging	38.74		30.88		37.32		2.41		(5.47	)	21.43		34.18
% of total netback	50		1		5		45		(1	)	100		100

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

(2) Composed of direct costs incurred to operate crude oil and natural gas wells. A number of assumptions have been made in allocating these costs between crude oil, heavy oil, condensate, natural gas and NGLs production.

(3) Includes realized cash gains and losses on risk management contracts.

Royalties

ARC pays royalties to the respective provincial governments and landowners of the four western Canadian provinces in which it operates. Approximately 76 per cent of these royalties are Crown royalties. Each province that ARC operates in has established a separate and distinct royalty regime which impacts ARC’s average corporate royalty rate.

Total royalties as a percentage of pre-hedged commodity product sales revenue decreased from 14 per cent ($7.05 per boe) in the third quarter of 2014 to 9.2 per cent ($2.59 per boe) in the third quarter of 2015 reflecting the "sliding scale" effect of royalty rates with the decrease in average commodity prices during that time period. Similarly, total royalties decreased from $74.9 million in the third quarter of 2014 to $25.6 million in the third quarter of 2015. For the nine months ended September 30, 2015, total royalties represented 8.9 per cent of pre-hedged commodity product sales ($2.64 per

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boe) as compared to 14.2 per cent ($7.80 per boe) for the same period in 2014. The decrease in the royalty rate during the first nine months of 2015 as compared to the same period of the prior year also reflects the impact of the decrease in commodity prices on royalties over the same periods.

Operating and Transportation Expenses

Operating expenses decreased to $7.18 per boe in the third quarter of 2015 compared to $8.91 per boe in the third quarter of 2014. On an absolute dollar basis, operating expenses have also decreased by $23.8 million or 25 per cent in the third quarter of 2015 as compared to the third quarter of 2014. The decrease is mainly a result of lower electricity rates, reduced maintenance activity levels, and diligent cost control efforts including negotiating service cost decreases with many of ARC's suppliers throughout 2015. The lower electricity cost in the third quarter of 2015 compared to the third quarter of 2014 is due to an average Alberta Power Pool Rate of $26.04 per megawatt hour in the third quarter of 2015 as compared to an average rate of $63.91 per megawatt hour during the third quarter of 2014. For the nine months ended September 30, 2015 operating expenses decreased by $41.6 million or $1.51 per boe, as a result of lower activity levels and increased production volumes from new wells with relatively lower average operating costs.

ARC hedges a portion of its electricity costs using financial risk management contracts that do not qualify for hedge accounting. The gains and losses associated with these contracts are included within gains and losses on risk management contracts on the condensed interim consolidated statements of income (loss) (the "statements of income (loss)"). Had these contracts been recognized within operating expenses, ARC’s operating expenses would have been increased by $0.09 per boe for the three months ended September 30, 2015 (increased $0.01 per boe for the nine months ended September 30, 2015) as a result of a realized loss of $0.9 million during the period (realized loss of $0.3 million for the nine months ended September 30, 2015).

Transportation expense was $2.44 per boe during the third quarter of 2015 ($2.38 per boe for the nine months ended September 30, 2015) as compared to $2.44 per boe in the third quarter of 2014 ($2.13 per boe for the nine months ended September 30, 2014). Due to turnaround activity resulting in declines to production and firm service transportation contracts, transportation per boe was flat for the third quarter of 2015 compared to 2014. The increase in transportation charges for the nine months ended September 30, 2015 relative to the same period in 2014 is primarily related to increased production volumes in the Parkland and Tower areas. In the second half of 2014 and first quarter of 2015, new volumes of crude oil and NGLs were transported by truck which, at times, could result in large wait time charges. Beginning in the second quarter of 2015, all crude oil volumes from the Tower area are transported via pipeline, however pipeline tariff increases largely offset the decrease in trucking charges.

G&A Expenses and Share-Based Compensation

G&A, prior to share-based compensation expense and net of capitalized G&A and overhead recoveries on operated properties, decreased by four per cent to $14.1 million in the third quarter of 2015 from $14.7 million in the third quarter of 2014. While G&A expenses before the impact of recoveries and capitalized G&A saw a modest decrease from the third quarter of 2014 to the third quarter of 2015, there was a 25 per cent reduction in capitalized G&A and overhead recoveries during the same period. This reduction is related to reduced capital spending in the quarter.

For the nine months ended September 30, 2015, ARC's G&A, prior to share-based compensation expense and net of capitalized G&A and overhead recoveries on operated properties, was $48.3 million, a $4.1 million increase from the same period in 2014, reflecting decreased capitalized G&A and recoveries from partners associated with lower capital spending.

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Table 17 is a breakdown of G&A and share-based compensation expenses:

Table 17

	Three Months Ended						Nine Months Ended
	September 30						September 30
G&A and Share-Based Compensation	2015		2014		% Change		2015		2014		% Change
($ millions, except per boe)
G&A expenses (1)	23.2		26.8		(13	)	75.4		80.0		(6	)
Capitalized G&A and overhead recoveries	(9.1	)	(12.1	)	(25	)	(27.1	)	(35.8	)	(24	)
G&A expenses before share-based compensation plans	14.1		14.7		(4	)	48.3		44.2		9
G&A – share-based compensation plans (2)	6.6		4.7		40		6.3		14.1		(55	)
Total G&A and share-based compensation expenses	20.7		19.4		7		54.6		58.3		(6	)
Total G&A and share-based compensation expenses per boe	2.10		1.83		15		1.78		1.93		(8	)

(1) Includes expenses recognized under the DSU Plan.

(2) Comprised of expenses recognized under the RSU, PSU, Stock Option Plan and Long-term Restricted Share Award ("LTRSA") Plans.

Share-Based Compensation Plans – Restricted Share Unit & Performance Share Unit Plan, Share Option Plan, Deferred Share Unit Plan, and Long-term Restricted Share Award Plan

Restricted Share Unit and Performance Share Unit Plan

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

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

ARC recorded G&A expenses of $5.6 million during the third quarter of 2015 in accordance with the RSU and PSU Plan, as compared to an expense of $3.9 million during the third quarter of 2014. For the nine months ended September 30, 2015, ARC recorded an expense related to the RSU and PSU Plan of $3 million, a decrease of $9.1 million or 75 per cent from the nine months ended September 30, 2014. ARC recognized an increase in compensation charges for the third quarter of 2015 as compared to the third quarter of 2014 due to a higher estimated performance multiplier for its PSU rewards relative to what ARC had been estimating at the end of the prior quarter. The decrease for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014 is due to reduction to the valuation of awards at September 30, 2015, as ARC's share price decreased from $25.16 per share at December 31, 2014 to $17.64 at September 30, 2015.

During the nine months endedSeptember 30, 2015, ARC made cash payments of $10.9 million in respect of the RSU and PSU Plan ($39.4 million for the nine months endedSeptember 30, 2014). Of these payments, $8.4 million were in respect of amounts recorded to G&A expenses ($28.9 million for the nine months endedSeptember 30, 2014) and $2.5 million were in respect of amounts recorded to operating expenses and capitalized as PP&E and E&E assets ($10.5 million for the nine months endedSeptember 30, 2014). These amounts were accrued in prior periods.

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Table 18 shows the changes to the RSU and PSU Plan during 2015:

Table 18

RSU and PSU Plan (number of units, thousands)	RSUs	PSUs(1)	Total RSUs and PSUs
Balance, December 31, 2014	625	1,513	2,138
Granted	464	702	1,166
Distributed	(294)	(493)	(787)
Forfeited	(60)	(50)	(110)
Balance, September 30, 2015	735	1,672	2,407

(1) Based on underlying units before any effect of the performance multiplier.

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

Due to the variability in the future payments under the plan, ARC estimates that between $13.3 million and $74.4 million will be paid out in 2016 through 2018 based on the current share price, accrued dividends, and ARC’s market performance relative to its peers. Table 19 is a summary of the range of future expected payments under the RSU and PSU Plan based on variability of the performance multiplier and units outstanding under the RSU and PSU Plan as at September 30, 2015:

Table 19

Value of RSU and PSU Plan as at
September 30, 2015	Performance multiplier
(units thousands and $ millions, except per share)	—	1.0	2.0
Estimated units to vest
RSUs	754	754	754
PSUs	—	1,733	3,466
Total units (1)	754	2,487	4,220
Share price (2)	17.64	17.64	17.64
Value of RSU and PSU Plan upon vesting (3)	13.3	43.9	74.4
2016	6.2	16.0	25.7
2017	4.4	12.9	21.4
2018	2.7	15.0	27.3

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

(2) Values will fluctuate over the vesting period based on the volatility of the underlying share price. Assumes a future share price of $17.64, which is based on the closing share price at September 30, 2015.

(3) Upon vesting, a cash payment is made for the value of the share units, equivalent to the current market price of the underlying common shares plus accrued dividends.

Share Option Plan

Share options are granted to employees and consultants of ARC, vesting evenly on the fourth and fifth anniversaries of their respective grant dates, and have a maximum term of seven years. The option holder has the right to exercise the options at the original exercise price or at a reduced exercise price, equal to the exercise price at grant date less all dividends paid subsequent to the grant date and prior to the exercise date. On June 24, 2015, ARC granted 998,545 options to officers and certain employees at ARC.

At September 30, 2015, ARC had 3.4 million share options outstanding under this plan, representing less than one per cent of outstanding shares, with a weighted average exercise price of $22.25 per share. At September 30, 2015, approximately 176,000 share options were exercisable with a weighted average exercise price of $21.71 per share. Compensation expense of $1 million has been recorded during the third quarter of 2015 ($2.5 million for the nine months ended September 30, 2015) compared to $0.8 million for the third quarter of 2014 ($1.9 million for the nine months ended September 30, 2014), and is included within G&A expenses.

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Deferred Share Unit Plan

ARC has a DSU Plan for its non-employee directors under which each director receives a minimum of 60 per cent of their total annual remuneration in the form of DSUs. Each DSU fully vests on the date of grant but is settled in cash only when the director has ceased to be a member of the Board. For the three and nine months ended September 30, 2015, a G&A recovery of $0.4 million was recorded in relation to the DSU Plan (expense of less than $0.1 million and $1.3 million in 2014).

Long-term Restricted Share Award Plan

On April 30, 2015, at its Annual and Special Meeting of Shareholders, ARC shareholders approved a new Long-term Restricted Share Award ("LTRSA") Plan to award shares of ARC to qualifying officers and employees. With a ten year term and vesting evenly on the eighth, ninth and tenth anniversary of their respective grant dates, the LTRSA is intended to further align participant compensation with the interests of ARC and its shareholders over the long-term.

LTRSA grants consist of restricted common shares that are awarded at the date of grant and a cash payment made equal to the estimated personal tax obligation associated with the total award. The restricted shares issued on the grant date of the award are held in trust until the vesting conditions have been met.

While in trust, the restricted shares earn dividends which are reinvested into ARC common shares via the stock dividend program. These common shares issued through the stock dividend program are also held in trust until vested. Each LTRSA vests evenly on the eighth, ninth, and tenth anniversaries of their respective grant dates. Restricted shares and any accrued dividends that are subject to forfeiture will be redeemed and canceled by ARC.

Compensation expense associated with the cash payment is recognized at the fair value on the grant date, while expense associated with the restricted common shares is estimated as the fair value of the award equal to the previous five-day weighted average trading price of ARC shares on the grant date and is recognized over the vesting period.

