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 July 29, 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 six months ended June 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 a 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 June 2015, ARC had 567 employees with 329 professional, technical and support staff in the Calgary office, and 238 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

ARC's business plan has resulted in significant operational success and has contributed to a trailing five year annualized total return per share of 6.5 per cent (Table 1).

Table 1

Total Returns (1)	Trailing One Year		Trailing Three Year		Trailing Five Year
Dividends per share ($)	1.20		3.60		6.00
Capital appreciation (depreciation) per share ($)	(11.09	)	(1.50	)	1.67
Total return per share (%)	(31.1	)	6.9		37.3
Annualized total return per share (%)	(31.1	)	2.2		6.5
S&P/TSX Exploration & Producers Index annualized total return (%)	(40.9	)	(3.4	)	(5.8	)

(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 June 30, 2015.

Since 2011, ARC’s production has grown by 31,682 boe per day, or 38 per cent, while its proved plus probable reserves have grown by 100.3 million boe, or 18 per cent. Table 2 highlights ARC’s production and reserves for the first six months of 2015 and over the past four years:

Table 2

	2015 YTD	2014	2013	2012	2011
Production (boe/d) (1)	115,098	112,387	96,087	93,546	83,416
Daily production per thousand shares (2)(6)	0.34	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 six months ended June 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.

ARC Resources Ltd. Page 2

ECONOMIC ENVIRONMENT

ARC’s second 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				Six Months Ended
	June 30				June 30
	2015	2014	% Change		2015	2014	% Change
Brent (US$/bbl)	63.50	109.76	(42	)	59.35	108.82	(45	)
WTI oil (US$/bbl)	57.95	102.99	(44	)	53.34	100.84	(47	)
Edmonton Par (Cdn$/bbl)	67.73	105.62	(36	)	59.83	102.64	(42	)
Henry Hub NYMEX (US$/MMbtu) (2)	2.64	4.60	(43	)	2.81	4.80	(41	)
AECO natural gas (Cdn$/Mcf)	2.67	4.65	(43	)	2.81	4.72	(40	)
Cdn$/US$ exchange rate	1.23	1.09	13		1.24	1.10	13

(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.

During the second quarter of 2015, global crude oil prices appreciated compared to the first quarter of the year. The quarter-over-quarter strengthening of North American crude oil prices was driven by seasonal storage draw downs, alleviating concerns of record inventory levels, and high US throughput on the back of strong refining margins. However, as a result of continued oversupply in global crude oil markets as well as global economic uncertainty, crude oil prices remained significantly lower relative to prices throughout 2014. The second quarter of 2015 WTI crude oil price averaged US$57.95 per barrel, a decrease of 44 per cent compared to the second quarter of 2014. ARC’s crude oil price is primarily referenced to the Edmonton Par benchmark price, which averaged $67.73 per barrel in the second quarter of 2015, a decrease of 36 per cent compared to the same period in 2014. The differential between WTI and Edmonton Par narrowed to an average discount of US$2.87 per barrel, a 53 per cent decrease compared to the second quarter of 2014. The tightening of the WTI/Edmonton Par differential reflects regional disruptions due to forest fires across Alberta and major plant turnarounds, which resulted in reduced supply and thereby increased competition for available crude oil barrels.

Subsequent to June 30, global crude oil prices declined with the WTI crude oil price dropping approximately 20 per cent from the average of the second quarter. Increasing OPEC production and the potential removal of sanctions on Iran, combined with weaker expectations for global demand growth, have heightened concerns of longer-term supply/demand imbalances, causing the outlook for global crude oil prices to remain bearish through the second half of 2015. The relative weakness in the Canadian dollar compared to the US dollar and a slight narrowing of the WTI/Edmonton Par differential should serve to slightly offset the impact of lower crude oil prices.

North American natural gas prices continued to weaken during the second quarter of 2015. NYMEX Henry Hub (“NYMEX”) averaged US$2.64 per MMbtu in the second quarter of 2015, a decrease of 43 per cent compared to the second quarter of 2014. ARC’s realized natural gas price is primarily referenced to the AECO hub, which averaged $2.67 per Mcf in the second quarter of 2015, a decrease of 43 per cent compared to the second quarter of 2014. Despite the expectation for US power demand to remain at relatively strong levels and Mexican exports to increase, storage levels in both Canada and the US are expected to be tracking near capacity by the end of the injection season as a result of sustained record US natural gas production levels, which has resulted in a second quarter decrease in both Henry Hub NYMEX and AECO hub benchmark pricing. This signals continued weakness in the natural gas markets through the latter part of 2015.

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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 YTD		% Variance from Guidance
Production
Crude oil (bbl/d)	33,500 - 34,500	33,894		—
Condensate (bbl/d)	3,400 - 3,800	3,363		(1	)
Natural gas (MMcf/d)	430 - 440	442.7		1
NGLs (bbl/d)	4,500 - 4,900	4,053		(10	)
Total (boe/d)	113,000 - 116,000	115,098		—
Expenses ($/boe)
Operating	8.20 - 8.50	7.63		(7	)
Transportation	2.00 - 2.20	2.35		7
G&A (3)	2.00 - 2.30	1.63		(19	)
Interest	1.10 - 1.30	1.20		—
Current income tax (per cent of funds from operations) (4)	0 - 5	1		—
Capital expenditures before land purchases and net property dispositions ($ millions)	550	227.9		N/A
Land purchases and net property dispositions ($ millions)	—	(10.3	)	N/A
Weighted average shares, diluted (millions)	339	337		N/A

(1) Incorporates impact of divested non-core shallow gas assets located in southern Alberta with associated production of approximately 2,400 boe per day. This transaction closed in the second quarter of 2015.

(2) ARC expects third quarter 2015 production to decrease to a range of 104,000 to 107,000 boe per day due to downtime attributed to a significant planned turnaround at Dawson. ARC expects a significant increase in fourth quarter 2015 production to a range of 122,000 to 126,000 boe per day following commissioning of the new Sunrise gas processing facility and expanded Tower oil battery.

(3) 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 long-term incentive plans and $0.35 - $0.60 per boe associated with ARC’s long-term incentive plans. Actual per boe costs for each of these components for the six months ended June 30, 2015 were $1.64 and a recovery of $0.01 per boe, respectively.

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

On a per boe basis, operating expenses were below the original guidance range during the first six months of 2015. This is due primarily to higher average production volumes throughout the first six months of the year as well as lower than average costs for electricity and service cost reductions. During the second quarter, various planned turnarounds and maintenance had the effect of reducing production volumes and increasing operating costs while electricity costs also increased significantly. Turnaround activity and higher electricity rates are expected to continue throughout the third quarter and as such annual operating costs are expected to be within the guidance range. Transportation expenses are outside of the guidance range as ARC incurred additional trucking costs during the first quarter of 2015 to transport liquids to market. During the second quarter trucking activity has gone down as more production becomes pipeline connected, however this has been offset by increased pipeline tariff costs. ARC expects full year 2015 actual transportation expenses to approximate guidance as the year progresses. Year-to-date G&A expenses were below guidance due to reduced costs associated with ARC's long-term incentive plan due to the reduction in ARC's share price at June 30, 2015, as well as a reduced performance multiplier applied to its PSU awards.

ARC incurred $227.9 million of capital expenditures during the first six months of 2015. In addition, ARC spent $1.5 million on land purchases during the period and completed net dispositions for proceeds of $11.8 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 will resume development activities in other areas as reduced service costs are secured and economic conditions improve.

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

2015SECOND QUARTER FINANCIAL AND OPERATING RESULTS

Financial Highlights

Table 5

	Three Months Ended					Six Months Ended
	June 30					June 30
($ millions, except per share and volume data)	2015		2014	% Change		2015		2014	% Change
Funds from operations (1)	206.3		295.8	(30	)	397.8		588.1	(32	)
Funds from operations per share (1)(2)	0.61		0.93	(34	)	1.18		1.86	(37	)
Net income (loss)	(51.0	)	147.4	(135	)	(52.7	)	176.8	(130	)
Dividends per share (2)	0.30		0.30	—		0.60		0.60	—
Average daily production (boe/d)	109,900		110,165	—		115,098		107,944	7

(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				Six Months Ended
	June 30				June 30
($ millions)	2015		2014		2015		2014
Net income (loss)	(51.0	)	147.4		(52.7	)	176.8
Adjusted for the following non-cash items:
DD&A and impairment	150.8		160.4		329.5		310.2
Accretion of ARO	3.2		3.7		6.8		7.6
Intangible E&E expenses	44.4		1.7		44.4		1.7
Deferred tax expense	25.1		23.6		38.1		15.0
Unrealized loss (gain) on risk management contracts	61.2		(14.8	)	(16.5	)	74.4
Unrealized loss (gain) on foreign exchange	(16.9	)	(25.7	)	71.4		3.3
Gain on disposal of petroleum and natural gas properties	(10.6	)	—		(23.3	)	—
Other	0.1		(0.5	)	0.1		(0.9	)
Funds from operations	206.3		295.8		397.8		588.1
Net change in other liabilities	1.7		(1.1	)	(9.9	)	(14.6	)
Change in non-cash working capital	(5.9	)	40.3		(40.1	)	20.8
Cash flow from operating activities	202.1		335.0		347.8		594.3

