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 30, 2014 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, 2014, and the MD&A and audited consolidated financial statements as at and for the year ended December 31, 2013, 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 with near-term and long-term oil, natural gas, condensate and NGLs growth prospects 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 acquisition and 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, and running 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 with a clear line of sight towards 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 flows to fund future growth.

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 capital expenditures necessary to replace production declines and dividend payments using funds from operations ⁽¹⁾. ARC will finance growth 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 within its organization. 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 2014, ARC had approximately 585 employees with 344 professional, technical and support staff in the Calgary office, and 241 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 18.5 per cent (Table 1).

Table 1

Total Returns (1)	Trailing One Year	Trailing Three Year	Trailing Five Year
Dividends per share ($)	1.20	3.60	6.00
Capital appreciation per share ($)	4.96	7.48	14.68
Total return per share (%)	23.0	49.3	134.3
Annualized total return per share (%)	23.0	14.3	18.5
S&P/TSX Exploration & Producers Index annualized total return (%)	41.3	3.0	7.0

(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, 2014.

Since 2010, ARC’s production has grown by 33,990 boe per day, or 46 per cent, while its proved plus probable reserves have grown by 148.8 million boe, or 31 per cent. Table 2 highlights ARC’s production and reserves for the first six months of 2014 and over the past four years:

Table 2

	2014 YTD	2013	2012	2011	2010
Production (boe/d)	107,944	96,087	93,546	83,416	73,954
Daily production per share, boe per thousand shares (1)	0.34	0.31	0.31	0.29	0.28
Proved plus probable reserves (mmboe) (2)(3)(4)	N/A	633.9	607.0	572.4	485.1
Proved plus probable reserves per share (boe) (5)	N/A	2.0	2.0	2.0	1.8

(1) Daily production per share represents average daily production for the six months ended June 30, 2014 and annual daily average production for the full years ending December 31, 2013, 2012, 2011 and 2010, divided by the diluted weighted average common shares for the respective periods.

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

(3) 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.

(4) 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 Sixth Consecutive Year of 200 per cent or Greater Produced Reserves Replacement in 2013” dated February 5, 2014.

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

ECONOMIC ENVIRONMENT

ARC’s second quarter 2014 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
	2014	2013	% Change	2014	2013	% Change
Brent (US$/bbl)	109.76	103.35	6	108.82	107.91	1
WTI oil (US$/bbl)	102.98	94.23	9	100.81	94.28	7
Edmonton Par (Cdn$/bbl)	105.62	92.70	14	102.64	90.46	13
Henry Hub NYMEX (US$/mmbtu) (2)	4.67	4.09	14	4.79	3.72	29
AECO natural gas (Cdn$/mcf)	4.68	3.59	30	4.72	3.34	41
Cdn$/US$ exchange rate	1.09	1.02	7	1.10	1.02	8

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

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

Global crude oil prices remained strong through the second quarter of 2014 as a result of support from increased demand. WTI crude oil prices averaged US$102.98 per barrel during the second quarter of 2014, nine per cent higher than the

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second quarter of 2013. Brent crude oil prices remained strong throughout the second quarter on expected growth in global crude oil demand and ongoing geopolitical uncertainty. The benchmark Canadian light crude oil price, Edmonton Par, averaged $105.62 per barrel in the second quarter of 2014, 14 per cent higher than the second quarter of 2013. The WTI/Edmonton Par differential averaged a discount of US$6.13 per barrel during the second quarter of 2014. As compared to 2013, the volatility associated with Canadian crude oil differentials during the first half of 2014 was less significant due to commissioning of certain pipeline and infrastructure projects and strong refinery utilization. Additional pipeline and infrastructure projects and increased crude oil rail capacity are anticipated in 2014, and are expected to further alleviate certain bottlenecks. However, in the near-term, crude oil differentials may experience continued volatility until additional infrastructure capacity is available to meet the growing North American production level.

North American natural gas prices increased substantially in 2014 with the second quarter NYMEX Henry Hub (“NYMEX”) and AECO monthly (“AECO”) prices approximately 14 per cent and 30 per cent higher than second quarter 2013 levels, respectively. While ARC's diversified sales portfolio provides price exposure to a variety of markets, ARC's realized price on natural gas is primarily referenced to the AECO Hub. The AECO/NYMEX differential narrowed significantly in the first quarter of 2014 due to a prolonged cold winter that resulted in high western Canadian exports to the US and record intra-Alberta demand. As a result, Alberta natural gas inventories were drawn down to multi-year lows. Despite record North American natural gas production, natural gas inventories remained at low levels through the second quarter, therefore supporting domestic natural gas prices. Over the long-term, ARC expects demand for natural gas to increase due to the potential export of liquefied natural gas, increased natural gas power generation, increased exports to Mexico, and increased usage from the transportation and industrial sectors.

The devaluation of the Canadian dollar relative to the US dollar, which started in 2013 and continued through the first half of 2014, was attributed to a strengthening of the US economy relative to the Canadian economy. In particular, higher growth and employment rates in the US resulted in easing of the Federal Reserve’s financial stimulus program. Given that North American crude oil and natural gas benchmark prices are denominated in US dollars, the strengthening of the US dollar has a positive impact on the revenues received by western Canadian producers. Movement in the Cdn$/US$ exchange rate also impacts the value of ARC's long-term debt given that approximately 79 per cent of ARC's total debt outstanding is denominated in US dollars.

Ongoing commodity price volatility may affect ARC's funds from operations and rates of return on its capital programs. As continued volatility is expected in 2014, ARC will take steps to mitigate these risks and protect its strong financial position.

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2014Annual Guidance and Financial Highlights

Table 4 is a summary of ARC’s 2014 guidance and a review of 2014 year-to-date actual results:

Table 4

	Original 2014 Guidance	Revised 2014 Guidance	2014 YTD	% Variance from Original Guidance
Production (2)
Crude oil (bbl/d)	35,000 - 37,000	35,000 - 37,000	36,391	—
Condensate (bbl/d)	2,300 - 2,500	3,400 - 3,700	3,679	47
Natural gas (mmcf/d)	415 - 425	405 - 415	383.5	(8	)
NGLs (bbl/d)	3,700 - 4,000	3,800 - 4,100	3,962	—
Total (boe/d)	110,000 - 114,000	110,000 - 114,000	107,944	(2	)
Expenses ($/boe)
Operating	9.20 - 9.60	9.20 - 9.60	9.04	(2	)
Transportation	1.70 - 1.80	2.00 - 2.20	1.97	9
G&A (1)	2.20 - 2.40	2.20 - 2.40	1.99	(10	)
Interest	1.10 - 1.20	1.10 - 1.20	1.19	—
Current income tax ($ millions) (3)	60 - 70	80 - 100	47.0	N/A
Capital expenditures before land purchases and net property acquisitions ($ millions)	915	975	478.1	N/A
Land purchases and net property acquisitions ($ millions)	—	—	26.8	N/A
Weighted average shares, diluted (millions)	317	317	316	N/A

(1) The 2014 guidance for G&A expenses per boe was based on a range of $1.45 - $1.55 prior to the recognition of any expense associated with ARC’s long-term incentive plans and $0.75 - $0.85 per boe associated with ARC’s long-term incentive plans. Actual per boe costs for each of these components for the six months endedJune 30, 2014 were $1.51 and $0.48 per boe, respectively.

(2) Revised 2014 production guidance does not take into account the impact of any dispositions that may occur during the remainder of the year. Actual dispositions that have closed prior to June 30, 2014 have been reflected in the revised 2014 production guidance above.