At September 30, 2015, ARC had 100,287 restricted shares outstanding under this plan. For the three and nine months ended September 30, 2015, G&A expenses have been recorded of $nil and $0.7 million, respectively, relating to the cash payment under the LTRSA Plan ($nil for the three and nine months ended September 30, 2014).

Interest and Financing Charges

Interest and financing charges increased thirteen per cent to $12.7 million in the third quarter of 2015 from $11.2 million in the third quarter of 2014. For the nine months ended September 30, 2015, interest and financing charges were $37.7 million as compared to $34.4 million in 2014, an increase of ten per cent. The increase in interest charges primarily reflects the increased value of the US dollar relative to the Canadian dollar during the second and third quarters of 2015 as compared to the second and third quarters of 2014 as ARC's debt and related interest obligations are primarily held in US dollars.

At September 30, 2015, ARC had $1.09 billion of long-term debt outstanding, including a current portion of $56.3 million that is due for repayment within the next 12 months. ARC's debt balance is fixed at a weighted average interest rate of 4.45 per cent. Approximately 96 per cent (US$781.4 million) of ARC’s debt outstanding is denominated in US dollars.

Foreign Exchange Gains and Losses

ARC recorded a foreign exchange loss of $72.2 million in the third quarter of 2015 compared to a loss of $37.8 million in the third quarter of 2014. The loss is primarily attributed to the unrealized loss associated with the revaluation of ARC’s US dollar denominated debt outstanding from the period of June 30, 2015 to September 30, 2015 and reflects the change in value of the US dollar relative to the Canadian dollar from $1.247 to $1.339.

For the nine months ended September 30, 2015, ARC recorded a foreign exchange loss of $143.9 million compared to a loss of $41.4 million for the same period in the prior year. On average, during the nine months ended September 30, 2014, the value of the US dollar relative to the Canadian dollar increased $0.058 from $1.063 at December 31, 2013 to $1.121 at September 30, 2014. During the nine months ended September 30, 2015, the value of the US dollar relative to the Canadian dollar increased $0.179 from $1.160 at December 31, 2014 to $1.339 at September 30, 2015, resulting in an increased unrealized loss on the revaluation of ARC's US dollar denominated debt.

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

Table 20

	Three Months Ended					Nine Months Ended
	September 30					September 30
Foreign Exchange Gains and Losses ($ millions)	2015		2014		% Change	2015		2014		% Change
Unrealized loss on US denominated debt	(72.2	)	(37.8	)	91	(143.6	)	(41.1	)	249
Realized loss on US denominated transactions	—		—		—	(0.3	)	(0.3	)	—
Total foreign exchange loss	(72.2	)	(37.8	)	91	(143.9	)	(41.4	)	248

Taxes

ARC recorded a current income tax recovery of $10.1 million in the third quarter of 2015 ($6 million recovery for the nine months ended September 30, 2015) compared to $17 million expense during the third quarter of 2014 ($64 million expense for the nine months ended September 30, 2014). The reduction in current taxes for both the third quarter and the first nine months of 2015 reflects lower expected annual taxable income for 2015 related to decreased commodity prices.

During the third quarter of 2015, a deferred income tax recovery of $48.1 million was recorded ($10 million recovery for the nine months ended September 30, 2015) compared to an expense of $20.6 million in the third quarter of 2014 ($35.6 million expense for the nine months ended September 30, 2014). For the three and nine months ended September 30, 2015 as compared to the three and nine months ended September 30, 2014, ARC’s decrease in deferred tax expense primarily relates to the third quarter impairment charge which reduced the book basis of ARC's assets relative to their tax basis, slightly offset by unrealized gains recorded on risk management contracts.

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

Table 21

Income Tax Pool Type ($ millions)	September 30, 2015	Annual Deductibility
Canadian oil and gas property expense	639.5	10% declining balance
Canadian development expense	917.7	30% declining balance
Canadian exploration expense	—	100	%
Undepreciated capital cost	797.0	Primarily 25% declining balance
Other	21.7	Various rates, 7% declining balance to 20%
Total federal tax pools	2,375.9
Additional Alberta tax pools	17.2	Various rates, 25% declining balance to 100%

DD&A Expense and Impairment Charges

ARC records DD&A expense on its PP&E over the individual useful lives of the assets employing the unit of production method using proved plus probable reserves and associated estimated future development capital required for its crude oil and natural gas assets, and a straight-line method for its corporate administrative assets. Assets in the E&E phase are not amortized. For the three and nine months ended September 30, 2015, ARC recorded DD&A expense prior to any impairment of $146.3 million and $464.1 million as compared to $168.9 million and $479.1 million for the three and nine months ended September 30, 2014. The decrease in DD&A expense for the three months ended September 30, 2015 of $14.83 per boe compared to $15.89 per boe for the same period of the prior year reflects reduced capital spending on infrastructure. The decrease in DD&A expense for the nine months ended September 30, 2015 of $15.12 per boe compared to $15.88 per boe for the same period of the prior year also reflects the effect of reduced capital spending.

Impairment is recognized when the carrying value of an asset or group of assets exceeds its recoverable amount, defined as the higher of its value in use or fair value less costs of disposal. Any asset impairment that is recorded is recoverable to its original value less any associated DD&A expense should there be indicators that the recoverable amount of the asset has increased in value since the time of recording the initial impairment. At September 30, 2015, ARC evaluated its CGUs for indicators of any potential impairment or related recovery and as a result of continued declines in forward commodity prices for crude oil and natural gas, impairment tests were conducted.

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For the three months ended September 30, 2015, impairment charges of $326.6 million ($240.4 million net of deferred tax recovery) ($nil for the three months ended September 30, 2014) were recognized; $320 million due to a decline in expected future commodity prices and $6.6 million in relation to the disposition of non-core assets located in the Southern Alberta & Southwest Saskatchewan CGU. For the nine months endedSeptember 30, 2015, impairment charges of $338.3 million ($249.1 million net of deferred tax recovery) ($nil in the nine months ended September 30, 2014) were recognized; $320 million due to a decline in expected future commodity prices and $18.3 million in relation to the disposition of non-core assets located in the Southern Alberta & Southwest Saskatchewan CGU.

The results of the September 30, 2015 impairment test are sensitive to changes in any of the key judgments, such as a revision in reserves or resources, a change in forecast commodity prices, expected royalties, required future development expenditures or expected future production costs, which could decrease or increase the recoverable amounts of assets and result in additional impairment charges or recovery of impairment charges. For further information regarding the impairment charge for September 30, 2015, refer to Note 6 "Impairment" in the financial statements for the three and nine months ended September 30, 2015.

A breakdown of DD&A expense and impairment charges is summarized in Table 22:

Table 22

	Three Months Ended				Nine Months Ended
	September 30				September 30
DD&A Expense and Impairment Charges ($ millions, except per boe amounts)	2015	2014	% Change		2015	2014	% Change
Depletion of oil and gas assets	144.8	167.4	(14	)	459.4	474.5	(3	)
Depreciation of administrative assets	1.5	1.5	—		4.7	4.6	2
Impairment charges	326.6	—	100		338.3	—	100
Total DD&A expense and impairment charges	472.9	168.9	180		802.4	479.1	67
DD&A rate before impairment per boe	14.83	15.89	(7	)	15.12	15.88	(5	)
DD&A and impairment rate per boe	47.92	15.89	202		26.14	15.88	65

During the three and nine months ended September 30, 2015, ARC recorded impairment charges on E&E assets of $2.5 million and $46.9 million, respectively. Impairment of E&E assets are presented as part of intangible E&E expenses in the statements of income (loss).

Capital Expenditures, Acquisitions and Dispositions

Capital expenditures before acquisitions, dispositions or purchases of undeveloped land totaled $164.2 million in the third quarter of 2015 as compared to $218.2 million during the third quarter of 2014. This total includes development and production additions to PP&E of $144.7 million and additions to E&E assets of $19.5 million. PP&E expenditures include additions to oil and gas development and production assets and administrative assets. E&E expenditures include asset additions in areas that have been determined by Management to be in the E&E stage.

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A breakdown of capital expenditures, acquisitions and dispositions is shown in Table 23 and 23a:

Table 23

	Three Months Ended September 30
	2015						2014
Capital Expenditures ($ millions)	E&E		PP&E		Total		E&E		PP&E		Total		% Change
Geological and geophysical	5.1		2.9		8.0		—		3.5		3.5		129
Drilling and completions	14.4		103.5		117.9		11.8		143.1		154.9		(24	)
Plant and facilities	—		37.8		37.8		3.5		55.3		58.8		(36	)
Administrative assets	—		0.5		0.5		—		1.0		1.0		(50	)
Total capital expenditures	19.5		144.7		164.2		15.3		202.9		218.2		(25	)
Undeveloped land	—		0.6		0.6		0.8		21.1		21.9		(97	)
Total capital expenditures including undeveloped land purchases	19.5		145.3		164.8		16.1		224.0		240.1		(31	)
Acquisitions (1)	—		—		—		1.8		35.5		37.3		(100	)
Dispositions (2)	(7.6	)	(13.1	)	(20.7	)	(1.8	)	(3.3	)	(5.1	)	306
Total capital expenditures, land purchases and net acquisitions and dispositions	11.9		132.2		144.1		16.1		256.2		272.3		(47	)

(1) Excludes $18.1 million of non-cash petroleum and natural gas property transactions in the third quarter of 2015 ($nil in the third quarter of 2014).

(2) Represents proceeds and adjustments to proceeds from divestitures.

For the nine months ended September 30, 2015, capital expenditures before property acquisitions, dispositions or purchases of undeveloped land totaled $392.1 million as compared to $696.3 million during the same period of 2014. This total includes development and production additions to PP&E of $371.8 million and additions to E&E assets of $20.3 million.

During the third quarter of 2015, ARC divested of certain non-core oil assets located in Southwestern Saskatchewan. The divested properties had oil production of approximately 500 boe per day and three MMboe of proved plus probable oil and gas reserves.

Table 23a

	Nine Months Ended September 30
	2015						2014
Capital Expenditures ($ millions)	E&E		PP&E		Total		E&E		PP&E		Total		% Change
Geological and geophysical	5.1		8.3		13.4		1.4		11.5		12.9		4
Drilling and completions	14.9		237.8		252.7		28.3		467.3		495.6		(49	)
Plant and facilities	0.3		124.4		124.7		14.6		168.6		183.2		(32	)
Administrative assets	—		1.3		1.3		—		4.6		4.6		(72	)
Total capital expenditures	20.3		371.8		392.1		44.3		652.0		696.3		(44	)
Undeveloped land	—		2.1		2.1		0.8		43.5		44.3		(95	)
Total capital expenditures including undeveloped land purchases	20.3		373.9		394.2		45.1		695.5		740.6		(47	)
Acquisitions (1)	14.1		—		14.1		1.8		71.7		73.5		(81	)
Dispositions (2)	(7.6	)	(39.0	)	(46.6	)	(1.8	)	(35.1	)	(36.9	)	26
Total capital expenditures, land purchases and net acquisitions and dispositions	26.8		334.9		361.7		45.1		732.1		777.2		(53	)

(1) Excludes $28.7 million of non-cash petroleum and natural gas property transactions in the nine months ended September 30, 2015 ($1.9 million in the nine months ended September 30, 2014).