ARC Resources Ltd. Page 4

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

Table 7

	Three Months Ended				Six Months Ended
	June 30				June 30
	$ millions		$/Share (1)		$ millions		$/Share (1)
Funds from operations – 2014	295.8		0.93		588.1		1.86
Volume variance
Crude oil and liquids	(44.5	)	(0.13	)	(46.5	)	(0.14	)
Natural gas	13.1		0.04		56.6		0.17
Price variance
Crude oil and liquids	(132.0	)	(0.39	)	(314.8	)	(0.95	)
Natural gas	(81.9	)	(0.24	)	(185.4	)	(0.57	)
Realized gain or loss on risk management contracts	76.2		0.22		141.0		0.42
Royalties	55.4		0.16		105.0		0.31
Expenses
Transportation	(3.0	)	(0.01	)	(10.5	)	(0.03	)
Operating	10.8		0.03		17.8		0.05
G&A	(4.0	)	(0.01	)	5.4		0.02
Interest	(0.9	)	—		(1.8	)	(0.01	)
Current tax	21.5		0.06		42.9		0.13
Realized gain or loss on foreign exchange	(0.2	)	—		—		—
Diluted shares	—		(0.05	)	—		(0.08	)
Funds from operations – 2015	206.3		0.61		397.8		1.18

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

Funds from operations decreased by 30 per cent in the second quarter of 2015 to $206.3 million from $295.8 million generated in the second quarter of 2014. The decrease reflects lower revenue due primarily to significantly lower realized commodity prices in the second quarter of 2015 as compared to the second quarter of 2014 which was partially offset by increased natural gas production from new wells drilled throughout the latter part of 2014 and into 2015. Increased realized gains on risk management contracts relative to the second quarter of the prior year along with reduced royalties, current taxes and operating costs, partially offset the reduction in commodity prices. Higher G&A and transportation expense also contributed to the overall decrease.

For the year-to-date, funds from operations decreased by $190.3 million from $588.1 million for the first six months of 2014 to $397.8 million for the first six months of 2015. This decrease is also primarily due to decreased revenue due to significantly lower commodity prices and is partially offset by increased realized gains on risk management contracts, lower royalties and lower operating costs.

ARC Resources Ltd. Page 5

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)	53.34		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)	1.24		0.01		0.009
Interest rate on floating-rate debt (2)	2.8	%	1.0	%	—
Operational
Crude oil and liquids production volumes (bbl/d) (5)	41,310		1.0	%	0.016
Natural gas production volumes (MMcf/d) (5)	442.7		1.0	%	0.009
Operating expenses ($/boe) (5)	7.63		1.0	%	0.008
G&A expenses ($/boe) (5)	1.63		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 six 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 six months endedJune 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 $51 million ($0.15 per share) was incurred in the second quarter of 2015, a $198.4 million decrease compared to net income of $147.4 million ($0.47 per share) in the second quarter of 2014. ARC's revenue net of royalties decreased $189.9 million due to a significant decrease in prices realized for crude oil and natural gas during the second quarter of 2015 compared to those in the second quarter of 2014, partially offset by reduced royalties. Additionally, intangible E&E expenses increased by $42.7 million over the same period. Offsetting these decreases in net income were lower second quarter operating costs of $10.8 million, lower DD&A expense of $9.6 million and the recognition of a gain on disposal of petroleum and natural gas properties of $10.6 million during the second quarter of 2015 ($nil during the second quarter of 2014).

During the six months ended June 30, 2015, ARC incurred a net loss of $52.7 million ($0.16 per share), $229.5 million ($0.72 per share) less than net income of $176.8 million ($0.56 per share) recorded during the six months ended June 30, 2014. Lower commodity prices during the period resulted in lower revenue net of royalties of $385.1 million, however, the impact of falling prices was largely offset by increased gains on risk management contracts of $231.9 million. Also decreasing net income during the year to date was an increase to foreign exchange losses of $68.1 million, increased intangible E&E expenses of $42.7 million and higher DD&A expenses of $19.3 million. These items are partially offset by lower operating costs of $17.8 million and gains on disposal of petroleum and natural gas properties of $23.3 million.

ARC Resources Ltd. Page 6

Production

Table 9

	Three Months Ended				Six Months Ended
	June 30				June 30
Production	2015	2014	% Change		2015	2014	% Change
Light and medium crude oil (bbl/d)	30,979	34,361	(10	)	32,849	35,439	(7	)
Heavy oil (bbl/d)	979	956	2		1,045	952	10
Condensate (bbl/d)	3,139	4,462	(30	)	3,363	3,679	(9	)
Natural gas (MMcf/d)	426.0	397.2	7		442.7	383.5	15
NGLs (bbl/d)	3,795	4,179	(9	)	4,053	3,962	2
Total production (boe/d)	109,900	110,165	—		115,098	107,944	7
% Natural gas production	65	60	8		64	59	8
% Crude oil and liquids production	35	40	(13	)	36	41	(12	)

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 second quarter of 2015, crude oil and liquids production decreased 12 per cent from the second 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 six months ended June 30, 2015, crude oil and liquids volumes decreased by six per cent as compared to the same period in 2014 primarily due to natural declines associated with reduced drilling activity.

Natural gas production was 426 MMcf per day in the second quarter of 2015, an increase of seven per cent from the 397.2 MMcf per day produced in the second quarter of 2014. The increase is mainly attributed to new production from drilling throughout 2014 and early 2015 in northeastern British Columbia, particularly at Sunrise and Parkland as well as increased contracted capacity at a third party gas plant at Sunrise. For the year-to-date, natural gas production increased by 15 per cent as new production was brought on later in 2014 and early 2015 at Sunrise, Parkland and Dawson.

During the second quarter of 2015, ARC drilled 12 wells (100 per cent ARC) on operated properties consisting of five oil wells and seven natural gas wells. During the first half of 2015, ARC drilled 37 gross wells (36 net wells) on operated properties consisting of 22 gross (21 net) oil wells,13 gross (13 net) natural gas wells and two gross (two net) liquids-rich natural gas wells.

ARC Resources Ltd. Page 7

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

Table 10

	Three Months Ended June 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	61,241	2,524	2,182	329.8	1,555
Northern AB	21,477	7,529	696	70.5	1,502
Pembina	10,913	8,169	154	13.0	429
South Central AB (2)	6,202	3,970	58	11.7	228
Southeast SK & MB	10,067	9,766	49	1.0	81
Total	109,900	31,958	3,139	426.0	3,795

	Three Months Ended June 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	56,128	2,324	3,367	289.9	2,109
Northern AB	23,406	9,874	815	67.8	1,419
Pembina	11,243	8,748	161	11.8	361
South Central AB (2)	8,615	3,877	72	26.7	222
Southeast SK & MB	10,773	10,494	47	1.0	68
Total	110,165	35,317	4,462	397.2	4,179

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

(2) During the second quarters of 2014 and 2015, 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.

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

Table 10a

	Six Months Ended June 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	63,898	2,837	2,394	341.4	1,751
Northern AB	21,897	7,965	694	70.2	1,531
Pembina	11,536	8,729	167	13.1	459
South Central AB (2)	7,313	4,209	60	16.9	235
Southeast SK & MB	10,454	10,154	48	1.1	77
Total	115,098	33,894	3,363	442.7	4,053

	Six Months Ended June 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	52,096	2,409	2,583	271.6	1,834
Northern AB	23,736	10,315	820	67.0	1,441
Pembina	11,245	8,661	166	12.2	388
South Central AB (2)	9,937	4,365	74	31.6	231
Southeast SK & MB	10,930	10,641	36	1.1	68
Total	107,944	36,391	3,679	383.5	3,962

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

(2) During the second quarters of 2014 and 2015, 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.

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

Sales revenue from crude oil, natural gas, condensate, NGLs and other income was $321.7 million in the second quarter of 2015, a decrease of $245.3 million from $567 million for the same period in the prior year. The decrease reflects a decrease in average commodity pricing which lowered revenue by $213.9 million, as well as decreased crude oil and liquids production volumes that reduced revenue by $44.5 million. The decrease was partially offset by increased natural gas production volumes that contributed additional revenue of $13.1 million. Crude oil, condensate and NGLs revenue accounted for $209.4 million or 65 per cent of second quarter sales revenue.

For the six months ended June 30, 2015, sales revenue from crude oil, natural gas, condensate, NGLs and other income was $628.3 million, a decrease of $490.1 million from $1,118.4 million for the same period in the prior year. The decrease reflects a decrease in average commodity pricing which lowered revenue by $500.2 million, as well as decreased crude oil and liquids production volumes that reduced revenue by $46.5 million. The decrease was partially offset by increased natural gas production volumes that contributed additional revenue of $56.6 million.