(3) Current income tax of $47 million for the six months endedJune 30, 2014 reflects a prorated estimate of the 2014 annual cash tax obligation based on commodity prices received to date and the outlook for commodity prices for the remainder of 2014.

ARC’s year-to-date 2014 production was 107,944 boe per day. This is below the annual guidance range as new wells were systematically brought on production during the first half of the year. ARC expects 2014 annual average production to be within the guidance range of 110,000 to 114,000 boe per day despite its disposition of properties producing approximately 2,400 boe per day early in the second quarter.

On a per boe basis, operating expenses were below the guidance range during the first half of 2014, as ARC continues to increase its production from properties with lower operating cost structures. Transportation expense has exceeded original guidance during the first six months of 2014 as ARC continues to incur additional trucking and pipeline charges as a result of taking ownership of its marketing arrangements. G&A expenses were below guidance during the first half of 2014 reflecting a reduction to the estimated payment obligation under ARC's long-term incentive plans at June 30, 2014.

The guidance information presented herein 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.

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2014SECOND 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)	2014	2013	% Change	2014	2013	% Change
Funds from operations (1)	295.8	201.2	47	588.1	403.6	46
Funds from operations per share (1)(2)	0.93	0.65	43	1.86	1.30	43
Net income and comprehensive income	147.4	93.3	58	176.8	140.2	26
Operating income (3)	116.9	53.9	117	233.9	101.6	130
Dividends per share (2)	0.30	0.30	—	0.60	0.60	—
Average daily production (boe/d) (4)	110,165	93,436	18	107,944	94,449	14

(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.

(3) 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.Also refer to the "Operating Income" section within this MD&A for the definition of operating income and a reconciliation of ARC’s net income to operating income.

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

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 to funds from operations and cash flow from operating activities:

Table 6

	Three Months Ended				Six Months Ended
	June 30				June 30
($ millions)	2014		2013		2014		2013
Net income	147.4		93.3		176.8		140.2
Adjusted for the following non-cash items:
DD&A	160.4		129.7		310.2		262.9
Accretion of ARO	3.7		3.1		7.6		6.3
Intangible E&E expenses	1.7		—		1.7		—
Deferred tax expense	23.6		28.1		15.0		46.4
Unrealized loss (gain) on risk management contracts	(14.8	)	(63.8	)	74.4		(60.4	)
Unrealized gain on risk management contracts related to current production periods (1)	—		3.3		—		3.3
Unrealized loss (gain) on foreign exchange	(25.7	)	25.2		3.3		40.3
Gain on disposal of petroleum and natural gas properties	—		(17.0	)	—		(34.4	)
Other	(0.5	)	(0.7	)	(0.9	)	(1.0	)
Funds from operations	295.8		201.2		588.1		403.6
Unrealized gain on risk management contracts related to current production periods (1)	—		(3.3	)	—		(3.3	)
Net change in other liabilities	(1.1	)	2.6		(14.6	)	(1.0	)
Change in non-cash working capital	40.3		14.6		20.8		(24.0	)
Cash flow from operating activities	335.0		215.1		594.3		375.3

(1) ARC enters into certain commodity price risk management contracts that pertain to production periods spanning the entire calendar year but that are settled at the end of the year on an annual average benchmark commodity price. The portion of gains or losses associated with these contracts that relate to production periods for the three and six months ended June 30 has been applied to either increase or reduce funds from operations and operating income in order to more appropriately reflect the funds from operations and operating income generated during the period after any effect of contracts used for economic hedging.

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Details of the change in funds from operations from the three and six months ended June 30, 2013 to the three and six months ended June 30, 2014 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 – 2013	201.2		0.65		403.6		1.30
Volume variance
Crude oil and liquids	56.5		0.17		105.6		0.34
Natural gas	19.9		0.06		25.5		0.08
Price variance
Crude oil and liquids	47.1		0.15		90.5		0.30
Natural gas	40.1		0.13		114.9		0.36
Realized gain or loss on risk management contracts	(23.7	)	(0.07	)	(48.5	)	(0.15	)
Unrealized gain or loss on risk management contracts related to current production periods (2)	(3.3	)	(0.01	)	(3.3	)	(0.01	)
Royalties	(20.8	)	(0.07	)	(52.6	)	(0.17	)
Expenses
Transportation	(3.0	)	(0.01	)	(9.0	)	(0.03	)
Operating	(3.8	)	(0.01	)	(14.4	)	(0.05	)
G&A	3.5		0.01		12.8		0.04
Interest	(0.9	)	—		(2.6	)	(0.01	)
Current tax	(16.7	)	(0.05	)	(34.3	)	(0.11	)
Realized gain or loss on foreign exchange	(0.3	)	—		(0.1	)	—
Diluted shares	—		(0.02	)	—		(0.03	)
Funds from operations – 2014	295.8		0.93		588.1		1.86

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

(2) ARC enters into certain commodity price risk management contracts that pertain to production periods spanning the entire calendar year but that are settled at the end of the year on an annual average benchmark commodity price.The portion of gains or losses associated with these contracts that relate to production periods for the three and six months ended June 30 has been applied to either increase or reduce funds from operations and operating income in order to more appropriately reflect the funds from operations and operating income generated during the period after any effect of contracts used for economic hedging.

Funds from operations increased by 47 per cent in the second quarter of 2014 to $295.8 million from $201.2 million generated in the second quarter of 2013. The increase reflects increased revenue associated with higher realized commodity prices as well as increased crude oil and liquids and natural gas production and modestly reduced G&A costs. Increased royalties, increased realized losses on risk management contracts, higher current taxes, and higher operating and transportation expenses served to offset the increase in funds from operations.

For the first six months of 2014, funds from operations increased by $184.5 million or 46 per cent as compared to the same period in 2013. Increased commodity prices alongside increased crude oil, natural gas and NGLs volumes and reduced G&A expenses contributed to the year-over-year increase in funds from operations, offset by increased realized losses on risk management contracts and increased royalties, current income taxes, transportation, and operating expenses.

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2014 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)	100.81		1.00		0.033
Natural gas price (Cdn$ AECO/mcf) (2)(3)	4.72		0.10		0.026
Cdn$/US$ exchange rate (2)(3)(4)	1.10		0.01		0.028
Interest rate on floating-rate debt (2)	2.7	%	1.0	%	0.004
Operational
Crude oil and liquids production volumes (bbl/d) (5)	44,032		1.0	%	0.035
Natural gas production volumes (mmcf/d) (5)	383.5		1.0	%	0.014
Operating expenses ($/boe) (5)	9.04		1.0	%	0.008
G&A expenses ($/boe) (5)	1.99		10.0	%	0.026

(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 second quarter of 2014. 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, 2014.

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

Net Income

Net income of $147.4 million ($0.47 per share) was earned in the second quarter of 2014, a $54.1 million increase compared to net income of $93.3 million ($0.30 per share) in the second quarter of 2013. While ARC recorded increased revenue net of royalties of $142.8 million, this increase was partially offset by increased losses on risk management contracts of $72.7 million reflecting the impact of stronger current commodity prices and higher expected future commodity prices. Higher production levels served to increase ARC's transportation, operating, and DD&A charges by $3 million, $3.8 million and $30.7 million, respectively, while increased foreign exchange gains of $50.6 million were experienced as a result of the revaluation of ARC's US dollar denominated debt outstanding from the period of March 31, 2014 to June 30, 2014. During the three months ended June 30, 2013, ARC recorded a gain on its disposal of non-core assets of $17 million, where in 2014 no such gains were recognized.