(2) Represents proceeds and adjustments to proceeds from divestitures.

ARC finances its capital expenditures with funds from operations that are available after deducting current period expenditures on site restoration and reclamation, net reclamation fund contributions, and dividends declared in the current period. Further funding is obtained by contributions from DRIP, SDP, debt and equity. ARC financed 71 per cent

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of the $164.7 million third quarter capital program with funds from operations (91 per cent financed with funds from operations and contributions from DRIP and SDP in the third quarter of 2014).

During the nine months ended September 30, 2015, ARC has divested of certain non-core assets located in South Central Alberta and Southwestern Saskatchewan. In aggregate, the divested properties had associated natural gas production of approximately 2,400 boe per day and 12 MMboe of proved plus probable natural gas reserves and oil production of approximately 500 boe per day and three MMboe of proved plus probable oil and gas reserves.

Table 24

	Three Months Ended September 30
	2015			2014
Source of Funding of Capital Expenditures and Acquisitions ($ millions)	Capital Expenditures including Land Purchases	Acquisitions	Total Expenditures	Capital Expenditures including Land Purchases	Acquisitions	Total Expenditures
Expenditures (1)	164.7	—	164.7	239.8	37.3	277.1
Funds from operations, net (%) (2)	40	—	40	75	—	65
Contributions from DRIP and SDP (%)	31	—	31	16	—	14
Debt (%)	29	—	29	9	100	21
Total (%)	100	—	100	100	100	100

(1) Excludes capital expenditures attributable to non-cash stock options and non-cash property transactions, as well as proceeds from net dispositions.

(2) Refer to the sections entitled "Funds from Operations" and “Additional GAAP Measures” contained within this MD&A. The percentage of capital expenditures that have been funded by funds from operations is determined as funds from operations that are available after deducting current period expenditures on site restoration and reclamation, net reclamation fund contributions, and dividends declared in the current period.

Table 24a

	Nine Months Ended September 30
	2015			2014
Source of Funding of Capital Expenditures and Acquisitions ($ millions)	Capital Expenditures including Land Purchases	Acquisitions	Total Expenditures	Capital Expenditures including Land Purchases	Acquisitions	Total Expenditures
Expenditures (1)	394.0	14.1	408.1	740.3	73.5	813.8
Funds from operations, net (%) (2)	66	—	64	77	—	70
Contributions from DRIP and SDP (%)	33	100	35	15	—	14
Debt (%)	1	—	1	8	100	16
Total (%)	100	100	100	100	100	100

(1) Excludes capital expenditures attributable to non-cash stock options and non-cash property transactions, as well as proceeds from net dispositions.

(2) Refer to the sections entitled "Funds from Operations" and “Additional GAAP Measures” contained within this MD&A. The percentage of capital expenditures that have been funded by funds from operations is determined as funds from operations that are available after deducting current period expenditures on site restoration and reclamation, net reclamation fund contributions, and dividends declared in the current period.

Asset Retirement Obligations and Reclamation Fund

At September 30, 2015, ARC has recorded an ARO of $582.4 million ($616.1 million at December 31, 2014) for the future abandonment and reclamation of ARC’s properties. The estimated ARO includes assumptions in respect of actual costs to abandon wells or reclaim the property, the time frame in which such costs will be incurred, as well as annual inflation factors in order to calculate the undiscounted total future liability. The future liability has been discounted at a liability-specific risk-free interest rate of 2.2 per cent (2.3 per cent at December 31, 2014).

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Accretion charges of $3.3 million and $10.1 million for the three and nine months ended September 30, 2015 ($3.6 million and $11.2 million for 2014), respectively, have been recognized in the statements of income (loss) to reflect the increase in the ARO liability associated with the passage of time.

Actual spending under ARC’s abandonment and reclamation program for the three and nine months ended September 30, 2015 was $4.5 million and $8.1 million ($8.0 millionand$14.3 million for 2014), respectively.

In 2005, ARC established a restricted reclamation fund to finance obligations specifically associated with its Redwater property. Minimum contributions to this fund will be approximately $62 million in total over the next 40 years. The balance of this fund totaled $33.2 million at September 30, 2015, compared to $35.2 million at December 31, 2014. Under the terms of ARC’s investment policy, cash in the reclamation fund can only be invested in certain securities and require a minimum credit rating for investments of A or higher.

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

Capitalization, Financial Resources and Liquidity

A breakdown of ARC’s capital structure as at September 30, 2015 and December 31, 2014 is outlined in Table 25:

Table 25

Capital Structure and Liquidity ($ millions, except per cent and ratio amounts)	September 30, 2015		December 31, 2014
Long-term debt (1)	1,092.5		1,074.8
Working capital deficit (surplus) (2)	(111.4	)	181.1
Net debt obligations (3)	981.1		1,255.9
Market value of common shares (4)	6,071.7		8,036.1
Total capitalization (3)	7,052.8		9,292.0
Net debt as a percentage of total capitalization	13.9		13.5
Net debt to annualized funds from operations (3)	1.3		1.1

(1) Includes a current portion of long-term debt of $56.3 million at September 30, 2015 and $49.5 million at December 31, 2014.

(2) Working capital deficit is calculated as current liabilities less current assets as they appear on the condensed interim consolidated balance sheets (the "balance sheets"), and excludes current unrealized amounts pertaining to risk management contracts, assets held for sale and ARO contained within liabilities associated with assets held for sale, as well as the current portion of long-term debt and current portion of ARO.

(3) Refer to the section entitled "Additional GAAP Measures” contained within this MD&A.

(4) Calculated using the total common shares outstanding at September 30, 2015 multiplied by the closing share price of $17.64 at September 30, 2015 (closing share price of $25.16 at December 31, 2014).

At September 30, 2015, ARC had total available credit facilities of approximately $2.3 billion with debt of $1.09 billion currently drawn. ARC’s long-term debt balance includes a current portion of $56.3 million at September 30, 2015 ($49.5 million at December 31, 2014), reflecting principal payments that are due to be paid within the next 12 months. ARC intends to finance these obligations by using cash on hand or drawing on its syndicated credit facility at the time the payments are due.

On October 26, 2015, ARC extended its syndicated revolving credit facility for one additional year until November 6, 2019 at existing terms.

On January 29, 2015, ARC issued 17.9 million common shares for aggregate gross proceeds of $402.7 million (net proceeds of $386.1 million) on a bought deal basis. The proceeds from this offering were used to temporarily reduce bank indebtedness, increase working capital and to fund ongoing capital expenditure programs.

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ARC’s debt agreements contain a number of covenants, all of which were met as at September 30, 2015. These agreements are available at www.sedar.com. ARC calculates its covenants four times annually. The major financial covenants are described below:

Table 26

Covenant description	Estimated Position at September 30, 2015 (1)
Long-term debt and letters of credit not to exceed three and a quarter times annualized net income before non-cash items, income taxes and interest expense	1.3
Long-term debt, letters of credit, and subordinated debt not to exceed four times annualized net income before non-cash items, income taxes and interest expense	1.3
Long-term debt and letters of credit not to exceed 50 per cent of the book value of shareholders’ equity and long-term debt, letters of credit and subordinated debt	0.2

(1) Estimated position, subject to final approval.

ARC’s long-term strategy is to target net debt between one and 1.5 times annualized funds from operations and less than 20 per cent of total capitalization. This strategy has resulted in manageable debt levels to date and has positioned ARC to remain well within its debt covenants.

ARC typically uses three markets to raise capital: equity, bank debt and long-term notes. Long-term notes are issued to large institutional investors normally with an average term of five to 12 years. The cost of this debt is based upon two factors: the current rate of long-term government bonds and ARC’s credit spread. ARC’s weighted average interest rate on its outstanding long-term notes is currently 4.45 per cent.

Shareholders’ Equity

At September 30, 2015, there were 344.2 million shares outstanding, an increase of 24.8 million shares compared to December 31, 2014. During the first quarter of 2015, ARC issued 17.9 million shares for aggregate gross proceeds of $402.7 million. The remaining 6.9 million shares issued are attributable to those issued to participants in the DRIP and SDP.

At September 30, 2015, ARC had 3.4 million share options outstanding under its Share Option Plan, representing less than one per cent of outstanding shares, with a weighted average exercise price of $22.25 per share. These options vest in equal parts on the fourth and fifth anniversaries of the grant date. At September 30, 2015, approximately 0.2 million share options were exercisable with a weighted average exercise price of $21.71 per share.

At September 30, 2015, ARC had 100,287 restricted shares outstanding under its Long-term Restricted Share Award Plan. These awards vest evenly on the eighth, ninth and tenth anniversaries of the grant date. For more information on the restricted shares outstanding and held in trust under ARC's LTRSA Plan, refer to the section entitled "Long-term Restricted Share Award Plan” contained within this MD&A.

Dividends

In the third quarter of 2015, ARC declared dividends totaling $103 million ($0.30 per share) compared to $95.2 million ($0.30 per share) during the third quarter of 2014.

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

• To maintain a dividend policy that, in normal times, in the opinion of Management and the Board, is sustainable after factoring in the impact of current commodity prices on funds from operations. ARC’s objective is to normalize the effect of volatility of commodity prices rather than to pass that volatility onto shareholders in the form of fluctuating monthly dividends.

• To maintain ARC’s financial flexibility, by reviewing ARC’s level of debt to equity and debt to funds from operations. The use of funds from operations and proceeds from equity offerings to fund capital development activities reduces the need to use debt to finance these expenditures.

ARC is focused on value creation, with the dividend being a key component of its business strategy. ARC believes that it is positioned to sustain current dividend levels despite the volatile commodity price environment. ARC’s third quarter dividend was equal to 59 per cent of third quarter 2015 funds from operations.

ARC Resources Ltd. Page 25

The actual amount of future monthly dividends is proposed by Management and is subject to the approval and discretion of the Board. The Board reviews future dividends in conjunction with their review of quarterly financial and operating results. Dividends are taxable to the shareholder irrespective of whether payment is received in cash or shares via the DRIP. In the case of shares issued via the SDP, dividends received are converted to a future capital gain to the recipient. Shareholders should consult their own tax advisors with respect to tax implications of dividends received in cash or via the DRIP or SDP in their particular circumstances.

On October 16, 2015, ARC confirmed that a dividend of $0.10 per common share designated as an eligible dividend will be paid on November 16, 2015 to shareholders of record on October 30, 2015 with an ex-dividend date of October 28, 2015.

Please refer to ARC’s website at www.arcresources.com for details of the estimated monthly dividend amounts and dividend dates for 2015.

Environmental Initiatives Impacting ARC

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

Contractual Obligations and Commitments

During the three and nine months ended September 30, 2015, ARC increased its transportation commitments by approximately $8.3 million and $90.4 million, respectively, from those presented at December 31, 2014. The increase relates to additional firm natural gas transportation that ARC committed to support the movement of ARC's natural gas production, with payments commencing in 2015 and to be incurred until 2027. There were no other material changes to ARC's commitments and contingencies from those presented as at December 31, 2014.

Off-Balance Sheet Arrangements

ARC has certain lease agreements which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases on the balance sheet as of September 30, 2015.