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

Table 11

	Three Months Ended				Six Months Ended
	June 30				June 30
Sales revenue by product ($ millions)	2015	2014	% Change		2015	2014	% Change
Crude oil	187.6	328.2	(43	)	344.8	650.6	(47	)
Condensate	18.5	42.1	(56	)	34.4	68.1	(49	)
Natural gas	111.7	180.5	(38	)	237.8	366.6	(35	)
NGLs	3.3	15.0	(78	)	9.5	31.4	(70	)
Total sales revenue from crude oil, natural gas, condensate and NGLs	321.1	565.8	(43	)	626.5	1,116.7	(44	)
Other income	0.6	1.2	(50	)	1.8	1.7	6
Total sales revenue	321.7	567.0	(43	)	628.3	1,118.4	(44	)

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		Six Months Ended
	June 30		June 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	65	68	62	67
Natural gas	35	32	38	33
Total sales revenue from crude oil, natural gas, condensate and NGLs	100	100	100	100
Other income	—	—	—	—
Total sales revenue	100	100	100	100

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Commodity Prices Prior to Hedging

Table 13

	Three Months Ended				Six Months Ended
	June 30				June 30
	2015	2014	% Change		2015	2014	% Change
Average Benchmark Prices
AECO natural gas (Cdn$/Mcf) (1)	2.67	4.65	(43	)	2.81	4.72	(40	)
WTI oil (US$/bbl)	57.95	102.99	(44	)	53.34	100.84	(47	)
Cdn$/US$ exchange rate	1.23	1.09	13		1.24	1.10	13
WTI oil (Cdn$/bbl)	71.28	112.26	(37	)	66.14	110.92	(40	)
Edmonton par (Cdn$/bbl)	67.73	105.62	(36	)	59.83	102.64	(42	)
ARC Realized Prices Prior to Hedging
Crude oil ($/bbl)	64.49	102.14	(37	)	56.20	98.78	(43	)
Condensate ($/bbl)	64.84	103.72	(37	)	56.49	102.31	(45	)
Natural gas ($/Mcf)	2.88	4.99	(42	)	2.97	5.28	(44	)
NGLs ($/bbl)	9.53	39.51	(76	)	12.99	43.76	(70	)
Total commodity price prior to other income and hedging ($/boe)	32.10	56.44	(43	)	30.07	57.16	(47	)
Other income ($/boe)	0.07	0.12	(42	)	0.09	0.08	13
Total commodity price prior to hedging ($/boe)	32.17	56.56	(43	)	30.16	57.24	(47	)

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

In the second quarter of 2015, WTI (US$/bbl) decreased 44 per cent as compared to the same period in 2014. Similarly, ARC’s realized crude oil price decreased by 37 per cent over the same time period. During the second quarter of 2015, the differential between WTI and Edmonton posted prices narrowed to an average discount of US$2.87 per barrel compared to US$6.13 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 $1.23. The narrowing of the differential combined with a weaker Canadian dollar served to mitigate the overall impact of the decrease in WTI on ARC's realized prices.

For the six months ended June 30, 2015, ARC's realized crude oil price fell by 43 per cent as compared to the six months ended June 30, 2014. This price decrease is primarily attributed to the 47 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 second quarter and first half of 2015 as compared to the same periods in 2014 as year-over-year North American supply greatly exceeded demand and left inventory levels much higher at the end of the winter. ARC's second quarter and first half of 2015 average realized prices of $2.88 per Mcf and $2.97 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. Additionally, 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

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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 second quarter of 2015 compared to the same period in 2014:

Table 14

Risk Management Contracts ($ millions)	Crude Oil & Liquids		Natural  Gas		Foreign Currency		Power	Q2 2015 Total		Q2 2014 Total
Realized gain (loss) on contracts (1)	17.6		34.0		(1.9	)	1.1	50.8		(25.4	)
Unrealized gain (loss) on contracts (2)	(29.8	)	(40.1	)	2.8		5.9	(61.2	)	14.8
Gain (loss) on risk management contracts	(12.2	)	(6.1	)	0.9		7.0	(10.4	)	(10.6	)

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

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

Table 14a summarizes the total gain or loss on risk management contracts for the six months ended June 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)	35.3		63.4	(3.9	)	0.6	95.4	(45.6	)
Unrealized gain (loss) on contracts (2)	(33.2	)	48.1	(0.7	)	2.3	16.5	(74.4	)
Gain (loss) on risk management contracts	2.1		111.5	(4.6	)	2.9	111.9	(120.0	)

(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 six months ended June 30, 2015, ARC recorded a loss of $10.4 million and a gain of $111.9 million, respectively, on its risk management contracts comprising realized gains of $50.8 million and unrealized losses of $61.2 million for the second quarter and a realized gain of $95.4 million and an unrealized gain of $16.5 million for the year-to-date. The realized gains primarily reflect positive cash settlements received on crude oil and natural gas contracts with average floor prices of US$90/bbl and $3.94/MMbtu throughout the periods and are partially offset by modest losses on forward foreign currency contracts.

ARC's second quarter 2015 unrealized losses on crude oil contracts primarily reflect higher WTI and Canadian WTI prices as well as positive cash settlements on WTI positions. During the same period, unrealized losses on natural gas contracts reflect higher NYMEX Henry Hub prices, offset by slightly wider AECO basis through 2019. Year-to-date, ARC's unrealized gains on natural gas contracts reflect lower NYMEX Henry Hub prices and wider AECO basis through 2019. Second quarter and year-to-date gains on electricity contracts reflect higher power prices during both periods.

ARC’s risk management contracts provide protection from natural gas prices on 215,000 MMbtu per day for the second half of 2015. ARC has also executed long-term natural gas contracts on 166,100 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 second half 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.

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 June 30, 2015, see Note 8 “Financial Instruments and Market Risk Management” in the financial statements as at and for the three and six months ended June 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 July 29, 2015	H2 2015			2016		2017		2018		2019
Crude Oil - Cdn$ WTI (2)	Cdn$/bbl		bbl/day	Cdn$/bbl	bbl/day	Cdn$/bbl	bbl/day	Cdn$/bbl	bbl/day	Cdn$/bbl	bbl/day
Ceiling	80.95		10,000	83.38	3,000	83.38	1,488	—	—	—	—
Floor	61.45		10,000	70.00	3,000	70.00	1,488	—	—	—	—
Crude Oil - Cdn$ WTI(2)	Cdn$/bbl		bbl/day	Cdn$/bbl	bbl/day	Cdn$/bbl	bbl/day	Cdn$/bbl	bbl/day	Cdn$/bbl	bbl/day
Swap	74.77		5,000	77.20	7,000	—	—	—	—	—	—
Crude Oil - MSW (Differential to WTI) (3)	US$/bbl		bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day
Swap	(4.32	)	3,750	—	—	—	—	—	—	—	—
Natural Gas - NYMEX (4)	US$/MMbtu		MMbtu/day	US$/MMbtu	MMbtu/day	US$/MMbtu	MMbtu/day	US$/MMbtu	MMbtu/day	US$/MMbtu	MMbtu/day
Ceiling	4.51		215,000	4.79	105,000	4.81	145,000	4.92	90,000	5.00	40,000
Floor	3.94		215,000	4.00	105,000	4.00	145,000	4.00	90,000	4.00	40,000
Swap	—		—	4.00	40,000	—	—	—	—	—	—
Natural Gas - AECO (5)	Cdn$/GJ		GJ/day	Cdn$/GJ	GJ/day	Cdn$/GJ	GJ/day	Cdn$/GJ	GJ/day	Cdn$/GJ	GJ/day
Swap	—		—	3.00	20,000	—	—	—	—	—	—
Natural Gas - AECO Basis(6)	AECO/NYMEX		MMbtu/day	AECO/NYMEX	MMbtu/day	AECO/NYMEX	MMbtu/day	AECO/NYMEX	MMbtu/day	AECO/NYMEX	MMbtu/day
Swap (percentage of NYMEX)	89.5		160,000	90.3	140,000	90.2	140,000	85.7	80,000	85.6	24,918
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		24	—	—	—	—	—	—	—	—
Floor	1.0463		24	—	—	—	—	—	—	—	—

(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 8 “Financial Instruments and Market Risk Management” in the financial statements for the three and six months ended June 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 net fair value of ARC’s risk management contracts at June 30, 2015 was a net asset of $274.5 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 second quarter and year-to-date netbacks prior to hedging were $19.29 per boe and $17.52 per boe, respectively, representing decreases of 48 per cent and 54 per cent as compared to the same periods in 2014.

ARC’s 2015 second quarter and year-to-date netbacks, including realized hedging gains and losses, were $24.37 per boe and $22.10 per boe, respectively, representing decreases of 30 per cent and 38 per cent as compared to the same periods in 2014.

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The components of operating netbacks for the second 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		Q2 2015 Total		Q2 2014 Total
	($/bbl)		($/bbl)		($/bbl)		($/Mcf)		($/bbl)		($/boe)		($/boe)
Average sales price	64.95		50.03		64.84		2.88		9.53		32.10		56.44
Other income	—		—		—		—		—		0.07		0.12
Total sales	64.95		50.03		64.84		2.88		9.53		32.17		56.56
Royalties	(5.40	)	(1.24	)	(10.68	)	(0.16	)	(1.80	)	(2.50	)	(8.02	)
Transportation	(2.47	)	(0.42	)	(2.56	)	(0.33	)	(7.55	)	(2.33	)	(2.02	)
Operating expenses (2)	(14.26	)	(8.83	)	(5.97	)	(0.91	)	(6.94	)	(8.05	)	(9.11	)
Netback prior to hedging	42.82		39.54		45.63		1.48		(6.76	)	19.29		37.41
Hedging gain (loss) (3)	6.43		—		—		0.84		—		5.08		(2.53	)
Netback after hedging	49.25		39.54		45.63		2.32		(6.76	)	24.37		34.88
% of total netback	58		1		5		37		(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.