For the six months ended June 30, 2014, net income was $176.8 million ($0.56 per share) as compared to $140.2 million ($0.45 per share) in 2013 resulting in a year-over-year increase of $36.6 million. Revenue after royalties increased by $283.9 million for the six months ended June 30,2014 as compared to the same period in 2013, but was partially offset by increased losses on risk management contracts of $183.3 million. Consistent with the quarterly analysis above, ARC recognized increased transportation, operating, and DD&A expenses of $9 million, $14.4 million and $47.3 million, respectively, during the six months ended June 30, 2014 as compared to the six months ended June 30, 2013 as a result of increased production levels. Reduced G&A expenses of $12.3 million and reduced losses on foreign exchange of $36.9 million served to increase net income, offset by a $34.4 million gain on disposal that was recorded during the first six months of 2013 when no such gain was recorded during the same period of the current year.

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Operating Income

Operating income is a non-GAAP financial measure that does not have standardized meaning, and is therefore unlikely to be comparable to similar measures presented by other issuers. Operating income is defined by ARC as net income excluding the impact of after-tax unrealized gains and losses on risk management contracts, after-tax unrealized gains and losses on foreign exchange, after-tax gains on disposal of petroleum and natural gas properties, after-tax impairment on PP&E, after-tax unrealized gains and losses on short-term investments, and is further adjusted to include any after-tax portion of unrealized gains or losses on risk management contracts settled annually that relate to current period production. ARC believes that adjusting net income for these non-operating items presents a measure of “full cycle” financial performance that is more comparable between periods than net income. The most directly comparable GAAP measure to operating income is net income. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.

ARC's operating income was $116.9 million in the second quarter of 2014, up $63 million compared to operating income of $53.9 million in the second quarter of 2013. For the six months ended June 30, 2014, operating income was $233.9 million, up$132.3 million from $101.6 million from the same period in 2013.

Table 9

	Three Months Ended				Six Months Ended
	June 30				June 30
Operating Income ($ millions, except per share amounts)	2014		2013		2014		2013
Net income	147.4		93.3		176.8		140.2
Add (deduct) non-operating items:
Unrealized loss (gain) on risk management contracts	(14.8	)	(63.8	)	74.4		(60.4	)
Unrealized gain on risk management contracts related to current production periods (1)	—		3.3		—		3.3
Unrealized loss (gain) on foreign exchange	(25.7	)	25.2		3.3		40.3
Gain on disposal of petroleum and natural gas properties	—		(17.0	)	—		(34.4	)
Gain on short-term investment	(0.5	)	(0.5	)	(1.1	)	(0.7	)
Income tax associated with non-operating items	10.5		13.4		(19.5	)	13.3
Operating income	116.9		53.9		233.9		101.6
Operating income per share, diluted	0.37		0.17		0.74		0.33

(1) ARC enters into certain commodity price risk management contracts that pertain to production periods spanning the entire calendar year but that are settled at the end of the year on an annual average benchmark commodity price. The portion of gains or losses associated with these contracts that relate to production periods for the three and six months ended June 30 has been applied to either increase or reduce funds from operations and operating income in order to more appropriately reflect the funds from operations and operating income generated during the period after any effect of contracts used for economic hedging.

Production

Production volumes averaged 110,165 boe per day in the second quarter of 2014, an 18 per cent increase compared to an average of 93,436 boe per day for the same period in 2013. The increase in volumes is attributed to new production from wells brought on stream in late 2013 and through 2014, partially offset by the disposal of non-core assets early in the second quarter producing approximately 2,400 boe per day.

During the six months ended June 30, 2014, production volumes averaged 107,944 boe per day, a 14 per cent increase from production of 94,449 boe per day for the same period in the prior year, also attributed to good operational run-time and new production brought on from wells drilled in 2013 and 2014, offset slightly by the loss of production from the disposition of non-core assets.

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Table 10

	Three Months Ended				Six Months Ended
	June 30				June 30
Production	2014	2013	% Change		2014	2013	% Change
Light and medium crude oil (bbl/d)	34,361	30,815	12		35,439	31,259	13
Heavy oil (bbl/d)	956	820	17		952	808	18
Condensate (bbl/d)	4,462	2,150	108		3,679	2,091	76
Natural gas (mmcf/d)	397.2	340.8	17		383.5	344.7	11
NGLs (bbl/d)	4,179	2,859	46		3,962	2,845	39
Total production (boe/d)	110,165	93,436	18		107,944	94,449	14
% Natural gas production	60	61	(2	)	59	61	(3	)
% Crude oil and liquids production	40	39	3		41	39	5

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 2014, crude oil and liquids production increased 20 per cent from the second quarter of the prior year. Increased crude oil and liquids production is mainly the result of positive drilling results from new wells in Parkland and Tower in northeastern British Columbia and Ante Creek in northern Alberta. The increases were partially offset by approximately 500 barrels per day of production downtime associated with turnaround and pipeline integrity maintenance at Redwater.

For the six months ended June 30, 2014, ARC's total oil production increased by 4,324 barrels per day or 13 per cent as compared to the same period in 2013, also a result of new wells drilled throughout 2013.

Natural gas production was 397.2 mmcf per day in the second quarter of 2014, an increase of 17 per cent from the 340.8 mmcf per day produced in the second quarter of 2013. The increase is mainly attributed to new wells in Parkland, Sunrise and Attachie in northeastern British Columbia and is partially offset by the disposition of non-core assets early in the second quarter of 2014.

ARC produced 383.5 mmcf per day of natural gas during the six months ended June 30, 2014, an 11 per cent increase from the same period of the prior year, reflecting new wells drilled in northeastern British Columbia.

During the second quarter of 2014, ARC drilled 37 gross wells (37 net wells) on operated properties consisting of 18 gross (18 net) oil wells, 12 gross (12 net) natural gas wells, and seven gross (seven net) liquids-rich natural gas wells. Total wells drilled to June 30, 2014 were 97 gross wells (94 net wells) on operated properties consisting of 61 gross (58 net) oil wells, 20 gross (20 net) natural gas wells, and 16 gross (16 net) liquids-rich natural gas wells.

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Table 11 summarizes ARC’s production by core area for the second quarter of 2014 and 2013:

Table 11

	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

	Three Months Ended June 30, 2013
Production	Total	Crude Oil	Condensate	Natural Gas	NGLs
Core Area (1)	(boe/d)	(bbl/d)	(bbl/d)	(mmcf/d)	(bbl/d)
Northeast BC	40,338	543	1,118	227.8	712
Northern AB	17,393	6,505	622	54.8	1,131
Pembina	12,364	8,459	311	17.5	676
South Central AB	11,850	4,902	76	39.6	276
Southeast SK & MB	11,491	11,226	23	1.1	64
Total	93,436	31,635	2,150	340.8	2,859

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

(2) During the three months ended June 30, 2014, ARC disposed of certain non-core assets in this district. These assets had been producing approximately 2,400 boe per day prior to disposal.

Table 11a summarizes ARC’s production by core area for the six months ended June 30, 2014 and 2013:

Table 11a

	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

	Six Months Ended June 30, 2013
Production	Total	Crude Oil	Condensate	Natural Gas	NGLs
Core Area (1)	(boe/d)	(bbl/d)	(bbl/d)	(mmcf/d)	(bbl/d)
Northeast BC	40,950	667	1,063	230.9	738
Northern AB	17,076	6,323	609	54.2	1,114
Pembina	12,442	8,509	315	17.8	656
South Central AB	12,199	5,061	86	40.6	280
Southeast SK & MB	11,782	11,507	18	1.2	57
Total	94,449	32,067	2,091	344.7	2,845

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

(2) During the six months ended June 30, 2014, ARC disposed of certain non-core assets in this district. These assets had been producing approximately 2,400 boe per day prior to disposal.