Critical Accounting Estimates

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

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

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

• estimated capital expenditures on projects that are in progress;

• estimated DD&A charges that are based on estimates of oil and gas reserves that ARC expects to recover in the future;

• estimated fair values of financial instruments that are subject to fluctuation depending upon the underlying commodity prices, foreign exchange rates and interest rates, volatility curves and the risk of non-performance;

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

• estimated future recoverable value of PP&E, E&E and goodwill and any associated impairment charges or recoveries; and

• estimated compensation expense under ARC’s share-based compensation plans including the PSU Plan that is based on an adjustment to the final number of PSU awards that eventually vest based on a performance multiplier, the Share Option Plan and the LTRSA Plan.

ARC has hired individuals and consultants who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates. For further information on the determination of certain estimates inherent in the financial statements, refer to Note 5 “Management Judgments and Estimation Uncertainty” in the audited

ARC Resources Ltd. Page 26

consolidated financial statements for the year ended December 31, 2014 and refer to Note 6 "Impairment" in the financial statements for the three and nine months ended September 30, 2015.

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

ASSESSMENT OF BUSINESS RISKS

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

• volatility of oil and natural gas prices;

• refinancing and debt service;

• access to capital markets;

• retention of key personnel;

• operational matters;

• reserves and resources estimates;

• depletion of reserves and maintenance of dividend;

• counterparty risk;

• variations in interest rates and foreign exchange rates;

• changes in income tax legislation;

• changes in government royalty legislation;

• acquisitions;

• environmental concerns and related impact on operations; and

• regulation of the oil and natural gas industry by various levels of government and governmental agencies.

Additional information is available in ARC’s Annual Information Form that is filed on SEDAR at www.sedar.com.

PROJECT RISKS

ARC manages a variety of small and large projects and plans to continue with the development of several capital projects throughout 2015. Project delays may impact expected revenues from operations. Significant project cost overruns could make a project uneconomic. ARC's ability to execute projects and market oil and natural gas depends upon numerous factors beyond its control, including:

• availability of processing capacity;

• availability and proximity of pipeline capacity;

• availability of storage capacity;

• supply of and demand for oil and natural gas;

• availability of alternative fuel sources;

• effects of inclement weather;

• availability of drilling and related equipment;

ARC Resources Ltd. Page 27

• unexpected cost increases;

• accidental events;

• changes in regulations; and

• availability and productivity of skilled labour.

Because of these factors, ARC could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that ARC produces.

Internal Control over Financial Reporting

ARC is required to comply with National Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings,” otherwise referred to as Canadian Sarbanes Oxley (“C-Sox”). The certification of interim filings for the interim period ended September 30, 2015 requires that ARC disclose in the interim MD&A any changes in ARC’s internal control over financial reporting that occurred during the period that have materially affected, or are reasonably likely to materially affect, ARC’s internal control over financial reporting. ARC confirms that no such changes were made to its internal controls over financial reporting during the three months ended September 30, 2015.

FINANCIAL REPORTING UPDATE

Future Accounting Policy Changes

In May 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers," which replaces IAS 18 "Revenue," IAS 11 "Construction Contracts," and related interpretations. In September 2015, the IASB formalized the deferral of the effective date of IFRS 15 by one year, to January 1, 2018. The standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted. IFRS 15 will be applied by ARC on January 1, 2018 and the Company is currently evaluating the impact of the standard on ARC's financial statements.

In July 2014, the IASB completed the final elements of IFRS 9 "Financial Instruments." The Standard supersedes earlier versions of IFRS 9 and completes the IASB’s project to replace IAS 39 "Financial Instruments: Recognition and Measurement." IFRS 9, as amended, includes a principle-based approach for classification and measurement of financial assets, a single 'expected loss’ impairment model and a substantially-reformed approach to hedge accounting. The Standard will come into effect for annual periods beginning on or after January 1, 2018, with earlier adoption permitted. IFRS 9 will be applied by ARC on January 1, 2018 and the Company is currently evaluating the impact of the standard on ARC's financial statements.

In October 2015, the IASB voted on the effective date of IFRS 16 "Leases" which replaces IAS 17 "Leases." The IASB is expected to issue the standard in 2015. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted if the entity is also applying IFRS 15 "Revenue from Contracts with Customers." IFRS 16 will be applied by ARC on January 1, 2019 and the Company is currently evaluating the impact of the standard on ARC's financial statements.

Non-GAAP Measures

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

Additional GAAP Measures

All additional GAAP Measures described below do not have a standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities.

Funds from Operations

Funds from operations is defined as net income excluding the impact of non-cash DD&A and impairment charges, accretion of ARO, E&E expense, deferred tax expense and recovery, unrealized gains and losses on risk management

ARC Resources Ltd. Page 28

contracts, unrealized gains and losses on foreign exchange, gains on disposal of petroleum and natural gas properties, unrealized gains and losses on short-term investments, non-cash lease inducement charges, share-based compensation expense, and is further adjusted to include any portion of unrealized gains and losses on risk management contracts settled annually that relate to current period production. ARC considers funds from operations to be a key measure of operating performance as it demonstrates ARC’s ability to generate the necessary funds to fund future growth through capital investment and to repay debt. Management believes that such a measure provides a better assessment of ARC’s operations on a continuing basis by eliminating certain non-cash charges and charges that are nonrecurring, while respecting that certain risk management contracts that are settled on an annual basis are intended to protect prices on product sales occurring throughout the year. From a business perspective, the most directly comparable measure of funds from operations calculated in accordance with GAAP is net income.

Net Debt

Net debt is defined as long-term debt plus working capital surplus or deficit. Working capital surplus or deficit is calculated as current liabilities less current assets as they appear on the balance sheets, and excludes current unrealized amounts pertaining to risk management contracts, assets held for sale and ARO contained within liabilities associated with assets held for sale, as well as the current portion of long-term debt and current portion of ARO.

Total Capitalization

Total capitalization is defined as total shares outstanding multiplied by the closing share price on the Toronto Stock Exchange plus net debt outstanding. Total capitalization is used by ARC in analyzing its balance sheet strength and liquidity.

Forward-looking Information and Statements

This MD&A contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect," "anticipate," "continue," "estimate," "objective," "ongoing," "may," "will," "project," "should," "believe," "plans," "intends," "strategy," and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this MD&A contains forward-looking information and statements pertaining to the following: ARC’s financial goals under the heading “About ARC Resources Ltd.," ARC’s view of future crude oil, natural gas, condensate and NGLs pricing under the heading “Economic Environment,” ARC’s guidance for 2015 under the heading “2015Annual Guidance and Financial Highlights,” ARC’s intentions in the future regarding hedging under the heading “Risk Management,” ARC’s view as to the estimated future payments under the RSU and PSU Plan under the heading “Share-Based Compensation Plans – Restricted Share Unit & Performance Share Unit Plan, Share Option Plan, Deferred Share Unit Plan, and Long-term Restricted Share Award Plan,” the financing information relating to raising capital under the heading "Capitalization, Financial Resources and Liquidity," ARC's belief in relation to maintaining current dividend levels under the heading "Dividends," ARC’s estimates of normal course obligations under the heading “Contractual Obligations and Commitments,” and a number of other matters, including the amount of future asset retirement obligations, future liquidity and financial capacity, future results from operations and operating metrics, future costs, expenses and royalty rates, future interest costs, and future development, exploration, acquisition and development activities (including drilling plans) and related capital expenditures.

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

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

ARC Resources Ltd. Page 29

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

ARC Resources Ltd. Page 30

GLOSSARY

The following is a list of abbreviations that may be used in this MD&A:

Measurement

bbl        barrel

bbl/d        barrels per day

Mbbls        thousand barrels

MMbbls        million barrels

boe ⁽¹⁾        barrels of oil equivalent

boe/d ⁽¹⁾        barrels of oil equivalent per day

Mboe ⁽¹⁾        thousands of barrels of oil equivalent

MMboe ⁽¹⁾    millions of barrels of oil equivalent

Mcf        thousand cubic feet

Mcf/d        thousand cubic feet per day

MMcf        million cubic feet

MMcf/d        million cubic feet per day

Bcf        billion cubic feet

MMbtu        million British Thermal Units

GJ        gigajoule

(1) Where applicable in this MD&A natural gas has been converted to boe based on a conversion ratio of six Mcf to one bbl. The boe rate is based on an energy equivalent 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 a conversion ratio of 6:1 may be misleading as an indication of value.