The components of operating netbacks for the six months ended June 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	56.63		42.75		56.49		2.97		12.99		30.07		57.16
Other income	—		—		—		—		—		0.09		0.08
Total sales	56.63		42.75		56.49		2.97		12.99		30.16		57.24
Royalties	(5.61	)	(1.27	)	(9.71	)	(0.18	)	(2.15	)	(2.66	)	(8.21	)
Transportation	(2.71	)	(0.52	)	(2.78	)	(0.31	)	(7.87	)	(2.35	)	(1.97	)
Operating expenses (2)	(12.94	)	(11.88	)	(5.66	)	(0.90	)	(5.77	)	(7.63	)	(9.04	)
Netback prior to hedging	35.37		29.08		38.34		1.58		(2.80	)	17.52		38.02
Hedging gain (loss) (3)	5.81		—		—		0.76		—		4.58		(2.34	)
Netback after hedging	41.18		29.08		38.34		2.34		(2.80	)	22.10		35.68
% of total netback	53		1		5		41		—		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 14.2 per cent ($8.02 per boe) in the second quarter of 2014 to 7.8 per cent ($2.50 per boe) in the second quarter of 2015 reflecting the "sliding scale" effect of royalty rates with the decrease in average commodity prices during that time period. Similarly, total

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royalties decreased from $80.4 million in the second quarter of 2014 to $25 million in the second quarter of 2015. For the six months ended June 30, 2015, total royalties represented 8.8 per cent of pre-hedged commodity product sales ($2.66 per boe) as compared to 14.3 per cent ($8.21 per boe) for the same period in 2014. The decrease in the royalty rate during the first six 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 $8.05 per boe in the second quarter of 2015 compared to $9.11 per boe in the second quarter of 2014. On an absolute dollar basis, operating expenses have decreased by $10.8 million or 12 per cent for the second quarter of 2015 as compared to the second quarter of 2014. The decrease is mainly a result of reduced activity levels and diligent cost control efforts including negotiating service cost decreases with many of ARC's suppliers throughout 2015. Higher electricity costs partially offset this decrease in the second quarter of 2015 compared to the second quarter of 2014 with an average Alberta Power Pool Rate of $57.25 per megawatt hour in 2015 as compared to an average of $42.30 per megawatt hour during the second quarter of 2014. For the six months ended June 30, 2015 operating expenses decreased by $17.8 million or $1.41 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 (the "statements of income"). Had these contracts been recognized within operating expenses, ARC’s operating expenses would have been decreased by $0.11 per boe for the three months ended June 30, 2015 (decreased $0.03 per boe for the six months ended June 30, 2015) as a result of a realized gain of $1.1 million during the period (realized gain of $0.6 million for the six months ended June 30, 2015).

Transportation expense was $2.33 per boe during the second quarter of 2015 ($2.35 per boe for the six months ended June 30, 2015) as compared to $2.02 per boe in the second quarter of 2014. ($1.97 per boe for the six months ended June 30, 2014). The increase in transportation charges during the second quarter of 2015 and year-to-date relative to the same periods 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 in the second quarter of 2015 largely offset the decrease in trucking charges. Additionally, in the second quarter of 2015, turnarounds at a third party natural gas plant required ARC to secure additional takeaway capacity to avoid any possible shut in of production.

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, increased by 26 per cent to $17.7 million in the second quarter of 2015 from $14.1 million in the second quarter of 2014. While G&A expenses before the impact of recoveries and capitalized G&A saw a modest decrease from the second quarter of 2014 to the second quarter of 2015, there was a 40 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 six months ended June 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 $34.2 million, a $4.7 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						Six Months Ended
	June 30						June 30
G&A and Share-Based Compensation	2015		2014		% Change		2015		2014		% Change
($ millions, except per boe)
G&A expenses (1)	25.0		26.3		(5	)	52.2		53.2		(2	)
Capitalized G&A and overhead recoveries	(7.3	)	(12.2	)	(40	)	(18.0	)	(23.7	)	(24	)
G&A expenses before share-based compensation plans	17.7		14.1		26		34.2		29.5		16
G&A – share-based compensation plans (2)	5.5		4.9		12		(0.3	)	9.4		(103	)
Total G&A and share-based compensation expenses	23.2		19.0		22		33.9		38.9		(13	)
Total G&A and share-based compensation expenses per boe	2.32		1.90		22		1.63		1.99		(18	)

(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 $4.1 million during the second quarter of 2015 in accordance with the RSU and PSU Plan, as compared to an expense of $4.4 million during the second quarter of 2014. For the six months ended June 30, 2015, ARC recorded a recovery related to the RSU and PSU Plan of $2.5 million, a decrease of $10.8 million or 130 per cent from the six months ended June 30, 2014. ARC recognized a reduction in compensation charges for both the second quarter of 2015 as compared to the second quarter of 2014 and the six months ended June 30, 2015 as compared to the six months ended June 30, 2014 due to a lower estimated performance multiplier for its PSU awards relative to what ARC had been estimating at the end of the prior quarter. The reduction in compensation charges associated with a lower performance multiplier estimate was further supported by a reduction to the valuation of awards at June 30, 2015, as ARC's share price decreased from $25.16 per share at December 31, 2014 to $21.40 at June 30, 2015.

During the six months endedJune 30, 2015, ARC made cash payments of $14.4 million in respect of the RSU and PSU Plan ($17.3 million for the six months endedJune 30, 2014). Of these payments, $11 million were in respect of amounts recorded to G&A expenses ($12.6 million for the six months endedJune 30, 2014) and $3.4 million were in respect of amounts recorded to operating expenses and capitalized as PP&E and E&E assets ($4.7 million for the six months endedJune 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	215	316	531
Distributed	(147)	(246)	(393)
Forfeited	(52)	(44)	(96)
Balance, June 30, 2015	641	1,539	2,180

(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 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 $14.2 million and $83.4 million will be paid out in 2015 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 June 30, 2015:

Table 19

Value of RSU and PSU Plan as at
June 30, 2015	Performance multiplier
(units thousands and $ millions, except per share)	—	1.0	2.0
Estimated units to vest
RSUs	664	664	664
PSUs	—	1,616	3,232
Total units (1)	664	2,280	3,896
Share price (2)	21.40	21.40	21.40
Value of RSU and PSU Plan upon vesting (3)	14.2	48.8	83.4
2015	3.4	9.3	15.3
2016	5.8	17.4	29.1
2017	3.6	13.8	24.1
2018	1.4	8.3	14.9

(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 $21.40, which is based on the closing share price at June 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 June 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 $22.55 per share. At June 30, 2015, approximately 0.2 million share options were exercisable with a weighted average exercise price of $22.01 per share. Compensation expense of $0.7 million has been recorded during the second quarter of 2015 ($1.5 million for the six months ended June 30, 2015) compared to $0.5 million for the second quarter of 2014 ($1.1 million for the six months ended June 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 six months ended June 30, 2015, a G&A expense of $0.3 million and $nil was recorded in relation to the DSU Plan (expense of $0.7 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. The first LTRSA grant occurred on June 24, 2015. 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 to be 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 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 June 30, 2015, ARC had 88,635 restricted shares outstanding under this plan. For the three and six months ended June 30, 2015, G&A expenses of $0.7 million were recorded in relation to the LTRSA Plan ($nil for the three and six months ended June 30, 2014).

Interest and Financing Charges

Interest and financing charges increased eight per cent to $12.1 million in the second quarter of 2015 from $11.2 million in the second quarter of 2014. For the six months ended June 30, 2015, interest and financing charges were $25 million as compared to $23.2 million in 2014, an increase of eight per cent. The increase in interest charges primarily reflects the increased value of the US dollar relative to the Canadian dollar during the first and second quarters of 2015 as compared to the first and second quarters of 2014 as ARC's debt and related interest obligations are primarily held in US dollars.

At June 30, 2015, ARC had $1.02 billion of long-term debt outstanding, including a current portion of $52.8 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 gain of $16.4 million in the second quarter of 2015 compared to a gain of $25.4 million in the second quarter of 2014. The gain is primarily a result of an unrealized gain on the revaluation of ARC’s US dollar denominated debt outstanding from the period of March 31, 2015 to June 30, 2015 and reflects the change in value of the US dollar relative to the Canadian dollar from $1.2683 to $1.2474.

For the six months ended June 30, 2015, ARC recorded a foreign exchange loss of $71.7 million compared to a loss of $3.6 million for the same period in the prior year. On average, during the six months ended June 30, 2014, the value of the US dollar relative to the Canadian dollar remained relatively flat, from $1.0636 at December 31, 2013 to $1.0676 at June 30, 2014. During the six months ended June 30, 2015, the value of the US dollar relative to the Canadian dollar increased from $1.1601 at December 31, 2014 to $1.2474 at June 30, 2015, resulting in an 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						Six Months Ended
	June 30						June 30
Foreign Exchange Gains and Losses ($ millions)	2015		2014		% Change		2015		2014		% Change
Unrealized gain (loss) on US denominated debt	16.9		25.7		(34	)	(71.4	)	(3.3	)	100
Realized loss on US denominated transactions	(0.5	)	(0.3	)	67		(0.3	)	(0.3	)	—
Total foreign exchange gain (loss)	16.4		25.4		(35	)	(71.7	)	(3.6	)	100

Taxes

ARC recorded a current income tax expense of $1.8 million in the second quarter of 2015 ($4.1 million expense for the six months ended June 30, 2015) compared to $23.3 million expense during the second quarter of 2014 ($47 million expense for the six months ended June 30, 2014). The reduction in current taxes for both the second quarter and the first six months of 2015 reflects lower expected annual taxable income for 2015 related to decreased commodity prices.

During the second quarter of 2015, a deferred income tax expense of $25.1 million was recorded ($38.1 million expense for the six months ended June 30, 2015) compared to an expense of $23.6 million in the second quarter of 2014 ($15 million expense for the six months ended June 30, 2014). For the three and six months ended June 30, 2015 as compared to the three and six months ended June 30, 2014, ARC’s increase in deferred tax expense is related primarily to changes in the book basis of ARC's assets and liabilities relative to their tax basis coupled with an increase to the Alberta corporate tax rate that was substantively enacted during the second quarter of 2015.