ARC Resources Ltd. Page 10

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

Sales revenue from crude oil, natural gas, condensate, NGLs and other income was $567 million in the second quarter of 2014, an increase of $163.6 million from $403.4 million for the same period in the prior year, reflecting an increase in pricing which contributed additional revenue of $87.2 million and increased production volumes that contributed an additional $76.4 million. Crude oil, condensate and NGLs revenue accounted for $385.3 million or 68 per cent of second quarter sales revenue.

For the six months ended June 30, 2014, sales revenue from crude oil, natural gas, condensate, NGLs and other income was $1,118.4 million, an increase of $336.5 million from $781.9 million for the same period in the prior year, reflecting an increase in pricing which contributed additional revenue of $205.4 million and increased production volumes that contributed an additional $131.1 million.

A breakdown of sales revenue by product is outlined in Table 12:

Table 12

	Three Months Ended			Six Months Ended
	June 30			June 30
Sales revenue by product ($ millions)	2014	2013	% Change	2014	2013	% Change
Crude oil	328.2	256.8	28	650.6	499.6	30
Condensate	42.1	17.8	137	68.1	36.4	87
Natural gas	180.5	120.5	50	366.6	226.2	62
NGLs	15.0	7.6	97	31.4	17.2	83
Total sales revenue from crude oil, natural gas, condensate, and NGLs	565.8	402.7	41	1,116.7	779.4	43
Other income	1.2	0.7	71	1.7	2.5	(32	)
Total sales revenue	567.0	403.4	41	1,118.4	781.9	43

Commodity Prices Prior to Hedging

Table 13

	Three Months Ended			Six Months Ended
	June 30			June 30
	2014	2013	% Change	2014	2013	% Change
Average Benchmark Prices
AECO natural gas (Cdn$/mcf) (1)	4.68	3.59	30	4.72	3.34	41
WTI oil (US$/bbl)	102.98	94.23	9	100.81	94.28	7
Cdn$/US$ exchange rate	1.09	1.02	7	1.10	1.02	8
WTI oil (Cdn$/bbl)	112.30	96.11	17	110.58	96.17	15
Edmonton par (Cdn$/bbl)	105.62	92.70	14	102.64	90.46	13
ARC Realized Prices Prior to Hedging
Crude oil ($/bbl)	102.14	89.18	15	98.78	86.07	15
Condensate ($/bbl)	103.72	91.08	14	102.31	96.13	6
Natural gas ($/mcf)	4.99	3.89	28	5.28	3.63	45
NGLs ($/bbl)	39.51	29.25	35	43.76	33.32	31
Total commodity price prior to other income and hedging ($/boe)	56.44	47.36	19	57.16	45.59	25
Other income ($/boe)	0.12	0.09	33	0.08	0.15	(47	)
Total commodity price prior to hedging ($/boe)	56.56	47.45	19	57.24	45.74	25

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

In the second quarter of 2014, WTI (US$/bbl) increased nine per cent year-over-year whileARC’s realized crude oil price increased by 15 per cent during the same time period. Partially offsetting the increase in the WTI benchmark price, the differential between WTI and Edmonton posted prices widened to an average discount of US$6.13 per barrel in the second quarter of 2014 from US$3.64 per barrel in the same period in 2013. However, during the same period, the

ARC Resources Ltd. Page 11

average exchange rate for the Canadian dollar as compared to the US dollar weakened from $1.02 to $1.09. As a result of these factors, ARC's realized crude oil price has increased by 15 per cent from $89.18 per barrel during the second quarter of 2013 to $102.14 during the second quarter of 2014.

ARC's average realized oil price for the six months ended June 30, 2014 of $98.78 per barrel was 15 per cent higher than the same period in 2013. Although WTI has increased seven per cent during first six months of 2014 as compared to the first six months of 2013, the average differential between WTI and Edmonton posted prices widened during the same periods in 2013 and 2014 from an average of US$5.26 to US$7.24, respectively. This widened differential was more than offset by the impact of the weakened value of the Canadian dollar in comparison to the US dollar, from an average of $1.02 in the first six months of 2013 to $1.10 in the first six months of 2014, which increased the Canadian dollar price that ARC ultimately received for its oil.

Natural gas prices increased in the second quarter of 2014 as compared to 2013 as natural gas inventory levels were lower following strong demand from a colder North American winter than in the previous year. ARC's second quarter 2014 average realized price of $4.99 per mcf was higher than the average AECO monthly index price during the same period due in part to ARC's higher than average heat content inherent 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.

During the six months ended June 30, 2014, ARC's average realized natural gas price of $5.28 per mcf increased by 45 per cent over the same period of the prior year and reflects the 41 per cent increase in the average AECO monthly posting in 2014 as compared to 2013.

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 14

Revenue by Product Type	Three Months Ended				Six Months Ended
	June 30				June 30
($ millions)	2014		2013		2014		2013
	Revenue	% of Total	Revenue	% of Total	Revenue	% of Total	Revenue	% of Total
Crude oil and liquids	385.3	68	282.2	70	750.1	67	553.2	71
Natural gas	180.5	32	120.5	30	366.6	33	226.2	29
Total sales revenue from crude oil, natural gas, condensate, and NGLs	565.8	100	402.7	100	1,116.7	100	779.4	100
Other income	1.2	—	0.7	—	1.7	—	2.5	—
Total sales revenue	567.0	100	403.4	100	1,118.4	100	781.9	100

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 the amount of risk management contract volumes to a maximum of 55 per cent of total forecast production over the next two years with a maximum of 25 per cent of forecast natural gas production in risk management contracts beyond two years and up to five years. ARC’s risk management program guidelines allow for further risk management contracts on anticipated volumes associated with new production arising from specific capital projects and acquisitions or to further protect cash flows for a specific period with approval of the Board.

Gains and losses on risk management contracts are composed of both realized gains and losses representing the portion of risk management contracts that have settled in cash during the period and unrealized gains or losses that represent the change in the mark-to-market position of those contracts throughout the period. ARC does not employ hedge accounting for 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.

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Table 15 summarizes the total gain or loss on risk management contracts for the second quarter of 2014 compared to the same period in 2013:

Table 15

Risk Management Contracts ($ millions)	Crude Oil & Liquids		Natural  Gas		Foreign Currency		Power		Q2 2014 Total		Q2 2013 Total
Realized loss on contracts (1)	(10.4	)	(12.8	)	(1.4	)	(0.8	)	(25.4	)	(1.7	)
Unrealized gain on contracts related to second quarter production (2)	—		—		—		—		—		3.3
Impact of risk management contracts on funds from operations	(10.4	)	(12.8	)	(1.4	)	(0.8	)	(25.4	)	1.6
Unrealized gain (loss) on contracts related to future production periods (3)	(6.0	)	5.9		14.4		0.5		14.8		60.5
Gain (loss) on risk management contracts	(16.4	)	(6.9	)	13.0		(0.3	)	(10.6	)	62.1

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

(2) ARC enters into certain commodity price risk management contracts that pertain to production periods spanning the entire calendar year but that are settled at the end of the year on an annual average benchmark commodity price.