Financial and Business Environment

ARO        asset retirement obligations

CGU        cash-generating unit

DD&A        depletion, depreciation and amortization

DRIP        Dividend Reinvestment Program

DSU        Deferred Share Unit

E&E        intangible exploration and evaluation

GAAP        generally accepted accounting principles

G&A        general and administrative

IASB        International Accounting Standards Board

IFRS        International Financial Reporting Standards

LTRSA        Long-term Restricted Share Award

MSW        Mixed Sweet Blend

NGLs        natural gas liquids

NYMEX        New York Mercantile Exchange

PP&E        property, plant and equipment

PSU        Performance Share Unit

RSU        Restricted Share Unit

SDP        Stock Dividend Program

WTI        West Texas Intermediate

ARC Resources Ltd. Page 31

QUARTERLY HISTORICAL REVIEW

($ millions, except per share amounts)	2015						2014							2013
FINANCIAL	Q3		Q2		Q1		Q4		Q3		Q2		Q1	Q4
Sales of crude oil, natural gas, condensate, NGLs and other income	279.5		321.7		306.6		454.1		535.2		567.0		551.4	425.0
Per share, basic (1)	0.82		0.95		0.92		1.43		1.69		1.79		1.75	1.36
Per share, diluted (1)	0.82		0.94		0.92		1.42		1.68		1.79		1.75	1.35
Funds from operations (2)	174.9		206.3		191.5		251.7		284.2		295.8		292.3	237.8
Per share, basic (1)	0.51		0.61		0.57		0.79		0.90		0.94		0.93	0.76
Per share, diluted (1)	0.51		0.61		0.57		0.79		0.89		0.93		0.93	0.76
Net income (loss)	(235.0	)	(51.0	)	(1.7	)	113.7		90.3		147.4		29.4	13.6
Per share, basic (1)	(0.69	)	(0.15	)	(0.01	)	0.36		0.28		0.47		0.09	0.04
Per share, diluted (1)	(0.69	)	(0.15	)	(0.01	)	0.36		0.28		0.47		0.09	0.04
Dividends declared	103.0		102.1		101.6		95.7		95.2		94.8		94.5	94.0
Per share (1)	0.30		0.30		0.30		0.30		0.30		0.30		0.30	0.30
Total assets	6,072.4		6,346.0		6,588.8		6,325.5		6,095.5		5,988.7		5,949.5	5,736.0
Total liabilities	2,578.3		2,565.7		2,704.2		2,773.7		2,603.5		2,531.1		2,580.7	2,339.9
Net debt outstanding (3)	981.1		878.1		950.5		1,255.9		1,152.8		1,061.9		1,096.0	1,011.5
Weighted average shares outstanding	342.8		340.4		333.2		318.6		317.2		315.9		314.7	313.5
Weighted average shares outstanding, diluted	342.8		340.7		333.5		319.1		317.8		316.6		315.2	313.9
Shares outstanding, end of period	344.2		341.5		339.3		319.4		317.8		316.5		315.3	314.1
CAPITAL EXPENDITURES
Geological and geophysical	8.0		3.1		2.3		4.7		3.5		3.5		5.9	6.6
Drilling and completions	117.9		51.8		83.0		164.4		154.9		181.6		159.1	140.9
Plant and facilities	37.8		43.2		43.7		78.2		58.8		49.4		75.0	58.8
Administrative assets	0.5		0.3		0.5		2.0		1.0		1.6		2.0	1.4
Total capital expenditures	164.2		98.4		129.5		249.3		218.2		236.1		242.0	207.7
Undeveloped land purchased at Crown land sales	0.6		0.1		1.4		18.0		21.9		16.6		5.8	3.5
Total capital expenditures including undeveloped land purchases	164.8		98.5		130.9		267.3		240.1		252.7		247.8	211.2
Acquisitions	—		14.1		—		—		37.3		5.5		30.7	12.4
Dispositions	(20.7	)	(14.9	)	(11.0	)	(2.4	)	(5.1	)	(31.8	)	—	0.5
Total capital expenditures, land purchases and net acquisitions and dispositions	144.1		97.7		119.9		264.9		272.3		226.4		278.5	224.1
OPERATING
Production
Crude oil (bbl/d)	29,397		31,958		35,851		37,442		35,871		35,317		37,478	35,542
Condensate (bbl/d)	3,361		3,139		3,591		3,448		3,862		4,462		2,887	2,580
Natural gas (MMcf/d)	425.1		426.0		459.6		432.1		424.5		397.2		369.6	359.4
NGLs (bbl/d)	3,653		3,795		4,314		5,075		5,056		4,179		3,743	2,868
Total (boe/d)	107,261		109,900		120,354		117,986		115,530		110,165		105,699	100,883
Average realized prices, prior to hedging
Crude oil ($/bbl)	52.43		64.49		48.73		72.49		93.34		102.14		95.58	82.85
Condensate ($/bbl)	53.00		64.84		49.12		74.04		95.55		103.72		100.11	88.72
Natural gas ($/Mcf)	3.03		2.88		3.05		4.15		4.46		4.99		5.60	3.61
NGLs ($/bbl)	5.68		9.53		16.07		32.69		39.61		39.51		48.54	41.47
Oil equivalent ($/boe)	28.22		32.10		28.20		41.78		50.28		56.44		57.91	45.51
TRADING STATISTICS
($, based on intra-day trading)
High	21.98		25.60		25.87		29.85		32.60		33.68		30.66	29.95
Low	15.57		21.01		20.75		22.70		28.54		30.30		27.52	25.68
Close	17.64		21.40		21.76		25.16		29.55		32.49		30.45	29.57
Average daily volume (thousands)	1,736		1,424		1,944		1,886		1,205		1,037		1,248	1,030

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

(2) Refer to the sections entitled "Funds from Operations" and “Additional GAAP Measures” contained within this MD&A.

(3) Refer to the sections entitled "Capitalization, Financial Resources and Liquidity" and “Additional GAAP Measures” contained within this MD&A.

ARC Resources Ltd. Page 32

ARC RESOURCES LTD.
CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)
As at
(Cdn$ millions)	September 30, 2015		December 31, 2014
ASSETS
Current assets
Cash and cash equivalents	205.0		7.1
Short-term investment	3.7		3.6
Accounts receivable	109.5		165.0
Prepaid expenses	15.8		14.3
Risk management contracts (Note 9)	160.8		131.8
Assets held for sale (Note 5)	—		5.8
	494.8		327.6
Reclamation fund	33.2		35.2
Risk management contracts (Note 9)	209.4		128.0
Intangible exploration and evaluation assets (Note 4, 6)	262.9		266.4
Property, plant and equipment (Note 5, 6)	4,823.9		5,320.1
Goodwill (Note 6)	248.2		248.2
Total assets	6,072.4		6,325.5
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	188.2		339.1
Current portion of long-term debt (Note 7)	56.3		49.5
Current portion of asset retirement obligations (Note 8)	15.0		13.0
Dividends payable	34.4		32.0
Risk management contracts (Note 9)	1.1		1.0
Liabilities associated with assets held for sale (Note 8)	—		5.5
	295.0		440.1
Risk management contracts (Note 9)	0.7		1.0
Long-term debt (Note 7)	1,036.2		1,025.3
Long-term incentive compensation liability (Note 11)	19.4		29.1
Other deferred liabilities	14.5		15.8
Asset retirement obligations (Note 8)	567.4		603.1
Deferred taxes	645.1		659.3
Total liabilities	2,578.3		2,773.7
Commitments and contingencies (Note 12)
SHAREHOLDERS’ EQUITY
Shareholders’ capital	4,484.9		3,951.1
Contributed surplus	11.4		8.6
Deficit	(1,002.3	)	(407.9	)
Accumulated other comprehensive income	0.1		—
Total shareholders’ equity	3,494.1		3,551.8
Total liabilities and shareholders’ equity	6,072.4		6,325.5

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 33

ARC RESOURCES LTD.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) (unaudited)
For the three and nine months ended September 30
	Three Months Ended				Nine Months Ended
(Cdn$ millions, except per share amounts)	2015		2014		2015		2014
REVENUE
Sales of crude oil, natural gas, condensate, natural gas liquids and other income	279.5		535.2		907.8		1,653.6
Royalties	(25.6	)	(74.9	)	(81.0	)	(235.3	)
	253.9		460.3		826.8		1,418.3
Gain (loss) on risk management contracts (Note 8)	132.6		58.8		244.5		(61.2	)
	386.5		519.1		1,071.3		1,357.1
EXPENSES
Transportation	24.1		25.9		73.0		64.3
Operating	70.9		94.7		229.8		271.4
Intangible exploration and evaluation expenses (Note 4, 6)	2.5		28.2		46.9		29.9
General and administrative	20.7		19.4		54.6		58.3
Interest and financing charges	12.7		11.2		37.7		34.4
Accretion of asset retirement obligations (Note 8)	3.3		3.6		10.1		11.2
Depletion, depreciation, amortization and impairment (Note 5, 6)	472.9		168.9		802.4		479.1
Loss on foreign exchange	72.2		37.8		143.9		41.4
Loss (gain) on short-term investment	0.4		(0.4	)	(0.1	)	(1.5	)
Gain on disposal of petroleum and natural gas properties	—		1.9		(23.3	)	1.9
	679.7		391.2		1,375.0		990.4
Provision for (recovery of) income taxes
Current	(10.1	)	17.0		(6.0	)	64.0
Deferred	(48.1	)	20.6		(10.0	)	35.6
	(58.2	)	37.6		(16.0	)	99.6
Net income (loss)	(235.0	)	90.3		(287.7	)	267.1
Net income (loss) per share (Note 10)
Basic	(0.69	)	0.28		(0.85	)	0.85
Diluted	(0.69	)	0.28		(0.85	)	0.84

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 34

ARC RESOURCES LTD.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)
For the three and nine months ended September 30
	Three Months Ended			Nine Months Ended
(Cdn$ millions)	2015		2014	2015		2014
Net income (loss)	(235.0	)	90.3	(287.7	)	267.1
Other comprehensive income (loss)
Items that may be reclassified into earnings, net of tax:
Net unrealized gain (loss) on reclamation fund investments	(0.1	)	—	0.1		—
Other comprehensive income (loss)	(0.1	)	—	0.1		—
Comprehensive income (loss)	(235.1	)	90.3	(287.6	)	267.1

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 35

ARC RESOURCES LTD.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (unaudited)
For the nine months ended September 30
(Cdn$ millions)	Shareholders’ Capital		Contributed Surplus	Deficit		Accumulated other comprehensive income	Total Shareholders’ Equity
December 31, 2013	3,800.8		3.8	(408.5	)	—	3,396.1
Total comprehensive income	—		—	267.1		—	267.1
Shares issued pursuant to the dividend reinvestment program	84.9		—	—		—	84.9
Shares issued pursuant to the stock dividend program	25.3		—	—		—	25.3
Cancellation of shares and return of accrued dividends	(0.8	)	1.9	—		—	1.1
Recognized under share-based compensation plans (Note 11)	—		2.0	—		—	2.0
Dividends declared	—		—	(284.5	)	—	(284.5	)
September 30, 2014	3,910.2		7.7	(425.9	)	—	3,492.0
December 31, 2014	3,951.1		8.6	(407.9	)	—	3,551.8
Net income (loss)	—		—	(287.7	)	—	(287.7	)
Other comprehensive income	—		—	—		0.1	0.1
Total comprehensive income (loss)	—		—	(287.7	)	0.1	(287.6	)
Shares issued for cash	402.7		—	—		—	402.7
Shares issued pursuant to the dividend reinvestment program	109.8		—	—		—	109.8
Shares issued pursuant to the stock dividend program	33.9		—	—		—	33.9
Cancellation of shares and return of accrued dividends	(0.1	)	0.1	—		—	—
Share issue costs (1)	(12.5	)	—	—		—	(12.5	)
Recognized under share-based compensation plans (Note 11)	—		2.7	—		—	2.7
Dividends declared	—		—	(306.7	)	—	(306.7	)
September 30, 2015	4,484.9		11.4	(1,002.3	)	0.1	3,494.1

(1) Amount is net of deferred tax of $4.2 million.

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 36

ARC RESOURCES LTD.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
For the three and nine months ended September 30
	Three Months Ended				Nine Months Ended
(Cdn$ millions)	2015		2014		2015		2014
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)	(235.0	)	90.3		(287.7	)	267.1
Add items not involving cash:
Unrealized loss (gain) on risk management contracts	(93.9	)	(67.1	)	(110.4	)	7.3
Accretion of asset retirement obligations (Note 8)	3.3		3.6		10.1		11.2
Depletion, depreciation, amortization and impairment (Note 5, 6)	472.9		168.9		802.4		479.1
Intangible exploration and evaluation expenses (Note 4, 6)	2.5		28.2		46.9		29.9
Unrealized loss on foreign exchange	72.2		37.8		143.6		41.1
Gain on disposal of petroleum and natural gas properties	—		1.9		(23.3	)	1.9
Deferred tax expense (recovery)	(48.1	)	20.6		(10.0	)	35.6
Other (Note 13)	1.0		—		1.1		(0.9	)
Net change in other liabilities (Note 13)	(8.1	)	(6.2	)	(18.0	)	(20.8	)
Change in non-cash working capital (Note 13)	(1.4	)	(10.5	)	(41.5	)	10.3
	165.4		267.5		513.2		861.8
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES
Repayment of long-term debt under revolving credit facilities, net	—		(119.1	)	(83.8	)	(87.2	)
Issue of senior notes	—		166.6		—		166.6
Repayment of senior notes	—		—		(40.9	)	(33.0	)
Issue of common shares (Note 10)	—		—		402.7		—
Share issue costs	—		—		(16.7	)	—
Cash dividends paid	(51.8	)	(56.5	)	(160.6	)	(173.9	)
	(51.8	)	(9.0	)	100.7		(127.5	)
CASH FLOW FROM (USED IN) INVESTING ACTIVITIES
Acquisition of petroleum and natural gas properties (Note 5)	—		(35.5	)	(14.1	)	(71.7	)
Disposal of petroleum and natural gas properties	20.7		3.3		46.6		35.1
Property, plant and equipment development expenditures (Note 5)	(145.2	)	(223.7	)	(373.7	)	(695.2	)
Intangible exploration and evaluation asset expenditures (Note 4)	(19.5	)	(16.1	)	(20.3	)	(45.1	)
Net reclamation fund withdrawals (contributions)	(1.0	)	(1.2	)	2.0		(1.4	)
Change in non-cash working capital (Note 13)	14.4		8.8		(56.5	)	44.5
	(130.6	)	(264.4	)	(416.0	)	(733.8	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(17.0	)	(5.9	)	197.9		0.5
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	222.0		6.4		7.1		—
CASH AND CASH EQUIVALENTS, END OF PERIOD	205.0		0.5		205.0		0.5
The following are included in cash flow from operating activities:
Income taxes paid in cash	0.7		5.5		42.8		26.1
Interest paid in cash	16.1		12.1		41.9		36.0

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 37

NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

September 30, 2015 and 2014

1. STRUCTURE OF THE BUSINESS

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

ARC was incorporated in Canada and the Company’s registered office and principal place of business is located at 1200, 308 – 4^th Avenue SW, Calgary, Alberta, Canada T2P 0H7.