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)	June 30, 2015	Annual Deductibility
Canadian oil and gas property expense	672.0	10% declining balance
Canadian development expense	930.1	30% declining balance
Canadian exploration expense	—	100	%
Undepreciated capital cost	801.4	Primarily 25% declining balance
Other	23.7	Various rates, 7% declining balance to 20%
Total federal tax pools	2,427.2
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 six months ended June 30, 2015, ARC recorded DD&A expense prior to any impairment of $152.5 million and $317.8 million as compared to $160.4 million and $310.2 million for the three and six months ended June 30, 2014. The decrease in DD&A expense for the three months ended June 30, 2015 compared to the same period of the prior year reflects decreased production volumes and reduced capital spending on infrastructure. The slight increase in DD&A expense for the six months of 2015 compared to the same period of the prior year reflects higher production volumes, which was partially offset by 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. For the six months endedJune 30, 2015, an impairment charge of $11.7 million ($nil in the six months ended June 30, 2014) was recognized associated with non-core assets located in the south central Alberta district that were disposed in the second quarter of 2015. There

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were no impairment charges or recoveries recorded for the six months ended June 30, 2014. As future commodity prices remain volatile, impairment charges or recoveries could be recorded in future periods.

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

Table 22

	Three Months Ended					Six Months Ended
	June 30					June 30
DD&A Expense ($ millions, except per boe amounts)	2015		2014	% Change		2015	2014	% Change
Depletion of oil and gas assets	150.9		158.8	(5	)	314.6	307.1	2
Depreciation of administrative assets	1.6		1.6	—		3.2	3.1	3
Impairment (recovery) charges	(1.7	)	—	100		11.7	—	100
Total DD&A expense and impairment charges	150.8		160.4	(6	)	329.5	310.2	6
DD&A rate before impairment per boe	15.25		16.00	(5	)	15.25	15.88	(4	)
DD&A and impairment rate per boe	15.08		16.00	(6	)	15.82	15.88	—

At June 30, 2015, ARC recorded an impairment of $44.4 million on an E&E asset. The impairment charge was recorded as part of intangible E&E expenses in the statements of income.

Capital Expenditures, Acquisitions and Dispositions

Capital expenditures before acquisitions, dispositions or purchases of undeveloped land totaled $98.4 million in the second quarter of 2015 as compared to $236.1 million during the second quarter of 2014. This total includes development and production additions to PP&E of $97.3 million and additions to E&E assets of $1.1 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.

During the second quarter of 2015, ARC divested of certain non-core shallow gas assets located in southern Alberta. 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.

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

Table 23

	Three Months Ended June 30
	2015					2014
Capital Expenditures ($ millions)	E&E	PP&E		Total		E&E	PP&E		Total		% Change
Geological and geophysical	0.3	2.8		3.1		—	3.5		3.5		(11	)
Drilling and completions	0.5	51.3		51.8		7.0	174.6		181.6		(71	)
Plant and facilities	0.3	42.9		43.2		1.3	48.1		49.4		(13	)
Administrative assets	—	0.3		0.3		—	1.6		1.6		(81	)
Total capital expenditures	1.1	97.3		98.4		8.3	227.8		236.1		(58	)
Undeveloped land purchased at Crown land sales	—	0.1		0.1		—	16.6		16.6		(99	)
Total capital expenditures including undeveloped land purchases	1.1	97.4		98.5		8.3	244.4		252.7		(61	)
Acquisitions (1)	14.1	—		14.1		—	5.5		5.5		156
Dispositions (2)	—	(14.9	)	(14.9	)	—	(31.8	)	(31.8	)	(53	)
Total capital expenditures, land purchases and net acquisitions and dispositions	15.2	82.5		97.7		8.3	218.1		226.4		(57	)

(1) Excludes $18.1 million of non-cash petroleum and natural gas property transactions in the second quarter of 2015 ($1.9 million in the second quarter of 2014).

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

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For the six months ended June 30, 2015, capital expenditures before property acquisitions, dispositions or purchases of undeveloped land totaled $227.9 million as compared to $478.1 million during the same period of 2014. This total includes development and production additions to PP&E of $227.1 million and additions to E&E assets of $0.8 million.

Table 23a

	Six Months Ended June 30
	2015					2014
Capital Expenditures ($ millions)	E&E	PP&E		Total		E&E	PP&E		Total		% Change
Geological and geophysical	—	5.4		5.4		1.4	8.0		9.4		(43	)
Drilling and completions	0.5	134.3		134.8		16.5	324.2		340.7		(60	)
Plant and facilities	0.3	86.6		86.9		11.1	113.3		124.4		(30	)
Administrative assets	—	0.8		0.8		—	3.6		3.6		(78	)
Total capital expenditures	0.8	227.1		227.9		29.0	449.1		478.1		(52	)
Undeveloped land purchased at Crown land sales	—	1.5		1.5		—	22.4		22.4		(93	)
Total capital expenditures including undeveloped land purchases	0.8	228.6		229.4		29.0	471.5		500.5		(54	)
Acquisitions (1)	14.1	—		14.1		—	36.2		36.2		(61	)
Dispositions (2)	—	(25.9	)	(25.9	)	—	(31.8	)	(31.8	)	(19	)
Total capital expenditures, land purchases and net acquisitions and dispositions	14.9	202.7		217.6		29.0	475.9		504.9		(57	)

(1) Excludes $28.7 million of non-cash petroleum and natural gas property transactions in the six months ended June 30, 2015 ($1.9 million in the six months ended June 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 100 per cent of the $98.5 million second quarter capital program with funds from operations (92 per cent financed with funds from operations and contributions from DRIP and SDP in the second quarter of 2014).

Table 24

	Three Months Ended June 30
	2015			2014
Source of Funding of Capital Expenditures and Net Acquisitions ($ millions)	Capital Expenditures including Land Purchases	Net Acquisitions	Total Expenditures	Capital Expenditures including Land Purchases	Net Acquisitions	Total Expenditures
Expenditures (1)	98.5	14.1	112.6	252.7	5.5	258.2
Funds from operations, net (%) (2)	100	22	90	78	—	76
Contributions from DRIP and SDP (%)	—	78	10	14	—	14
Debt (%)	—	—	—	8	100	10
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.

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Table 24a

	Six Months Ended June 30
	2015			2014
Source of Funding of Capital Expenditures and Net Acquisitions ($ millions)	Capital Expenditures including Land Purchases	Net Acquisitions	Total Expenditures	Capital Expenditures including Land Purchases	Net Acquisitions	Total Expenditures
Expenditures (1)	229.3	14.1	243.4	500.5	36.2	536.7
Funds from operations, net (%) (2)	84	—	79	78	—	73
Contributions from DRIP and SDP (%)	16	100	21	14	—	13
Debt (%)	—	—	—	8	100	14
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 June 30, 2015, ARC has recorded an ARO liability of $574.9 million ($616.1 million at December 31, 2014) for the future abandonment and reclamation of ARC’s properties. The estimated ARO liability 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 2.3 per cent (2.3 per cent at December 31, 2014).

Accretion charges of $3.2 million and $6.8 million for the three and six months ended June 30, 2015 ($3.7 million and $7.6 million for 2014), respectively, have been recognized in the statements of income to reflect the increase in the ARO liability associated with the passage of time.

Actual spending under ARC’s abandonment and reclamation program for the three and six months ended June 30, 2015 was $1.6 million and $3.6 million ($3.1 millionand$6.3 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 $63 million in total over the next 40 years. The balance of this fund totaled $32.3 million at June 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.

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Capitalization, Financial Resources and Liquidity

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

Table 25

Capital Structure and Liquidity ($ millions, except per cent and ratio amounts)	June 30, 2015		December 31, 2014
Long-term debt (1)	1,020.6		1,074.8
Working capital deficit (surplus) (2)	(142.5	)	181.1
Net debt obligations (3)	878.1		1,255.9
Market value of common shares (4)	7,308.1		8,036.1
Total capitalization (3)	8,186.2		9,292.0
Net debt as a percentage of total capitalization	10.7		13.5
Net debt to annualized funds from operations (3)	1.1		1.1

(1) Includes a current portion of long-term debt of $52.8 million at June 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 June 30, 2015 multiplied by the closing share price of $21.40 at June 30, 2015 (closing share price of $25.16 at December 31, 2014).

At June 30, 2015, ARC had total available credit facilities of approximately $2.2 billion with debt of $1.02 billion currently drawn. ARC’s long-term debt balance includes a current portion of $52.8 million at June 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 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.

ARC’s debt agreements contain a number of covenants, all of which were met as at June 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 June 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	1.0
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	1.0
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 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.

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Shareholders’ Equity

At June 30, 2015, there were 341.5 million shares outstanding, an increase of 22.1 million shares over shares issued at 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 4.2 million shares issued are attributable to those issued to participants in the DRIP and SDP.

At June 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 $22.55 per share. These options vest in equal parts on the fourth and fifth anniversaries of the grant date. At June 30, 2015, approximately 0.2 million share options were exercisable with a weighted average exercise price of $22.01 per share.

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. The first LTRSA grant occurred on June 24, 2015. At June 30, 2015, ARC had 88,635 restricted shares outstanding under this plan. 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 second quarter of 2015, ARC declared dividends totaling $102.1 million ($0.30 per share) compared to $94.8 million ($0.30 per share) during the second 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 second quarter dividend was equal to 49 per cent of second quarter 2015 funds from operations.

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 July 16, 2015, ARC confirmed that a dividend of $0.10 per common share designated as an eligible dividend will be paid on August 17, 2015 to shareholders of record on July 31, 2015 with an ex-dividend date of July 29, 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 six months ended June 30, 2015, ARC increased its transportation commitments by approximately $81.3 million and $82.1 million, respectively, from those presented at December 31, 2014. There were no other material changes to ARC's commitments and contingencies from those presented as at December 31, 2014.

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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 June 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 consolidated financial statements for the year ended December 31, 2014.