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

Table 15a summarizes the total gain or loss on risk management contracts for the six months ended June 30, 2014 compared to the same period in 2013:

Table 15a

Risk Management Contracts ($ millions)	Crude Oil & Liquids		Natural  Gas		Foreign Currency		Power		2014 YTD Total		2013 YTD Total
Realized gain (loss) on contracts (1)	(16.0	)	(23.6	)	(4.6	)	(1.4	)	(45.6	)	2.9
Unrealized gain on contracts related to year-to-date production (2)	—		—		—		—		—		3.3
Impact of risk management contracts on funds from operations	(16.0	)	(23.6	)	(4.6	)	(1.4	)	(45.6	)	6.2
Unrealized gain (loss) on contracts related to future production periods (3)	(9.8	)	(64.7	)	2.0		(1.9	)	(74.4	)	57.1
Gain (loss) on risk management contracts	(25.8	)	(88.3	)	(2.6	)	(3.3	)	(120.0	)	63.3

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

(2) ARC enters into certain commodity price risk management contracts that pertain to production periods spanning the entire calendar year but that are settled at the end of the year on an annual average benchmark commodity price.

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

During the second quarter of 2014, ARC recorded a loss of $10.6 million on its risk management contracts comprising realized losses of $25.4 million and unrealized gains of $14.8 million. The realized losses related to crude oil, natural gas, foreign exchange and electricity contracts.

For the six months ended June 30, 2014, ARC has recognized a loss on its risk management contracts of $120 million comprising a realized loss of $45.6 million and an unrealized loss of $74.4 million. The realized losses are related to crude oil, natural gas, foreign exchange and electricity contracts and represent cash payments made by ARC during the period. ARC's net unrealized losses related primarily to natural gas contracts with losses of $64.7 million. These losses were due to the increase in the value of the NYMEX forward curve over that time period.

The unrealized losses on crude oil contracts are largely attributed to contracts having ceiling prices averaging approximately US$100 per barrel throughout 2014. At June 30, 2014, these positions had been marked-to-market at an average forward price of approximately US$102.36 per barrel compared to a December 31, 2013 average forward price of US$92.76 per barrel.

ARC’s risk management contracts provide protection from natural gas prices falling lower than an average floor price of US$4.03 per mmbtu on approximately 240,000 mmbtu per day for the remainder of 2014. In addition, they provide upside participation to a price of US$4.17 per mmbtu on approximately 240,000 mmbtu per day for the remainder of 2014. ARC has also executed long-term natural gas hedge contracts on 165,000 mmbtu per day for 2015, 100,000 mmbtu per day for the period 2016 through 2017, and 50,000 mmbtu per day for 2018. ARC currently has hedged approximately 60 per cent of total forecast natural gas production for the remainder of 2014.

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ARC also has AECO basis swap contracts in place, fixing the AECO price received to approximately 90 per cent of the Henry Hub NYMEX price on a portion of its natural gas volume throughout 2014 and into 2019. As at June 30, 2014, the net fair value of these basis swap contracts was an asset of $19.5 million.

Given the significant contribution of ARC’s crude oil, condensate and NGLs production to total sales revenue and funds from operations, ARC management also recognizes the risk associated with a reduction in crude oil pricing. Accordingly, ARC has protected the selling price on a portion of crude oil production by establishing crude oil floor and ceiling prices for 2014 with approximately 45 per cent of total forecast crude oil and condensate production being hedged for the remainder of 2014 at floor prices of US$90 per barrel. These contracts allow ARC to participate in crude oil prices up to approximately US$100 per barrel on approximately 18,000 barrels per day for the remainder of 2014.

Table 16 summarizes ARC’s average crude oil and natural gas hedged volumes for 2014 through 2019 as at the date of this MD&A. For a complete listing and terms of ARC’s hedging contracts at June 30, 2014, 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, 2014. Updates to the following table are posted to ARC’s website at www.arcresources.com.

Table 16

Hedge Positions Summary (1)
As at July 30, 2014	Remainder of 2014		2015		2016 - 2017		2018		Jan - June 2019
Crude Oil (2)	US$/bbl	bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day	US$/bbl	bbl/day
Ceiling	100.00	18,000	100.83	2,975	—	—	—	—	—	—
Floor	90.00	18,000	90.00	2,975	—	—	—	—	—	—
Sold Floor	70.00	5,000	—	—	—	—	—	—	—	—
Natural Gas (3)	US$/mmbtu	mmbtu/day	US$/mmbtu	mmbtu/day	US$/mmbtu	mmbtu/day	US$/mmbtu	mmbtu/day	US$/mmbtu	mmbtu/day
Ceiling	4.17	240,000	4.65	165,000	4.95	100,000	5.00	50,000	—	—
Floor	4.03	240,000	4.00	165,000	4.00	100,000	4.00	50,000	—	—
Natural Gas - AECO Basis(4)	AECO/NYMEX	mmbtu/day	AECO/NYMEX	mmbtu/day	AECO/NYMEX	mmbtu/day	AECO/NYMEX	mmbtu/day	AECO/NYMEX	mmbtu/day
Swap (percentage of NYMEX)	89.8	190,000	90.5	130,000	90.5	130,000	88.9	44,959	90.8	20,000
Foreign Exchange	Cdn$/ US$	US$ Total	Cdn$/ US$	US$ Total	Cdn$/ US$	US$ Total	Cdn$/ US$	US$ Total	Cdn$/ US$	US$ Total
Ceiling	1.0740	264,000	1.0725	48,000	—	—	—	—	—	—
Floor	1.0436	264,000	1.0463	48,000	—	—	—	—	—	—

(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, 2014.

(2) The crude oil prices in this table are referenced to WTI. For 2014, all floor positions settle against the monthly average WTI price. Positions establishing the “ceiling” have been sold against the monthly average WTI price.

(3) The natural gas prices in this table are referenced to NYMEX at Henry Hub.

(4) 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) ARC has hedged a portion of production by tying ARC's price to a percentage of the NYMEX natural gas price.

“Floors” represent the lower price limits on hedged volumes and consist of put and swap prices. “Ceilings” provide an upper limit to the prices ARC may receive for hedged volumes and are the result of combined call and swap prices. ARC has also sold puts that limit the downside protection at an average of the disclosed “Sold Floor” price. These “Sold Floors” do not eliminate the floor, but merely limit the downside protection. The purpose of transacting these sold puts is to reduce ARC’s overall hedging transaction costs.

To accurately analyze ARC’s hedge position, contracts need to be modeled separately as using average prices and volumes may be misleading. The following provides examples of how Table 16 can be interpreted for approximate current year values (all in US dollars):

• If the market price is above $100.00 per barrel, ARC will receive $100.00 per barrel on 18,000 barrels per day.

• If the market price is between $90.00 and $100.00 per barrel, ARC will receive the market price on 18,000 barrels per day.

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• If the market price is between $70.00 and $90.00 per barrel, ARC will receive $90.00 per barrel on 18,000 barrels per day.

• If the market price is below $70.00 per barrel, ARC will receive $90.00 per barrel less the difference between $70.00 per barrel and the market price on 5,000 barrels per day. For example, if the market price is at $55.00 per barrel, ARC will receive $75.00 per barrel on 5,000 barrels per day and $90.00 per barrel on 13,000 barrels per day.

The net fair value of ARC’s risk management contracts at June 30, 2014 was a net liability of $22.1 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 operating netback prior to hedging was $37.41 per boe in the second quarter of 2014 ($38.02 for the six months ended June 30, 2014) as compared to $28.11 per boe in the same period of 2013 ($28.22 for the six months ended June 30, 2013).

ARC’s 2014 second quarter and year-to-date netbacks, including realized hedging gains and losses, were $34.88 per boe and $35.68 per boe, respectively, representing increases of 23 per cent and 25 per cent as compared to the same periods in 2013.