2. BASIS OF PREPARATION

These condensed interim consolidated financial statements (the “financial statements”) have been prepared in accordance with International Accounting Standard ("IAS") 34 "Interim Financial Reporting" using accounting policies consistent with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board ("IASB"). These financial statements are condensed as they do not include all of the information required by IFRS for annual financial statements and therefore should be read in conjunction with ARC's audited consolidated financial statements for the year ended December 31, 2014. All financial information is reported in millions of Canadian dollars ("Cdn$"), unless otherwise noted. References to “US$” are to United States dollars.

The financial statements have been prepared on a historical cost basis, except as detailed in the accounting policies disclosed in Note 3 "Summary of Accounting Policies" of ARC’s audited consolidated financial statements for the year ended December 31, 2014. All accounting policies and methods of computation followed in the preparation of these financial statements are consistent with those of the previous financial year. There have been no significant changes to the use of estimates or judgments since December 31, 2014, except for those used in the calculation of impairment losses as disclosed in Note 6 "Impairment."

The financial statements include the accounts of ARC and its wholly owned subsidiaries, ARC Resources General Partnership and 1504793 Alberta Ltd.

These financial statements were authorized for issue by the Board of Directors on November 4, 2015.

3. FUTURE ACCOUNTING POLICY CHANGES

In May 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers," which replaces IAS 18 "Revenue," IAS 11 "Construction Contracts," and related interpretations. In September 2015, the IASB formalized the deferral of the effective date of IFRS 15 by one year, to January 1, 2018. The standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted. IFRS 15 will be applied by ARC on January 1, 2018 and the Company is currently evaluating the impact of the standard on ARC's financial statements.

In July 2014, the IASB completed the final elements of IFRS 9 "Financial Instruments." The Standard supersedes earlier versions of IFRS 9 and completes the IASB’s project to replace IAS 39 "Financial Instruments: Recognition and Measurement." IFRS 9, as amended, includes a principle-based approach for classification and measurement of financial assets, a single 'expected loss’ impairment model and a substantially-reformed approach to hedge accounting. The Standard will come into effect for annual periods beginning on or after January 1, 2018, with earlier adoption permitted. IFRS 9 will be applied by ARC on January 1, 2018 and the Company is currently evaluating the impact of the standard on ARC's financial statements.

In October 2015, the IASB voted on the effective date of IFRS 16 "Leases" which replaces IAS 17 "Leases." The IASB is expected to issue the standard in 2015. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted if the entity is also applying IFRS 15 "Revenue from Contracts with Customers." IFRS 16 will be applied by ARC on January 1, 2019 and the Company is currently evaluating the impact of the standard on ARC's financial statements.

ARC Resources Ltd. Page 38

4. INTANGIBLE EXPLORATION AND EVALUATION ("E&E") ASSETS

Carrying amount
Balance, December 31, 2014	266.4
Additions	20.3
Acquisitions	27.1
Assets reclassified as held for sale and disposed in period (Note 5)	(8.4	)
Intangible exploration and evaluation expenses	(46.9	)
Other	4.4
Balance, September 30, 2015	262.9

ARC has certain E&E properties that have sales of petroleum products associated with production from test wells. For the nine months ended September 30, 2015 and 2014, these operating results have been recognized in the condensed interim consolidated statements of income (loss) (the "statements of income (loss)") and comprised sales of crude oil, natural gas, condensate and natural gas liquids of $5.6 million and $15.6 million, royalties of $0.2 million and $0.9 million, operating expenses of $3.5 million and $4.6 million, and transportation expenses of $0.8 million and $1.1 million, respectively. All cash flows associated with E&E assets for the nine months ended September 30, 2015 and 2014 are reflected in cash flow from operating activities.

5. PROPERTY, PLANT AND EQUIPMENT

Cost	Development and Production Assets		Administrative Assets		Total
Balance, December 31, 2014	7,917.1		61.4		7,978.5
Additions	372.6		1.3		373.9
Acquisitions	15.6		—		15.6
Change in asset retirement cost	24.6		—		24.6
Assets reclassified as held for sale and disposed in period	(260.4	)	—		(260.4	)
Balance, September 30, 2015	8,069.5		62.7		8,132.2
Accumulated depletion, depreciation, amortization and impairment
Balance, December 31, 2014	(2,630.3	)	(28.1	)	(2,658.4	)
Depletion, depreciation and amortization	(459.4	)	(4.7	)	(464.1	)
Impairment (Note 6)	(338.3	)	—		(338.3	)
Accumulated depletion and impairment reclassified as held for sale and disposed in period	152.5		—		152.5
Balance, September 30, 2015	(3,275.5	)	(32.8	)	(3,308.3	)
Carrying amounts
Balance, December 31, 2014	5,286.8		33.3		5,320.1
Balance, September 30, 2015	4,794.0		29.9		4,823.9

For the three and nine months ended September 30, 2015, $7.5 million and $20.3 million of direct and incremental general and administrative expenses were capitalized to property, plant and equipment ("PP&E") ($10 millionand$28.8 million for the three and nine months ended September 30, 2014), respectively.

Assets held for sale (1)
Balance, December 31, 2014	5.8
Additions	116.3
Disposals	(122.1	)
Balance, September 30, 2015	—

(1) Includes E&E and PP&E properties.

ARC Resources Ltd. Page 39

6. IMPAIRMENT

Intangible Exploration & Evaluation Assets

	Three Months Ended		Nine Months Ended
	September 30		September 30
Intangible exploration and evaluation expenses	2015	2014	2015	2014
E&E impairment test	—	—	44.4	1.7
E&E impairment on transfer to PP&E	—	28.2	—	28.2
E&E impairment on disposal	2.5	—	2.5	—
Total	2.5	28.2	46.9	29.9

At June 30, 2015, ARC performed an impairment test on one of its E&E assets as Management had decided to indefinitely delay any further investment to evaluate the asset and sufficient data existed to indicate that the carrying value of the asset would not be fully recovered from any future development or sale. As a result of the impairment test, ARC recorded an impairment in intangible E&E expenses in the statements of income (loss) of $44.4 million on this asset based on a recoverable amount of $10 million. This asset was subsequently disposed during the third quarter of 2015 and a further $2.5 million impairment charge was recognized upon disposal. At September 30, 2014, ARC recorded impairment of $28.2 million related to the transfer of as E&E asset to PP&E based on an estimated recoverable amount of $9 million. Impairment charges on E&E assets are recognized as intangible exploration and evaluation expenses in the statements of income (loss).

There were no indicators of impairment at September 30, 2015 for ARC's intangible E&E assets and therefore an impairment test was not performed.

Property, Plant and Equipment

	Three Months Ended		Nine Months Ended
	September 30		September 30
PP&E impairment	2015	2014	2015	2014
Impairment test	320.0	—	320.0	—
Impairment on disposal	6.6	—	18.3	—
Total PP&E impairment	326.6	—	338.3	—

Non-Core Asset Disposition

During the three and nine months ended September 30, 2015, ARC completed dispositions of certain non-core PP&E assets in its Southern Alberta & Southwest Saskatchewan cash-generating unit ("CGU"). As a result of these dispositions, ARC recorded impairment charges of $6.6 million and $18.3 million in depletion, depreciation, amortization and impairment in the statements of income (loss).

Impairment Test

At September 30, 2015, ARC evaluated its CGUs for indicators of any potential impairment or related recovery. As a result of continued declines in forward commodity prices for crude oil and natural gas, impairment tests were conducted at September 30, 2015 on each of ARC's CGUs. In estimating the recoverable amount of each CGU, the following information was incorporated:

i) the net present value of the after-tax cash flows from proved plus probable oil and gas reserves of each CGU based on reserves estimated by ARC’s independent reserve evaluator at December 31, 2014, updated for forward commodity price estimates assuming ongoing reductions in required future development capital expenditures of 20 per cent and reductions to future operating costs of 12.5 per cent, based on recent experience of oilfield service cost reductions and enhanced efficiency. The reserve evaluation is based on an estimated remaining reserve life up to a maximum of 50 years.

ii) the fair value of undeveloped land based on estimates provided by ARC’s independent land evaluator at December 31, 2014, and adjusted for acquisitions and divestments occurring during the nine months ended September 30, 2015.

iii) where applicable, economic contingent resources associated with interests in certain of ARC's properties.

iv) recent transactions completed within the industry on assets with similar geological and geographic characteristics within the relevant CGU.

ARC Resources Ltd. Page 40

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

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

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

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

The estimated recoverable amounts were based on fair value less costs of disposal calculations using after-tax discount rates that are based on an estimated industry weighted average cost of capital ranging from nine to nine and a half per cent (December 31, 2014: nine to nine and a half per cent) depending on the resource composition of the assets in the CGU, an inflation rate of two per cent, and the following forward commodity price estimates:

	Edmonton Light Crude Oil	WTI Oil	AECO Gas	Cdn$/US$
Year	(Cdn$/bbl) (1,2)	(US$/bbl) (1,2)	(Cdn$/MMbtu) (1,2)	Exchange Rates (1,2)
2015	57.91	49.49	2.83	0.78
2016	61.33	50.00	3.43	0.75
2017	64.52	55.00	3.62	0.78
2018	68.75	60.00	3.72	0.80
2019	72.73	65.00	3.81	0.83
2020	76.47	70.00	3.90	0.85
2021	82.35	75.00	4.10	0.85
2022	88.24	80.00	4.30	0.85
2023	94.12	85.00	4.50	0.85
2024	98.41	89.63	4.78	0.85
Remainder	+2.0% per year	+2.0% per year	+2.0% per year	0.85

(1) Source: GLJ Petroleum Consultants price forecast, effective October 1, 2015.

(2) The forecast benchmark prices listed above are adjusted for quality differentials, heat content and distance to market in performing the Company's impairment tests.

As a result of its impairment test at September 30, 2015, ARC recorded impairment charges to its PP&E of $320 million ($235.5 million net of deferred tax recovery), which was recognized in depletion, depreciation, amortization and impairment in the statements of income (loss) and was a result of a decline in expected future commodity prices and its impact on expected future cash flows of some of ARC's CGUs.

Impairment charges were recognized in the following CGUs:

• Northern Alberta CGU ($120 million, $88.3 million net of deferred tax recovery) composed of a mixture of oil and gas producing assets. The recoverable amount of $802 million at September 30, 2015 was determined using an after-tax discount rate of nine per cent.