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;

ARC Resources Ltd. Page 24

• 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;

• 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 June 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 June 30, 2015.

ARC Resources Ltd. Page 25

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 July 2015, the IASB unanimously affirmed its proposal to defer the effective date of IFRS 15 to January 1, 2018. Pending approval from the Accounting Standards Board ("AcSB"), 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.

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 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,"

ARC Resources Ltd. Page 26

"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).

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 27

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

DD&A        depreciation, depletion 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 28

QUARTERLY HISTORICAL REVIEW

($ millions, except per share amounts)	2015				2014							2013
FINANCIAL	Q2		Q1		Q4		Q3		Q2		Q1	Q4	Q3
Sales of crude oil, natural gas, condensate, NGLs and other income	321.7		306.6		454.1		535.2		567.0		551.4	425.0	417.4
Per share, basic (1)	0.95		0.92		1.43		1.69		1.79		1.75	1.36	1.34
Per share, diluted (1)	0.94		0.92		1.42		1.68		1.79		1.75	1.35	1.34
Funds from operations (2)	206.3		191.5		251.7		284.2		295.8		292.3	237.8	220.4
Per share, basic (1)	0.61		0.57		0.79		0.90		0.94		0.93	0.76	0.71
Per share, diluted (1)	0.61		0.57		0.79		0.89		0.93		0.93	0.76	0.71
Net income (loss)	(51.0	)	(1.7	)	113.7		90.3		147.4		29.4	13.6	86.9
Per share, basic (1)	(0.15	)	(0.01	)	0.36		0.28		0.47		0.09	0.04	0.28
Per share, diluted (1)	(0.15	)	(0.01	)	0.36		0.28		0.47		0.09	0.04	0.28
Dividends declared	102.1		101.6		95.7		95.2		94.8		94.5	94.0	93.7
Per share (1)	0.30		0.30		0.30		0.30		0.30		0.30	0.30	0.30
Total assets	6,346.0		6,588.8		6,325.5		6,095.5		5,988.7		5,949.5	5,736.0	5,599.2
Total liabilities	2,565.7		2,704.2		2,773.7		2,603.5		2,531.1		2,580.7	2,339.9	2,156.6
Net debt outstanding (3)	878.1		950.5		1,255.9		1,152.8		1,061.9		1,096.0	1,011.5	936.5
Weighted average shares outstanding	340.4		333.2		318.6		317.2		315.9		314.7	313.5	312.2
Weighted average shares outstanding, diluted	340.7		333.5		319.1		317.8		316.6		315.2	313.9	312.5
Shares outstanding, end of period	341.5		339.3		319.4		317.8		316.5		315.3	314.1	312.8
CAPITAL EXPENDITURES
Geological and geophysical	3.1		2.3		4.7		3.5		3.5		5.9	6.6	4.5
Drilling and completions	51.8		83.0		164.4		154.9		181.6		159.1	140.9	179.2
Plant and facilities	43.2		43.7		78.2		58.8		49.4		75.0	58.8	65.6
Administrative assets	0.3		0.5		2.0		1.0		1.6		2.0	1.4	1.0
Total capital expenditures	98.4		129.5		249.3		218.2		236.1		242.0	207.7	250.3
Undeveloped land purchased at Crown land sales	0.1		1.4		18.0		21.9		16.6		5.8	3.5	8.9
Total capital expenditures including undeveloped land purchases	98.5		130.9		267.3		240.1		252.7		247.8	211.2	259.2
Acquisitions	14.1		—		—		37.3		5.5		30.7	12.4	12.6
Dispositions	(14.9	)	(11.0	)	(2.4	)	(5.1	)	(31.8	)	—	0.5	(53.6	)
Total capital expenditures, land purchases and net acquisitions and dispositions	97.7		119.9		264.9		272.3		226.4		278.5	224.1	218.2
OPERATING
Production
Crude oil (bbl/d)	31,958		35,851		37,442		35,871		35,317		37,478	35,542	31,438
Condensate (bbl/d)	3,139		3,591		3,448		3,862		4,462		2,887	2,580	2,235
Natural gas (MMcf/d)	426.0		459.6		432.1		424.5		397.2		369.6	359.4	348.9
NGLs (bbl/d)	3,795		4,314		5,075		5,056		4,179		3,743	2,868	2,687
Total (boe/d)	109,900		120,354		117,986		115,530		110,165		105,699	100,883	94,515
Average realized prices, prior to hedging
Crude oil ($/bbl)	64.49		48.73		72.49		93.34		102.14		95.58	82.85	101.43
Condensate ($/bbl)	64.84		49.12		74.04		95.55		103.72		100.11	88.72	96.70
Natural gas ($/Mcf)	2.88		3.05		4.15		4.46		4.99		5.60	3.61	2.94
NGLs ($/bbl)	9.53		16.07		32.69		39.61		39.51		48.54	41.47	36.80
Oil equivalent ($/boe)	32.10		28.20		41.78		50.28		56.44		57.91	45.51	47.94
TRADING STATISTICS
($, based on intra-day trading)
High	25.60		25.87		29.85		32.60		33.68		30.66	29.95	28.65
Low	21.01		20.75		22.70		28.54		30.30		27.52	25.68	24.71
Close	21.40		21.76		25.16		29.55		32.49		30.45	29.57	26.27
Average daily volume (thousands)	1,424		1,944		1,886		1,205		1,037		1,248	1,030	1,004

(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 29

ARC RESOURCES LTD.
CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)
(Cdn$ millions)	June 30, 2015		December 31, 2014
ASSETS
Current assets
Cash and cash equivalents	222.0		7.1
Short-term investment	4.1		3.6
Accounts receivable	135.3		165.0
Prepaid expenses	19.2		14.3
Risk management contracts (Note 8)	102.4		131.8
Assets held for sale (Note 5)	—		5.8
	483.0		327.6
Reclamation fund	32.3		35.2
Risk management contracts (Note 8)	173.1		128.0
Intangible exploration and evaluation assets (Note 4)	249.9		266.4
Property, plant and equipment (Note 5)	5,159.5		5,320.1
Goodwill	248.2		248.2
Total assets	6,346.0		6,325.5
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	204.0		339.1
Current portion of long-term debt (Note 6)	52.8		49.5
Current portion of asset retirement obligations (Note 7)	13.0		13.0
Dividends payable	34.1		32.0
Risk management contracts (Note 8)	0.5		1.0
Liabilities associated with assets held for sale (Note 7)	—		5.5
	304.4		440.1
Risk management contracts (Note 8)	0.5		1.0
Long-term debt (Note 6)	967.8		1,025.3
Long-term incentive compensation liability (Note 10)	23.0		29.1
Other deferred liabilities	14.9		15.8
Asset retirement obligations (Note 7)	561.9		603.1
Deferred taxes	693.2		659.3
Total liabilities	2,565.7		2,773.7
Commitments and contingencies (Note 11)
SHAREHOLDERS’ EQUITY
Shareholders’ capital	4,434.1		3,951.1
Contributed surplus	10.3		8.6
Deficit	(664.3	)	(407.9	)
Accumulated other comprehensive income	0.2		—
Total shareholders’ equity	3,780.3		3,551.8
Total liabilities and shareholders’ equity	6,346.0		6,325.5

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 30

ARC RESOURCES LTD.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) (unaudited)
For the three and six months ended June 30
	Three months ended				Six Months Ended
	June 30				June 30
(Cdn$ millions, except per share amounts)	2015		2014		2015		2014
REVENUE
Sales of crude oil, natural gas, condensate, natural gas liquids and other income	321.7		567.0		628.3		1,118.4
Royalties	(25.0	)	(80.4	)	(55.4	)	(160.4	)
	296.7		486.6		572.9		958.0
Gain (loss) on risk management contracts (Note 8)	(10.4	)	(10.6	)	111.9		(120.0	)
	286.3		476.0		684.8		838.0
EXPENSES
Transportation	23.3		20.3		48.9		38.4
Operating	80.5		91.3		158.9		176.7
Intangible exploration and evaluation expenses (Note 4)	44.4		1.7		44.4		1.7
General and administrative	23.2		19.0		33.9		38.9
Interest and financing charges	12.1		11.2		25.0		23.2
Accretion of asset retirement obligations (Note 7)	3.2		3.7		6.8		7.6
Depletion, depreciation, amortization and impairment (Note 5)	150.8		160.4		329.5		310.2
Loss (gain) on foreign exchange	(16.4	)	(25.4	)	71.7		3.6
Gain on short-term investment	(0.1	)	(0.5	)	(0.5	)	(1.1	)
Gain on disposal of petroleum and natural gas properties	(10.6	)	—		(23.3	)	—
	310.4		281.7		695.3		599.2
Provision for income taxes
Current	1.8		23.3		4.1		47.0
Deferred	25.1		23.6		38.1		15.0
	26.9		46.9		42.2		62.0
Net income (loss)	(51.0	)	147.4		(52.7	)	176.8
Net income (loss) per share (Note 9)
Basic	(0.15	)	0.47		(0.16	)	0.56
Diluted	(0.15	)	0.47		(0.16	)	0.56

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 31

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)
For the three and six months ended June 30
	Three months ended			Six Months Ended
	June 30			June 30
(Cdn$ millions)	2015		2014	2015		2014
Net income (loss)	(51.0	)	147.4	(52.7	)	176.8
Other comprehensive income
Items that may be reclassified into earnings, net of tax:
Net unrealized gain on reclamation fund investments	(0.1	)	—	0.2		—
Other comprehensive income	(0.1	)	—	0.2		—
Comprehensive income (loss)	(51.1	)	147.4	(52.5	)	176.8