The components of operating netbacks for the second quarter of 2014 compared to the same period in 2013 are summarized in Table 17:

Table 17

Netbacks(1)	Crude Oil		Heavy Oil		Condensate		Natural Gas		NGLs		Q2 2014 Total		Q2 2013 Total
	($/bbl)		($/bbl)		($/bbl)		($/mcf)		($/bbl)		($/boe)		($/boe)
Average sales price	102.71		81.36		103.72		4.99		39.51		56.44		47.36
Other income	—		—		—		—		—		0.12		0.09
Total sales	102.71		81.36		103.72		4.99		39.51		56.56		47.45
Royalties	(16.47	)	(6.28	)	(13.21	)	(0.57	)	(6.48	)	(8.02	)	(7.01	)
Transportation	(2.83	)	(0.84	)	(0.94	)	(0.24	)	(6.11	)	(2.02	)	(2.04	)
Operating expenses (2)	(16.40	)	(15.73	)	(2.04	)	(0.97	)	(7.46	)	(9.11	)	(10.29	)
Netback prior to hedging	67.01		58.51		87.53		3.21		19.46		37.41		28.11
Hedging gain (loss) (3)	(3.87	)	—		—		(0.37	)	—		(2.53	)	0.16
Netback after hedging	63.14		58.51		87.53		2.84		19.46		34.88		28.27
% of total netback	57		1		10		29		3		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 oil and 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. In the first and second quarters of 2013, realized gains on foreign exchange contracts were not included in the netback calculation as they related solely to debt.

ARC Resources Ltd. Page 15

The components of operating netbacks for the six months ended June 30, 2014 compared to the same period in 2013 are summarized in Table 17a:

Table 17a

Netbacks(1)	Crude Oil		Heavy Oil		Condensate		Natural Gas		NGLs		2014 YTD Total		2013 YTD Total
	($/bbl)		($/bbl)		($/bbl)		($/mcf)		($/bbl)		($/boe)		($/boe)
Average sales price	99.34		77.72		102.31		5.28		43.76		57.16		45.59
Other income	—		—		—		—		—		0.08		0.15
Total sales	99.34		77.72		102.31		5.28		43.76		57.24		45.74
Royalties	(15.21	)	(5.31	)	(14.67	)	(0.67	)	(7.79	)	(8.21	)	(6.31	)
Transportation	(2.87	)	(0.84	)	(0.48	)	(0.24	)	(3.71	)	(1.97	)	(1.72	)
Operating expenses (2)	(15.07	)	(16.92	)	(4.79	)	(0.98	)	(8.09	)	(9.04	)	(9.49	)
Netback prior to hedging	66.19		54.65		82.37		3.39		24.17		38.02		28.22
Hedging gain (loss) (3)	(3.19	)	—		—		(0.36	)	—		(2.34	)	0.33
Netback after hedging	63.00		54.65		82.37		3.03		24.17		35.68		28.55
% of total netback	58		1		8		30		3		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 oil and 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. In the first and second quarters of 2013, realized gains on foreign exchange contracts were not included in the netback calculation as they related solely to debt.

Royalties

ARC pays royalties to the respective provincial governments and landowners of the four western Canadian provinces in which it operates. Approximately 85 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.

In British Columbia, the majority of ARC’s royalty expense stems from production of natural gas and associated liquids. While condensate and NGLs have a flat royalty rate of 20 per cent of sales revenue, the royalty rates for natural gas are based on the drill date of a well and a reference price. In Alberta, the majority of ARC’s royalties are related to oil production where royalty rates are based on reference prices, production levels and well depths. Similarly, most royalties remitted in Saskatchewan and Manitoba relate to oil production. Royalty calculations in these provinces are based on the classification of the oil product and well productivity.

Each province has various incentive programs in place to promote drilling by reducing the overall royalty expense for producers and offsetting gathering and processing costs. In most cases, the incentive period lasts for a finite period of time (usually 12 months upon commencement of production), after which point the royalty rate usually increases depending on the production rate of the well and prevailing market commodity prices.

In the first quarter of 2013, the British Columbia government announced a three per cent minimum royalty for all natural gas wells that qualify for the Deep Well Royalty Credit as well as the termination of the Summer Drilling Credit Program. These changes were effective April 1, 2013 and had a minimal impact on natural gas royalties for the balance of 2013. During the first quarter of 2014, the provincial government of British Columbia announced further changes to its royalty program, whereby the three per cent minimum royalty was replaced by a six per cent minimum and additional royalty credits will be made available for horizontal wells drilled to depths greater than 1,900 meters. These changes apply to wells spud on or after April 1, 2014. ARC expects that it should be able to leverage these newly announced credits in its future drilling in northern British Columbia.

Total royalties as a percentage of pre-hedged commodity product sales revenue decreased from 14.8 per cent ($7.01 per boe) in the second quarter of 2013 to 14.2 per cent ($8.02 per boe) in the second quarter of 2014, reflecting increased natural gas drilling eligible to receive provincial drilling credits as well as an increased proportion of NGLs production coming from British Columbia where the NGLs royalty rate is lower than in Alberta as compared to the prior year. Total royalties increased from $59.6 million in the second quarter of 2013 to $80.4 million in the second quarter of 2014 due to increased production. For the six months ended June 30, 2014, total royalties represented 14.3 per cent of pre-hedged commodity product sales ($8.21 per boe) as compared to 13.8 per cent ($6.31 per boe) for the same period in 2013.

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The increase in the royalty rate during the first six months of 2014 as compared to the same period of the prior year reflects the increase in commodity prices over the same periods.

Operating and Transportation Expenses

Operating expenses decreased to $9.11 per boe in the second quarter of 2014 compared to $10.29 per boe in the second quarter of 2013. On a full dollar basis, operating expenses have increased by $3.8 million or four per cent for the second quarter of 2014 as compared to the second quarter of 2013. In the second quarter of the prior year, operating costs were impacted by very high electricity costs due to average quarterly electricity rates of $123.36 per megawatt hour. In 2014, the second quarter average electricity rate was 66 per cent lower at $42.30 per megawatt hour. On a per boe basis, ARC's operating costs were lower for the second quarter of 2013 compared to the second quarter of 2014 as additional production volumes were brought on from new wells having a lower average cost structure. For the six months ended June 30, 2014, operating expenses decreased by $0.45 per boe, also as a result of increased production volumes from new wells with relatively lower 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 increased by $0.08 per boe for the three months ended June 30, 2014 (increased $0.07 per boe for the six months ended June 30, 2014) as a result of a realized loss of $0.8 million during the period (realized loss of $1.4 million for the six months ended June 30, 2014).

Transportation expense was $2.02 per boe during the second quarter of 2014 ($1.97 per boe for the six months ended June 30, 2014) as compared to $2.04 per boe in the second quarter of 2013 ($1.72 per boe for the six months ended June 30, 2013). ARC chooses to control its own transportation arrangements in order to move its product most efficiently to market. Generally this results in bearing additional transport costs, but in most cases is offset by higher revenue received for its products. As this transformation has taken place over the past two years, ARC's transportation expenses per barrel have been increasing. Additionally, with the current situation of many crude oil and liquids pipelines being at or near capacity, ARC has incurred additional transportation expenses throughout 2013 and into 2014 as it has been necessary to use additional methods of transport to get its production to market.

G&A Expenses and Long-Term Incentive Compensation

G&A, prior to long-term incentive compensation expense and net of capitalized G&A and overhead recoveries on operated properties, decreased by 11 per cent to $14.1 million in the second quarter of 2014 from $15.9 million in the second quarter of 2013. Second quarter 2014 G&A expenses decreased as compared to the second quarter of 2013 as a result of increased capital spending that led to additional capitalized G&A and increased recoveries from ARC's partners.