• Pembina CGU ($120 million, $88.3 million net of deferred tax recovery) composed of primarily oil producing assets. The recoverable amount of $697 million at September 30, 2015 was determined using an after-tax discount rate of nine per cent.

• Redwater CGU ($75 million, $55.2 million net of deferred tax recovery) composed of primarily oil producing assets. The recoverable amount of $255 million at September 30, 2015 was determined using an after-tax discount rate of nine per cent.

• Southern Alberta & Southwest Saskatchewan CGU ($5 million, $3.7 million net of deferred tax recovery) composed of primarily gas producing assets. The recoverable amount of $46 million at September 30, 2015 was determined using an after-tax discount rate of nine and a half per cent.

The fair value less costs of disposal values used to determine the recoverable amounts of the impaired PP&E assets are classified as Level 3 fair value measurements as certain key assumptions are not based on observable market data but, rather, management's best estimates. Refer to Note 9 for information on fair value hierarchy classifications.

ARC Resources Ltd. Page 41

The results of the September 30, 2015 impairment test are sensitive to changes in any of the key judgments, such as a revision in reserves or resources, a change in forecast commodity prices, expected royalties, required future development capital expenditures or expected future production costs, which could decrease or increase the recoverable amounts of assets and result in additional impairment charges or recovery of impairment charges.

The following table demonstrates the effect of the assumed discount rate and the effect of forecast benchmark commodity prices estimates on impairment charges recorded for the three and nine months ended September 30, 2015. The sensitivity is based on a one per cent increase and one per cent decrease in the assumed discount rate and a five per cent increase and five per cent decrease in the forecast benchmark commodity price estimate.

	Increase in Discount Rate of 1 per cent	Decrease in Discount Rate of 1 per cent		Increase in Commodity Prices of 5 per cent		Decrease in Commodity Prices of 5 per cent
Northern Alberta CGU	40	(51	)	(58	)	55
Pembina CGU	60	(120	)	(120	)	52
Redwater CGU	22	(24	)	(23	)	26
Southern Alberta & Southwest Saskatchewan CGU	9	(5	)	(5	)	4
Southeast Saskatchewan & Manitoba CGU	82	—		—		86
Impairment charge increase (decrease)	213	(200	)	(206	)	223

Goodwill

The carrying value of goodwill at September 30, 2015 is $248.2 million. This value is supported by the combined excess recoverable amount over the current carrying value of ARC’s operating segment.

7. LONG-TERM DEBT

	U.S. $ Denominated		Canadian $ Amount
	September 30, 2015	December 31, 2014	September 30, 2015	December 31, 2014
Syndicated credit facilities
Cdn$ denominated	—	—	—	83.8
Senior notes
Master Shelf Agreement
5.42% US$ note	28.1	28.1	37.7	32.6
4.98% US$ note	40.0	50.0	53.6	58.0
3.72% US$ note	150.0	150.0	200.9	174.0
2004 Note Issuance
5.10% US$ note	4.8	9.6	6.4	11.1
2009 note issuance
7.19% US$ note	13.5	27.0	18.1	31.3
8.21% US$ note	35.0	35.0	46.9	40.6
6.50% Cdn$ note	—	—	5.8	11.6
2010 note issuance
5.36% US$ note	150.0	150.0	200.9	174.0
2012 note issuance
3.31% US$ note	60.0	60.0	80.4	69.7
3.81% US$ note	300.0	300.0	401.8	348.1
4.49% Cdn$ note	—	—	40.0	40.0
Total long-term debt outstanding	781.4	809.7	1,092.5	1,074.8
Long-term debt due within one year			56.3	49.5
Long-term debt due beyond one year			1,036.2	1,025.3

At September 30, 2015, the fair value of all senior notes is $1,068.8 million ($974.4 million as at December 31, 2014), compared to a carrying value of $1,092.5 million ($991 million as at December 31, 2014).

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On October 26, 2015, ARC extended its syndicated revolving credit facility for one additional year until November 6, 2019 at existing terms.

8. ASSET RETIREMENT OBLIGATIONS

	Nine Months Ended September 30, 2015		Year Ended December 31, 2014
Balance, beginning of period	616.1		475.4
Increase in liabilities relating to development activities	3.9		12.6
Increase in liabilities relating to change in estimates and discount rate (1)	25.1		174.2
Settlement of obligations	(8.1	)	(23.0	)
Accretion	10.1		14.9
Dispositions	(64.7	)	(32.5	)
Reclassified as liabilities associated with assets held for sale	—		(5.5	)
Balance, end of period	582.4		616.1
Expected to be incurred within one year	15.0		13.0
Expected to be incurred beyond one year	567.4		603.1

(1) Relates to changes in discount rate and anticipated settlement dates of asset retirement obligations.

The Bank of Canada's long-term risk-free bond rate of 2.2 per cent (2.3 per cent at December 31, 2014) and an inflation rate of 2 per cent (2 per cent at December 31, 2014) were used to calculate the present value of the asset retirement obligation liability at September 30, 2015.

9. FINANCIAL INSTRUMENTS AND MARKET RISK MANAGEMENT

Financial Instruments

ARC's financial instruments include cash and cash equivalents, short-term investment, accounts receivable, risk management contracts, reclamation fund assets, accounts payable and accrued liabilities, dividends payable, long-term debt, and long-term incentive compensation liability.

ARC’s financial instruments that are carried at fair value on the condensed interim consolidated balance sheets (the "balance sheets") include cash and cash equivalents, short-term investment, risk management contracts, and reclamation fund assets. The fair value of long-term debt is disclosed in Note 7. To estimate the fair value of these instruments, ARC uses quoted market prices when available, or third-party models and valuation methodologies that use observable market data. Fair value is measured using the assumptions that market participants would use, including transaction-specific details and non-performance risk.

All financial assets and liabilities for which fair value is measured or disclosed in the financial statements are further categorized using a three-level hierarchy that reflects the significance of the lowest level of inputs used in determining fair value:

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

• Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

All of ARC’s financial instruments carried at fair value are transacted in active markets. ARC’s cash and cash equivalents, short-term investment, and reclamation fund assets are classified as Level 1 measurements and its risk management contracts and fair value disclosure for its long-term debt are classified as Level 2 measurements. ARC does not have any financial instruments classified as Level 3.

ARC determines whether transfers have occurred between levels in the hierarchy by re-assessing its hierarchy classifications at each reporting date based on the lowest level input that is significant to the fair value measurement as a whole. There were no transfers between levels in the hierarchy in the nine months ended September 30, 2015.

The carrying values of ARC's accounts receivable, accounts payable and accrued liabilities, dividends payable, and long-term incentive compensation liability approximate their fair values.

ARC Resources Ltd. Page 43

Financial Assets and Financial Liabilities Subject to Offsetting

ARC's risk management contracts are subject to master netting agreements that create a legally enforceable right to offset by counterparty the related financial assets and financial liabilities on the Company's balance sheets in all circumstances. ARC manages these contracts on the basis of its net exposure to market risks and therefore measures their fair value consistently with how market participants would price the net risk exposure at the reporting date under current market conditions.

The following is a summary of ARC's financial assets and financial liabilities that are subject to offsetting as at September 30, 2015 and December 31, 2014:

	Gross Amounts of Recognized Financial Assets (Liabilities)		Gross Amounts of Recognized Financial Assets (Liabilities) Offset in Balance Sheet		Net Amounts of Financial Assets (Liabilities) Recognized in Balance Sheet Prior to Credit Risk Adjustment		Credit Risk Adjustment		Net Amounts of Financial Assets (Liabilities) Recognized in Balance Sheet
As at September 30, 2015
Risk management contracts
Current asset	171.8		(9.3	)	162.5		(1.7	)	160.8
Long-term asset	216.9		(5.4	)	211.5		(2.1	)	209.4
Current liability	(10.5	)	9.3		(1.2	)	0.1		(1.1	)
Long-term liability	(6.1	)	5.4		(0.7	)	—		(0.7	)
Net position	372.1		—		372.1		(3.7	)	368.4
As at December 31, 2014
Risk management contracts
Current asset	151.0		(18.2	)	132.8		(1.0	)	131.8
Long-term asset	132.1		(3.1	)	129.0		(1.0	)	128.0
Current liability	(19.2	)	18.2		(1.0	)	—		(1.0	)
Long-term liability	(4.1	)	3.1		(1.0	)	—		(1.0	)
Net position	259.8		—		259.8		(2.0	)	257.8

Risk Management Contracts

The following is a summary of all risk management contracts in place, excluding premiums, as at September 30, 2015.

Financial Cdn$ WTI Crude Oil Contracts (1)
			Volume	Bought Put	Sold Call
Term		Contract	bbl/d	Cdn$/bbl	Cdn$/bbl
1-Oct-15	31-Dec-15	Collar	10,000	61.80	81.27
1-Jan-16	30-Jun-17	Collar	3,000	70.00	83.38

(1) Settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).

Financial Cdn$ WTI Crude Oil Swap Contracts (2)
			Volume	Sold Swap
Term		Contract	bbl/d	Cdn$/bbl
1-Oct-15	31-Dec-15	Swap	5,000	74.77
1-Jan-16	31-Dec-16	Swap	7,000	77.20

(2) Settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate).

Financial MSW Crude Oil Contracts (3)
			Volume	Sold Swap
Term		Contract	bbl/d	US$/bbl
1-Oct-15	31-Dec-15	Swap	5,000	(4.81)
1-Jan-16	31-Dec-16	Swap	4,500	(4.09)

(3) Settled on the monthly average Mixed Sweet Blend ("MSW") Differential to WTI. The MSW differential refers to the discount between WTI and the mixed sweet crude grade at Edmonton, calculated on a monthly weighted average basis.

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Financial NYMEX Natural Gas Contracts (4)
			Volume	Bought Put	Sold Call
Term		Contract	MMbtu/d	US$/MMbtu	US$/MMbtu
1-Oct-15	31-Dec-15	Collar	145,000	3.91	4.30
1-Oct-15	31-Dec-17	Collar	70,000	4.00	4.93
1-Jan-16	31-Dec-16	Collar	35,000	4.00	4.50
1-Jan-17	31-Dec-17	Collar	75,000	4.00	4.70
1-Jan-18	31-Dec-18	Collar	80,000	4.00	4.91
1-Jan-18	31-Dec-19	Collar	10,000	4.00	5.00
1-Jan-19	31-Dec-19	Collar	30,000	4.00	5.00

(4) NYMEX Henry Hub "Last Day" Settlement.

Financial NYMEX Natural Gas Swap Contracts (5)
			Volume	Sold Swap
Term		Contract	MMbtu/d	US$/MMbtu
1-Jan-16	31-Dec-16	Swap	40,000	4.00

(5) NYMEX Henry Hub "Last Day" Settlement.

Financial AECO Natural Gas Swap Contracts (6)
			Volume	Sold Swap
Term		Contract	GJ/d	Cdn$/GJ
1-Jan-16	31-Dec-16	Swap	30,000	2.99

(6) AECO Monthly (7a) index Cdn$/GJ.