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 32

ARC RESOURCES LTD.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (unaudited)
For the six months ended June 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	—		—	176.8		—	176.8
Shares issued pursuant to the dividend reinvestment program	55.1		—	—		—	55.1
Shares issued pursuant to the stock dividend program	16.6		—	—		—	16.6
Cancellation of shares and return of accrued dividends	(0.8	)	1.9	—		—	1.1
Recognized under share-based compensation plans (Note 10)	—		1.2	—		—	1.2
Dividends declared	—		—	(189.3	)	—	(189.3	)
June 30, 2014	3,871.7		6.9	(421.0	)	—	3,457.6
December 31, 2014	3,951.1		8.6	(407.9	)	—	3,551.8
Net income (loss)	—		—	(52.7	)	—	(52.7	)
Other comprehensive income	—		—	—		0.2	0.2
Total comprehensive income (loss)	—		—	(52.7	)	0.2	(52.5	)
Shares issued for cash	402.7		—	—		—	402.7
Shares issued pursuant to the dividend reinvestment program	70.6		—	—		—	70.6
Shares issued pursuant to the stock dividend program	22.3		—	—		—	22.3
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 10)	—		1.6	—		—	1.6
Dividends declared	—		—	(203.7	)	—	(203.7	)
June 30, 2015	4,434.1		10.3	(664.3	)	0.2	3,780.3

(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 33

ARC RESOURCES LTD.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
For the three and six months ended June 30
	Three months ended				Six Months Ended
	June 30				June 30
(Cdn$ millions)	2015		2014		2015		2014
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)	(51.0	)	147.4		(52.7	)	176.8
Add items not involving cash:
Unrealized loss (gain) on risk management contracts	61.2		(14.8	)	(16.5	)	74.4
Accretion of asset retirement obligations (Note 7)	3.2		3.7		6.8		7.6
Depletion, depreciation, amortization and impairment (Note 5)	150.8		160.4		329.5		310.2
Intangible exploration and evaluation expenses (Note 4)	44.4		1.7		44.4		1.7
Unrealized loss (gain) on foreign exchange	(16.9	)	(25.7	)	71.4		3.3
Gain on disposal of petroleum and natural gas properties	(10.6	)	—		(23.3	)	—
Deferred tax expense	25.1		23.6		38.1		15.0
Other (Note 12)	0.1		(0.5	)	0.1		(0.9	)
Net change in other liabilities (Note 12)	1.7		(1.1	)	(9.9	)	(14.6	)
Change in non-cash working capital (Note 12)	(5.9	)	40.3		(40.1	)	20.8
	202.1		335.0		347.8		594.3
CASH FLOW FROM FINANCING ACTIVITIES
Issuance (repayment) of long-term debt under revolving credit facilities, net	—		(26.9	)	(83.8	)	31.9
Repayment of senior notes	(28.4	)	(33.0	)	(40.9	)	(33.0	)
Issue of common shares (Note 9)	—		—		402.7		—
Share issue costs (Note 9)	(0.1	)	—		(16.7	)	—
Cash dividends paid	(53.9	)	(59.1	)	(108.8	)	(117.4	)
	(82.4	)	(119.0	)	152.5		(118.5	)
CASH FLOW FROM INVESTING ACTIVITIES
Acquisition of petroleum and natural gas properties (Note 5)	(14.1	)	(5.5	)	(14.1	)	(36.2	)
Disposal of petroleum and natural gas properties	14.9		31.8		25.9		31.8
Property, plant and equipment development expenditures (Note 5)	(97.4	)	(244.4	)	(228.5	)	(471.5	)
Intangible exploration and evaluation asset expenditures (Note 4)	(1.1	)	(8.3	)	(0.8	)	(29.0	)
Net reclamation fund withdrawals (contributions)	(1.0	)	(1.0	)	3.0		(0.2	)
Change in non-cash working capital (Note 12)	10.4		8.2		(70.9	)	35.7
	(88.3	)	(219.2	)	(285.4	)	(469.4	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	31.4		(3.2	)	214.9		6.4
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	190.6		9.6		7.1		—
CASH AND CASH EQUIVALENTS, END OF PERIOD	222.0		6.4		222.0		6.4
The following are included in cash flow from operating activities:
Income taxes paid in cash	4.5		7.4		42.1		20.6
Interest paid in cash	10.0		12.4		25.8		23.9

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 34

NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

June 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 changes to the use of estimates or judgments since December 31, 2014.

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 July 29, 2015.

3. CHANGES IN ACCOUNTING POLICIES

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 July 2015, the IASB unanimously affirmed its proposal to defer the effective date of IFRS 15 to January 1, 2018. Pending approval from the Accounting Standards Board ("AcSB"), 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.

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

Carrying amount
Balance, December 31, 2014	266.4
Additions	0.8
Acquisitions	27.1
Intangible exploration and evaluation expenses	(44.4	)
Balance, June 30, 2015	249.9

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ARC has certain E&E properties that have sales of petroleum products associated with production from test wells. For the six months ended June 30, 2015 and 2014, these operating results have been recognized in the condensed interim consolidated statements of income (the "statements of income") and comprised sales of crude oil, natural gas, condensate and natural gas liquids of $4.1 million and $8.2 million, royalties of $0.1 million and $0.4 million, operating expenses of $2.8 million and $1.7 million, and transportation expenses of $0.7 million and $0.5 million, respectively. All cash flows associated with E&E assets for the six months ended June 30, 2015 and 2014 are reflected in cash flow from operating activities.

Due to current industry fundamentals, the Company's capital allocation decisions have impacted the planned development of some E&E assets. At June 30, 2015, ARC performed an impairment test on one of its E&E assets as Management has decided to indefinitely delay any further investment to evaluate the asset and sufficient data exists to indicate that the carrying value of the asset would not be fully recovered from any future development or sale. The recoverable amount of this asset was estimated as its fair value less costs of disposal based on the following:

i. the net present value of the after-tax cash flows from oil and gas reserves of this asset based on reserves estimated by ARC’s independent reserve evaluator with consideration given to recent transactions completed within the industry on assets with similar geological and geographic characteristics; and

ii. the fair value of undeveloped land based on estimates provided by ARC’s independent land evaluator with consideration given to recent transactions completed within the industry on similar lands.

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

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

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

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

The impairment test carried out at June 30, 2015 was based on a fair value less costs of disposal calculation, using an after-tax discount rate of 9.5 per cent and the following forward commodity price estimates:

	Edmonton Light Crude Oil	WTI Oil	AECO Gas	Cdn$/US$
Year	(Cdn$/bbl) (1)	(US$/bbl) (1)	(Cdn$/MMbtu) (1)	Exchange Rates (1)
2015	71.56	61.25	3.13	0.80
2016	75.76	67.50	3.30	0.83
2017	76.47	70.00	3.50	0.85
2018	82.35	75.00	3.79	0.85
2019	88.24	80.00	3.99	0.85
2020	94.12	85.00	4.20	0.85
2021	100.00	90.00	4.40	0.85
2022	101.36	91.90	4.61	0.85
2023	103.38	93.73	4.80	0.85
2024	105.46	95.61	4.89	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 July 1, 2015.

At June 30, 2015, ARC recorded an impairment in intangible E&E expenses in the statements of income of $44.4 million on this asset based on a recoverable amount of $10 million. The estimated recoverable amount of the

ARC Resources Ltd. Page 36

impaired E&E asset is classified as a Level 2 fair value measurement. Refer to Note 8 for information on fair value hierarchy classifications.

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	227.8		0.8		228.6
Acquisitions	15.6		—		15.6
Change in asset retirement cost	18.0		—		18.0
Assets reclassified as held for sale	(213.7	)	—		(213.7	)
Balance, June 30, 2015	7,964.8		62.2		8,027.0
Accumulated depletion, depreciation, amortization and impairment
Balance, December 31, 2014	(2,630.3	)	(28.1	)	(2,658.4	)
Depletion, depreciation, amortization and impairment	(326.4	)	(3.1	)	(329.5	)
Accumulated depletion and impairment reclassified as held for sale	120.4		—		120.4
Balance, June 30, 2015	(2,836.3	)	(31.2	)	(2,867.5	)
Carrying amounts
Balance, December 31, 2014	5,286.8		33.3		5,320.1
Balance, June 30, 2015	5,128.5		31.0		5,159.5

For the three and six months ended June 30, 2015, $5.1 million and $12.8 million of direct and incremental general and administrative expenses were capitalized to property, plant and equipment ("PP&E") ($9.7 millionand$18.8 million for the three and six months ended June 30, 2014), respectively.

Assets held for sale
Balance, December 31, 2014	5.8
Additions	93.3
Disposals	(99.1	)
Balance, June 30, 2015	—

ARC Resources Ltd. Page 37

6. LONG-TERM DEBT

	U.S. $ Denominated		Canadian $ Amount
	June 30, 2015	December 31, 2014	June 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	35.1	32.6
4.98% US$ note	40.0	50.0	50.0	58.0
3.72% US$ note	150.0	150.0	187.1	174.0
2004 Note Issuance
5.10% US$ note	4.8	9.6	6.0	11.1
2009 note issuance
7.19% US$ note	13.5	27.0	16.8	31.3
8.21% US$ note	35.0	35.0	43.7	40.6
6.50% Cdn$ note	—	—	5.8	11.6
2010 note issuance
5.36% US$ note	150.0	150.0	187.1	174.0
2012 note issuance
3.31% US$ note	60.0	60.0	74.8	69.7
3.81% US$ note	300.0	300.0	374.2	348.1
4.49% Cdn$ note	—	—	40.0	40.0
Total long-term debt outstanding	781.4	809.7	1,020.6	1,074.8
Long-term debt due within one year			52.8	49.5
Long-term debt due beyond one year			967.8	1,025.3

At June 30, 2015, the fair value of all senior notes is $1,009.8 million ($974.4 million as at December 31, 2014), compared to a carrying value of $1,020.6 million ($991 million as at December 31, 2014).