For the six months ended June 30, 2014, ARC's G&A, prior to long-term compensation expense and net of capitalized G&A and overhead recoveries on operated properties, was $29.5 million, a $1.2 million decrease from the same period in 2013, also reflecting increased capitalized G&A and recoveries from partners associated with capital spending.

Table 18 is a breakdown of G&A and long-term incentive compensation expenses:

Table 18

	Three Months Ended						Six Months Ended
	June 30						June 30
G&A and Long-term Incentive Compensation	2014		2013		% Change		2014		2013		% Change
($ millions, except per boe)
G&A expenses (1)	26.3		25.2		4		53.2		48.6		9
Capitalized G&A and overhead recoveries	(12.2	)	(9.3	)	31		(23.7	)	(17.9	)	32
G&A expenses before long-term incentive plans	14.1		15.9		(11	)	29.5		30.7		(4	)
G&A – long-term incentive plans (2)	4.9		6.4		(23	)	9.4		20.5		(54	)
Total G&A and long-term incentive compensation expenses	19.0		22.3		(15	)	38.9		51.2		(24	)
Total G&A and long-term incentive compensation expenses per boe	1.90		2.62		(27	)	1.99		3.00		(34	)

(1) Includes expenses recognized under the DSU Plan.

(2) Comprised of expenses recognized under the RSU, PSU and Stock Option Plans.

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Long-Term Incentive Plans – Restricted Share Unit & Performance Share Unit Plan, Share Option Plan, and Deferred Share Unit 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 $4.4 million during the second quarter of 2014 in accordance with the RSU and PSU Plan, as compared to $6.1 million during the second quarter of 2013. For the six months ended June 30, 2014, ARC recorded expenses related to the RSU and PSU Plan of $8.3 million, a decrease of $11.5 million or 58 per cent from the six months endedJune 30, 2013. The decreases for both the second quarter of 2014 as compared to the second quarter of 2013 and the six months ended June 30, 2014 as compared to the six months ended June 30, 2013 are related to a reduction in the performance multiplier used to determine the compensation cost associated with the PSU awards. During the first and second quarters of 2014, the total shareholder return of many of ARC's peers increased significantly, while ARC's total shareholder return increased by a more moderate amount. This reduction is partially offset by an increase in ARC's share price from a closing price of $29.57 at December 31, 2013 to $32.49 at June 30, 2014, which served to increase the value of accrued awards.

During the six months endedJune 30, 2014, ARC made cash payments of $17.3 million in respect of the RSU and PSU Plan ($15.7 million for the six months endedJune 30, 2013). Of these payments, $12.6 million were in respect of amounts recorded to G&A expenses ($11.6 million for the six months endedJune 30, 2013) and $4.7 million were in respect of amounts recorded to operating expenses and capitalized as PP&E and E&E assets ($4.1 million for the six months endedJune 30, 2013). These amounts were accrued in prior periods.

Table 19 shows the changes to the RSU and PSU Plan during 2014:

Table 19

RSU and PSU Plan (number of units, thousands)	RSUs	PSUs(1)	Total RSUs and PSUs
Balance, December 31, 2013	638	1,492	2,130
Granted	163	239	402
Distributed	(144)	(190)	(334)
Forfeited	(15)	(10)	(25)
Balance, June 30, 2014	642	1,531	2,173

(1) Based on underlying units before 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 significant volatility.

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Due to the variability in the future payments under the plan, ARC estimates that between $21.6 million and $126.5 million will be paid out in 2014 through 2017 based on the current share price, accrued dividends, and ARC’s market performance relative to its peers. Table 20 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, 2014:

Table 20

Value of RSU and PSU Plan as at
June 30, 2014	Performance multiplier
(units thousands and $ millions, except per share)	—	1.0	2.0
Estimated units to vest
RSUs	666	666	666
PSUs	—	1,614	3,228
Total units (1)	666	2,280	3,894
Share price (2)	32.49	32.49	32.49
Value of RSU and PSU Plan upon vesting (3)	21.6	74.1	126.5
2014	5.5	14.6	23.7
2015	9.0	26.8	44.5
2016	5.4	23.2	41.0
2017	1.7	9.5	17.3

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

(2) Values will fluctuate over the vesting period based on the volatility of the underlying share price. Assumes a future share price of $32.49, which is based on the closing share price at June 30, 2014.

(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 19, 2014, ARC granted 568,538 options to officers and certain employees at ARC.

At June 30, 2014, ARC had 2.6 million share options outstanding under this plan, representing less than one per cent of outstanding shares, with a weighted average exercise price of $24.04 per share. Compensation expense of $0.5 million has been recorded during the second quarter of 2014 ($1.1 million for the six months ended June 30, 2014) compared to $0.3 million for the second quarter of 2013 ($0.7 million for the six months ended June 30, 2013), and is included within G&A expenses.

Deferred Share Unit Plan

ARC has a DSU Plan for its non-employee directors under which each director receives a minimum of 55 per cent of their total annual remuneration in the form of 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, 2014, G&A expenses of $0.7 million and $1.3 million were recorded in relation to the DSU Plan ($0.6 million and $1.3 million in 2013).

Interest and Financing Charges

Interest and financing charges increased nine per cent to $11.2 million in the second quarter of 2014 from $10.3 million in the second quarter of 2013. For the six months ended June 30, 2014, interest and financing charges were $23.2 million as compared to $20.6 million in 2013, an increase of 13 per cent. The increase in interest charges reflects the higher average debt level held by ARC during the first and second quarters of 2014 as compared to the first and second quarters of 2013. Debt levels were lower in the first six months of 2013 following an equity offering completed during the latter half of 2012 which served to finance a portion of ARC's 2013 capital program.

At June 30, 2014, ARC had $903.7 million of long-term debt outstanding, including a current portion of $46 million that is due for repayment within the next 12 months. Of the total debt balance, $765.9 million is fixed at a weighted average

ARC Resources Ltd. Page 19

interest rate of 4.69 per cent, while the remaining $137.8 million incurs a floating interest rate based on market rates plus a current credit spread of 150 basis points. Approximately 79 per cent (US$669.1 million) of ARC’s debt outstanding is denominated in US dollars.

Foreign Exchange Gains and Losses

ARC recorded a foreign exchange gain of $25.4 million in the second quarter of 2014 compared to a loss of $25.2 million in the second quarter of 2013. The gain is primarily a result of the revaluation of ARC’s US dollar denominated debt outstanding from the period of March 31, 2014 to June 30, 2014 and reflects the change in value of the US dollar relative to the Canadian dollar from $1.1053 to $1.0676.

For the six months ended June 30, 2014, ARC recorded a foreign exchange loss of $3.6 million compared to a loss of $40.5 million for the same period in the prior year. During the six months ended June 30, 2013, the value of the US dollar relative to the Canadian dollar increased from $0.9949 at December 31, 2012 to $1.0512 at June 30, 2013. On average, during the six months ended June 30, 2014, the value of the US dollar relative to the Canadian dollar has remained relatively flat, from $1.0636 at December 31, 2013 to $1.0676 at June 30, 2014 resulting in less of an impact on the value of ARC's US dollar denominated debt.