Financial AECO Basis Swap Contracts (7)
			Volume	Ratio Sold Swap %
Term		Contract	MMbtu/d	AECO/NYMEX
1-Oct-15	31-Dec-15	Swap	30,000	85.2
1-Oct-15	31-Dec-17	Swap	110,000	90.6
1-Oct-15	30-Jun-18	Swap	20,000	89.9
1-Jan-16	31-Dec-16	Swap	10,000	88.4
1-Jan-17	31-Dec-17	Swap	10,000	86.1
1-Jan-18	31-Dec-18	Swap	40,000	82.1
1-Jan-18	30-Jun-19	Swap	20,000	90.8
1-Jul-18	31-Dec-18	Swap	20,000	85.4
1-Jan-19	31-Dec-19	Swap	15,000	82.2

(7) ARC receives NYMEX price based on Last Day settlement multiplied by AECO/NYMEX US$/MMbtu ratio; ARC pays AECO Monthly (7a) index US$/MMbtu.

Financial Electricity Heat Rate Contracts (8)
			Volume	Heat Rate
Term		Contract	MWh	GJ/MWh
1-Oct-15	31-Dec-17	Heat Rate Swap	20	13.71

(8) ARC pays AECO Monthly (5a) x Heat Rate; ARC receives floating AESO Power Price.

Financial Electricity Contracts (9)
			Volume	Bought Swap
Term		Contract	MWh	Cdn$/MWh
1-Oct-15	31-Dec-16	Fixed Rate Swap	5	51.00

(9) Alberta Power Pool (monthly average 24x7).

Foreign Exchange Contracts (10)
			Volume	Bought Put	Sold Call
Term		Contract	US$ millions/month	Cdn$/US$	Cdn$/US$
1-Oct-15	31-Dec-15	Collar	2.0	1.0400	1.0925

(10) Bank of Canada monthly average noon day rate settlement.

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Foreign Exchange Swap Contracts (11)
			Volume	Sold Swap	Limit Price
Term		Contract	US$ millions/month	Cdn$/US$	Cdn$/US$ (12)
1-Oct-15	31-Dec-15	Limit Swap	2.0	1.0525	1.1350

(11) Bank of Canada monthly average noon day rate settlement.

(12) Swap with upside participation up to the limit; above which, settlement will occur at the swap price.

10. SHAREHOLDERS’ CAPITAL

(thousands of shares)	Nine Months Ended September 30, 2015		Year Ended December 31, 2014
Common shares, beginning of period	319,439		314,067
Equity offering	17,859		—
Restricted shares issued pursuant to the LTRSA (1) Plan	100		—
Unvested restricted shares held in trust pursuant to the LTRSA Plan	(100	)	—
Cancelled shares	(1	)	(47	)
Dividend reinvestment program	5,262		4,159
Stock dividend program	1,621		1,260
Common shares, end of period	344,180		319,439

(1) Long-term Restricted Share Award.

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

	Three Months Ended September 30		Nine Months Ended September 30
(thousands of shares)	2015	2014	2015	2014
Weighted average common shares	342,794	317,183	338,853	315,944
Dilutive impact of share-based compensation	—	606	—	612
Weighted average common shares - diluted	342,794	317,789	338,853	316,556

Dividends declared for the three and nine months ended September 30, 2015 and 2014 were $0.30 and $0.90 per common share, respectively.

On October 16, 2015, the Board of Directors declared a dividend of $0.10 per common share, payable in cash or common shares under the Stock Dividend Program, to shareholders of record on October 30, 2015. The dividend payment date is November 16, 2015. Of the $34.4 million in dividends payable at September 30, 2015, $2.8 million is payable in common shares under the Stock Dividend Program ($4.2 million at December 31, 2014).

11. SHARE-BASED COMPENSATION PLANS

Long-term Incentive Plans

The following table summarizes the Restricted Share Unit ("RSU"), Performance Share Unit ("PSU") and Deferred Share Unit ("DSU") movement for the nine months ended September 30, 2015:

(number of units, thousands)	RSUs		PSUs(1)		DSUs
Balance, December 31, 2014	625		1,513		220
Granted	464		702		69
Distributed	(294	)	(493	)	—
Forfeited	(60	)	(50	)	—
Balance, September 30, 2015	735		1,672		289

(1) Based on underlying units before any effect of the performance multiplier.

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Compensation charges (recoveries) relating to the RSU, PSU and DSU Plans can be reconciled as follows:

	Nine Months Ended September 30, 2015		Nine Months Ended September 30, 2014
General and administrative expenses (recoveries)	(8.4	)	12.7
Operating expense (recoveries)	(0.5	)	3.2
PP&E (recoveries)	(0.7	)	2.8
Total compensation charges (recoveries)	(9.6	)	18.7
Cash payments	10.9		39.4

At September 30, 2015, $19.9 million of compensation amounts payable were included in accounts payable and accrued liabilities on the balance sheet ($30.9 million at December 31, 2014) and $19.4 million was included in long-term incentive compensation liability ($29.1 million at December 31, 2014). A recoverable amount of $0.3 million was included in accounts receivable at September 30, 2015 ($0.5 million at December 31, 2014).

Share Option Plan

ARC estimates the fair value of share options granted using a binomial-lattice option pricing model, with the grant date fair values as follows:

Grant Date	Number of Options Granted	Fair Value per Share Option ($)
March 24, 2011	430,990	8.40
June 21, 2012	1,056,373	5.25
June 20, 2013	713,248	7.87
June 19, 2014	568,538	10.21
June 24, 2015	998,545	5.68

The following assumptions were used to arrive at the estimated fair value of the share options at their grant date:

	Nine Months Ended September 30, 2015	Nine Months Ended September 30, 2014
Grant date share price ($)	20.20 - 32.94	20.20 - 32.94
Exercise price ($) (1)	16.30 - 31.44	17.50 - 32.64
Expected annual dividends ($)	1.20	1.20
Expected volatility (%) (2)	37.00 - 38.00	37.00 - 38.00
Risk-free interest rate (%)	1.39 - 2.61	1.39 - 2.61
Expected life of share option (3)	5.5 to 6 years	5.5 to 6 years

(1) Exercise price is reduced monthly by the amount of dividend declared.

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

(3) Expected life of the share option is calculated as the mid-point between vesting date and expiry.

ARC recorded compensation expense of $1 million and $2.5 million relating to the share option plan for the three and nine months ended September 30, 2015 ($0.8 million and $1.9 million for the three and nine months ended September 30, 2014), respectively. During the three and nine months endedSeptember 30, 2015, $0.1 million and $0.2 million of share option compensation charges were capitalized to PP&E ($0.1 million for the three and nine months ended September 30, 2014), respectively.

The changes in total share options outstanding and related weighted average exercise prices for the nine months ended September 30, 2015 were as follows:

	Share Options (number of units, thousands)		Weighted Average Exercise Price ($)
Balance, December 31, 2014	2,505		23.43
Granted	999		21.86
Exercised	—		—
Forfeited	(108	)	22.71
Balance, September 30, 2015	3,396		22.25
Exercisable, September 30, 2015	176		21.71

Long-term Restricted Share Award Plan

On April 30, 2015, at its Annual and Special Meeting of Shareholders, ARC shareholders approved a new LTRSA Plan to award shares of ARC to qualifying officers and employees. The first grant of the LTRSA Plan occurred on June 24, 2015.

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LTRSA grants consist of restricted common shares that are awarded at the date of grant and a cash payment made equal to the estimated personal tax obligation associated with the total award. The restricted shares issued on the grant date of the award are held in trust until the vesting conditions have been met.

While in trust, the restricted shares earn dividends which are reinvested into ARC common shares via the stock dividend program. These common shares issued through the stock dividend program are also held in trust until vested. Each LTRSA vests evenly on the eighth, ninth, and tenth anniversaries of their respective grant dates. Restricted shares and any accrued dividends that are subject to forfeiture will be redeemed and cancelled by ARC.

Compensation expense associated with the cash payment is recognized immediately, while compensation expense associated with the restricted common shares is recognized over the vesting period with a corresponding charge to contributed surplus. Upon vesting, ARC recognizes an increase in share capital with a corresponding reduction to contributed surplus. The dilutive effect of outstanding LTRSAs is reflected as additional share dilution in the computation of earnings per share.

The estimated fair value is determined as the weighted average trading price of ARC common shares for the five days immediately preceding the grant date. At September 30, 2015, the estimated fair value of the LTRSAs outstanding was as follows:

Grant Date	Number of Restricted Shares Granted	Fair Value per Restricted Share ($)
June 24, 2015	88,635	21.86
July 29, 2015	11,652	19.26

ARC recorded general and administrative expenses of $nil and $0.7 million relating to the cash payment under the LTRSA Plan for the three and nine months ended September 30, 2015 ($nil for the three and nine months ended September 30, 2014), respectively.

12. COMMITMENTS AND CONTINGENCIES

During the three and nine months ended September 30, 2015, ARC increased its transportation commitments by approximately $8.3 million and $90.4 million, respectively, from those presented at December 31, 2014. The increase relates to additional firm natural gas transportation that ARC committed to support the movement of ARC's natural gas production, with payments commencing in 2015 and to be incurred until 2027. There were no other material changes to ARC's commitments and contingencies from those presented as at December 31, 2014.

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13. SUPPLEMENTAL DISCLOSURES

Presentation in the Statements of Income (Loss)

ARC’s statements of income (loss) are prepared primarily by nature of item, with the exception of employee compensation expenses which are included in both operating and general and administrative expense line items.

The following table details the amount of total employee compensation expenses included in operating and general and administrative expense line items in the statements of income (loss):

	Three Months Ended		Nine Months Ended
	September 30		September 30
	2015	2014	2015	2014
Operating	9.6	9.8	28.1	27.0
General and administrative	19.9	19.6	48.4	58.5
Total employee compensation expenses	29.5	29.4	76.5	85.5

Cash Flow Statement Presentation

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

	Three Months Ended				Nine Months Ended
	September 30				September 30
Change in Non-Cash Working Capital	2015		2014		2015		2014
Accounts receivable	25.8		15.0		55.5		(23.8	)
Accounts payable and accrued liabilities	(16.2	)	(13.2	)	(152.0	)	80.5
Prepaid expenses	3.4		(3.5	)	(1.5	)	(1.9	)
Total	13.0		(1.7	)	(98.0	)	54.8
Relating to:
Operating activities	(1.4	)	(10.5	)	(41.5	)	10.3
Investing activities	14.4		8.8		(56.5	)	44.5
Total change in non-cash working capital	13.0		(1.7	)	(98.0	)	54.8

	Three Months Ended				Nine Months Ended
	September 30				September 30
Other Non-Cash Items	2015		2014		2015		2014
Non-cash lease inducement	(0.4	)	(0.4	)	(1.3	)	(1.3	)
Loss (gain) on short-term investment	0.4		(0.4	)	(0.1	)	(1.5	)
Share-based compensation expense	1.0		0.8		2.5		1.9
Total other non-cash items	1.0		—		1.1		(0.9	)

	Three Months Ended				Nine Months Ended
	September 30				September 30
Net Change in Other Liabilities	2015		2014		2015		2014
Long-term incentive compensation liability	(3.6	)	2.0		(9.7	)	(6.2	)
Risk management contracts	—		(0.2	)	(0.2	)	(0.3	)
Asset retirement obligations	(4.5	)	(8.0	)	(8.1	)	(14.3	)
Total net change in other liabilities	(8.1	)	(6.2	)	(18.0	)	(20.8	)

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