7. ASSET RETIREMENT OBLIGATIONS

	Six Months Ended June 30, 2015		Year Ended December 31, 2014
Balance, beginning of period	616.1		475.4
Increase in liabilities relating to development activities	3.1		12.6
Increase in liabilities relating to change in estimates and discount rate	14.9		174.2
Settlement of reclamation liabilities	(3.6	)	(23.0	)
Accretion	6.8		14.9
Dispositions	(62.4	)	(32.5	)
Reclassified as liabilities associated with assets held for sale	—		(5.5	)
Balance, end of period	574.9		616.1
Expected to be incurred within one year	13.0		13.0
Expected to be incurred beyond one year	561.9		603.1

The Bank of Canada's long-term risk-free bond rate of 2.3 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 June 30, 2015.

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8. 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 6. To estimate the fair value of these transactions, 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 fair value measurements 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 six months ended June 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.

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.

ARC Resources Ltd. Page 39

The following is a summary of ARC's financial assets and financial liabilities that are subject to offsetting as at June 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 June 30, 2015
Risk management contracts
Current asset	117.4		(14.1	)	103.3		(0.9	)	102.4
Long-term asset	184.6		(9.8	)	174.8		(1.7	)	173.1
Current liability	(14.6	)	14.1		(0.5	)	—		(0.5	)
Long-term liability	(10.4	)	9.8		(0.6	)	0.1		(0.5	)
Net position	277.0		—		277.0		(2.5	)	274.5
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 June 30, 2015.

Financial Cdn$ WTI Crude Oil Contracts (1)
			Volume	Bought Put	Sold Call
Term		Contract	bbl/d	Cdn$/bbl	Cdn$/bbl
1-Jul-15	30-Sep-15	Collar	5,000	60.20	80.00
1-Jul-15	31-Dec-15	Collar	5,000	62.00	81.27
1-Oct-15	31-Dec-15	Collar	5,000	61.60	81.26
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-Jul-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-Jul-15	30-Sep-15	Swap	3,500	(3.64)
1-Oct-15	31-Dec-15	Swap	4,000	(4.92)

(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.

ARC Resources Ltd. Page 40

Financial NYMEX Natural Gas Contracts (4)
			Volume	Bought Put	Sold Call
Term		Contract	MMbtu/d	US$/MMbtu	US$/MMbtu
1-Jul-15	31-Dec-15	Collar	145,000	3.91	4.30
1-Jul-15	31-Dec-17	Collar	70,000	4.00	4.93
1-Jan-16	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 AECO Natural Gas Swap Contracts (5)
			Volume	Sold Swap
Term		Contract	GJ/d	Cdn$/GJ
1-Jan-16	31-Dec-16	Swap	20,000	3.00

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

Financial AECO Basis Swap Contracts (6)
			Volume	Ratio Sold Swap %
Term		Contract	MMbtu/d	AECO/NYMEX
1-Jul-15	31-Dec-15	Swap	30,000	85.2
1-Jul-15	31-Dec-17	Swap	110,000	90.6
1-Jul-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

(6) 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 (7)
			Volume	Heat Rate
Term		Contract	MWh	GJ/MWh
1-Jul-15	31-Dec-17	Heat Rate Swap	20	13.71

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

Financial Electricity Contracts (8)
			Volume	Bought Swap
Term		Contract	MWh	Cdn$/MWh
1-Jul-15	31-Dec-16	Fixed Rate Swap	5	51.00

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

Foreign Exchange Contracts (9)
			Volume	Bought Put	Sold Call
Term		Contract	US$ millions/month	Cdn$/US$	Cdn$/US$
1-Jul-15	31-Dec-15	Collar	2.0	1.0400	1.0925

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

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Foreign Exchange Swap Contracts (10)
			Volume	Sold Swap	Limit Price
Term		Contract	US$ millions/month	Cdn$/US$	Cdn$/US$ (11)
1-Jul-15	31-Dec-15	Limit Swap	2.0	1.0525	1.1350

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

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

9. SHAREHOLDERS’ CAPITAL

(thousands of shares)	Six Months Ended June 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	89		—
Unvested restricted shares held in trust pursuant to the LTRSA Plan	(89	)	—
Cancelled shares	(1	)	(47	)
Dividend reinvestment program	3,190		4,159
Stock dividend program	1,009		1,260
Common shares, end of period	341,496		319,439

(1) Long-term Restricted Share Award.

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

	Three Months Ended June 30		Six Months Ended June 30
(thousands of shares)	2015	2014	2015	2,014
Weighted average common shares	340,418	315,917	336,850	315,314
Dilutive impact of share-based compensation	284	657	281	599
Weighted average common shares - diluted	340,702	316,574	337,131	315,913

Dividends declared for the three and six months ended June 30, 2015 and 2014 were $0.30 and $0.60 per common share, respectively.

On July 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 July 31, 2015. The dividend payment date is August 17, 2015. Of the $34.1 million in dividends payable at June 30, 2015, $4.3 million is payable in common shares under the Stock Dividend Program ($4.2 million at December 31, 2014).

10. 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 six months ended June 30, 2015:

(number of units, thousands)	RSUs		PSUs(1)		DSUs
Balance, December 31, 2014	625		1,513		220
Granted	215		316		43
Distributed	(147	)	(246	)	—
Forfeited	(52	)	(44	)	—
Balance, June 30, 2015	641		1,539		263

(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:

	Six Months Ended June 30, 2015		Six Months Ended June 30, 2014
General and administrative expenses (recoveries)	(2.3	)	9.2
Operating expense	0.5		2.5
PP&E	0.1		1.7
Total compensation charges (recoveries)	(1.7	)	13.4
Cash payments	14.4		17.3

At June 30, 2015, $20.8 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 $23 million was included in long-term incentive compensation liability ($29.1 million at December 31, 2014). A recoverable amount of $0.4 million was included in accounts receivable at June 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:

	Six Months Ended June 30, 2015	Six Months Ended June 30, 2014
Grant date share price ($)	20.20 - 32.94	20.20 - 32.94
Exercise price ($) (1)	16.60 - 31.74	17.80 - 32.94
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 $0.7 million and $1.5 million relating to the share option plan for the three and six months ended June 30, 2015 ($0.5 millionand$1.1 million for the three and six months ended June 30, 2014). During the three and six months endedJune 30, 2015, $nil and $0.1 million of share option compensation charges were capitalized to PP&E ($0.1 million for the three and six months ended June 30, 2014).

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The changes in total share options outstanding and related weighted average exercise prices for the six months ended June 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	(86	)	22.91
Balance, June 30, 2015	3,418		22.55
Exercisable, June 30, 2015	178		22.01

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.

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 to be 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 June 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

ARC recorded general and administrative expenses of $0.7 million relating to the cash payment under the LTRSA Plan for the three and six months ended June 30, 2015 ($nil for the three and six months ended June 30, 2014). At June 30, 2015, $0.7 million of compensation amounts payable were included in accounts payable and accrued liabilities on the balance sheet ($nil at December 31, 2014).

11. COMMITMENTS AND CONTINGENCIES

During the three and six months ended June 30, 2015, ARC increased its transportation commitments by approximately $81.3 million and $82.1 million, respectively, from those presented at December 31, 2014. There were no other material changes to ARC's commitments and contingencies from those presented as at December 31, 2014.

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12. SUPPLEMENTAL DISCLOSURES

Presentation in the Statements of Income

ARC’s statements of income 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:

	Three Months Ended		Six Months Ended
	June 30		June 30
	2015	2014	2015	2014
Operating	9.2	7.9	18.5	17.2
General and administrative	18.5	19.3	28.5	38.9
Total employee compensation expenses	27.7	27.2	47.0	56.1

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				Six Months Ended
	June 30				June 30
Change in Non-Cash Working Capital	2015		2014		2015		2014
Accounts receivable	(0.6	)	18.9		29.7		(38.8	)
Accounts payable and accrued liabilities	9.6		30.2		(135.8	)	93.7
Prepaid expenses	(4.5	)	(0.6	)	(4.9	)	1.6
Total	4.5		48.5		(111.0	)	56.5
Relating to:
Operating activities	(5.9	)	40.3		(40.1	)	20.8
Investing activities	10.4		8.2		(70.9	)	35.7
Total change in non-cash working capital	4.5		48.5		(111.0	)	56.5

	Three Months Ended				Six Months Ended
	June 30				June 30
Other Non-Cash Items	2015		2014		2015		2014
Non-cash lease inducement	(0.5	)	(0.5	)	(0.9	)	(0.9	)
Gain on short-term investment	(0.1	)	(0.5	)	(0.5	)	(1.1	)
Share-based compensation expense	0.7		0.5		1.5		1.1
Total other non-cash items	0.1		(0.5	)	0.1		(0.9	)

	Three Months Ended				Six Months Ended
	June 30				June 30
Net Change in Other Liabilities	2015		2014		2015		2014
Long-term incentive compensation liability	3.5		2.1		(6.1	)	(8.2	)
Risk management contracts	(0.2	)	(0.1	)	(0.2	)	(0.1	)
Asset retirement obligations	(1.6	)	(3.1	)	(3.6	)	(6.3	)
Total net change in other liabilities	1.7		(1.1	)	(9.9	)	(14.6	)

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