Table 21 shows the various components of foreign exchange losses:

Table 21

	Three Months Ended						Six Months Ended
	June 30						June 30
Foreign Exchange Gains and Losses ($ millions)	2014		2013		% Change		2014		2013		% Change
Unrealized gain (loss) on US denominated debt	25.7		(25.2	)	(202	)	(3.3	)	(40.3	)	(92	)
Realized loss on US denominated transactions	(0.3	)	—		100		(0.3	)	(0.2	)	50
Total foreign exchange gain (loss)	25.4		(25.2	)	(201	)	(3.6	)	(40.5	)	(91	)

Taxes

ARC recorded a current income tax expense of $23.3 million in the second quarter of 2014 ($47 million expense for the six months ended June 30, 2014) compared to a current tax expense of $6.6 million during the second quarter of 2013 ($12.7 million expense for the six months ended June 30, 2013). The increases in current taxes for both the second quarter and the first six months of 2014 compared to the same periods in 2013 reflect higher expected taxable income related to increased commodity prices and production volumes.

During the second quarter of 2014, a deferred income tax expense of $23.6 million was recorded ($15 million expense for the six months ended June 30, 2014) compared to an expense of $28.1 million in the second quarter of 2013 ($46.4 million expense for the six months ended June 30, 2013). For both the three and six months ended June 30, 2014 as compared to the three and six months ended June 30, 2013, ARC’s decrease in deferred tax expense is related primarily to increased unrealized losses on risk management contracts and a net increase in the ARO liability, partially offset by temporary differences arising from the book basis of ARC's PP&E relative to its tax basis.

The income tax pools (detailed in Table 22) are deductible at various rates and annual deductions associated with the initial tax pools will decline over time.

Table 22

Income Tax Pool Type ($ millions)	June 30, 2014	Annual Deductibility
Canadian oil and gas property expense	685.6	10% declining balance
Canadian development expense	874.2	30% declining balance
Canadian exploration expense	—	100	%
Undepreciated capital cost	825.9	Primarily 25% declining balance
Other	14.8	Various rates, 7% declining balance to 20%
Total federal tax pools	2,400.5
Additional Alberta tax pools	19.9	Various rates, 25% declining balance to 100%

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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 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, 2014, ARC recorded DD&A expense of $160.4 million and $310.2 million as compared to $129.7 million and $262.9 million for three and six months ended June 30, 2013, reflecting increased production volumes as well as increased capital spending on infrastructure as ARC continues to develop its own infrastructure to facilitate production in high-growth areas.

A breakdown of DD&A expense is summarized in Table 23:

Table 23

	Three Months Ended				Six Months Ended
	June 30				June 30
DD&A Expense ($ millions, except per boe amounts)	2014	2013	% Change		2014	2013	% Change
Depletion of oil and gas assets	158.8	127.7	24		307.1	259.4	18
Depreciation of administrative assets	1.6	2.0	(20	)	3.1	3.5	(11	)
Total DD&A expense	160.4	129.7	24		310.2	262.9	18
DD&A rate per boe	16.00	15.25	5		15.88	15.38	3

Capital Expenditures, Acquisitions and Dispositions

Capital expenditures before acquisitions, dispositions or purchases of undeveloped land totaled $236.1 million in the second quarter of 2014 as compared to $170.7 million during the second quarter of 2013. This total includes development and production additions to PP&E of $227.8 million and additions to E&E assets of $8.3 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 three and six months ended June 30, 2014, ARC spent approximately $16.6 million and $22.4 million, respectively, to acquire lands primarily in the northeastern British Columbia Montney and northern Alberta Montney regions. In the first quarter of 2014, ARC acquired a 20 mmcf per day processing facility and associated gathering system in the Alberta Montney region at Ante Creek where ARC holds an extensive land base.

A breakdown of capital expenditures, acquisitions and dispositions is shown in Table 24 and 24a:

Table 24

	Three Months Ended June 30
	2014					2013
Capital Expenditures ($ millions)	E&E	PP&E		Total		E&E	PP&E		Total		% Change
Geological and geophysical	—	3.5		3.5		—	3.1		3.1		13
Drilling and completions	7.0	174.6		181.6		0.9	105.8		106.7		70
Plant and facilities	1.3	48.1		49.4		0.2	59.6		59.8		(17	)
Administrative assets	—	1.6		1.6		—	1.1		1.1		45
Total capital expenditures	8.3	227.8		236.1		1.1	169.6		170.7		38
Undeveloped land purchased at Crown land sales	—	16.6		16.6		—	0.7		0.7		100
Total capital expenditures including undeveloped land purchases	8.3	244.4		252.7		1.1	170.3		171.4		47
Acquisitions (1)	—	5.5		5.5		—	2.4		2.4		129
Dispositions (2)	—	(31.8	)	(31.8	)	—	(28.2	)	(28.2	)	13
Total capital expenditures, land purchases and net acquisitions and dispositions	8.3	218.1		226.4		1.1	144.5		145.6		55

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

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

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For the six months ended June 30, 2014, capital expenditures before property acquisitions, dispositions or purchases of undeveloped land totaled $478.1 million as compared to $401.9 million during the same period of 2013. This total includes development and production additions to PP&E of $449.1 million (2013 - $399.6 million) and additions to E&E assets of $29 million (2013 - $2.3 million).

Table 24a

	Six Months Ended June 30
	2014					2013
Capital Expenditures ($ millions)	E&E	PP&E		Total		E&E	PP&E		Total		% Change
Geological and geophysical	1.4	8.0		9.4		—	8.1		8.1		16
Drilling and completions	16.5	324.2		340.7		2.1	246.2		248.3		37
Plant and facilities	11.1	113.3		124.4		0.2	143.1		143.3		(13	)
Administrative assets	—	3.6		3.6		—	2.2		2.2		64
Total capital expenditures	29.0	449.1		478.1		2.3	399.6		401.9		19
Undeveloped land purchased at Crown land sales	—	22.4		22.4		—	1.9		1.9		100
Total capital expenditures including undeveloped land purchases	29.0	471.5		500.5		2.3	401.5		403.8		24
Acquisitions (1)	—	36.2		36.2		5.0	6.4		11.4		218
Dispositions (2)	—	(31.8	)	(31.8	)	—	(36.7	)	(36.7	)	(13	)
Total capital expenditures, land purchases and net acquisitions and dispositions	29.0	475.9		504.9		7.3	371.2		378.5		33

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

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

In Q2 2014, ARC divested of certain non-core shallow gas assets located in southwestern Saskatchewan for gross proceeds of approximately $33 million. The divested properties had associated natural gas production of approximately 2,400 boe per day and 56 bcf of proved plus probable natural gas reserves. Proceeds from the divestment were used to further strengthen ARC's balance sheet.

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, and debt. ARC financed 92 per cent of the $252.7 million second quarter capital program with funds from operations and contributions from DRIP and SDP (79 per cent in the second quarter of 2013).

Table 25

	Three Months Ended June 30
	2014					2013
Source of Funding of Capital Expenditures and Net Dispositions ($ millions)	Capital Expenditures including Land Purchases	Net Dispositions		Total Expenditures		Capital Expenditures including Land Purchases	Net Dispositions		Total Expenditures
Expenditures	252.7	(26.3	)	226.4		171.4	(25.8	)	145.6
Funds from operations, net (%) (1)	78	—		87		60	—		71
Contributions from DRIP and SDP (%)	14	—		16		19	—		22
Debt (%)	8	100		(3	)	21	100		7
Total (%)	100	100		100		100	100		100

(1) 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.

ARC Resources Ltd. Page 22

Table 25a

	Six Months Ended June 30
	2014			2013
Source of Funding of Capital Expenditures and Net Acquisitions and Dispositions ($ millions)	Capital Expenditures including Land Purchases	Net Acquisitions	Total Expenditures	Capital Expenditures including Land Purchases	Net Dispositions		Total Expenditures
Expenditures	500.5	4.4	504.9	403.8	(25.3	)	378.5
Funds from operations, net (%) (1)	78	—	78	52	—		55
Contributions from DRIP and SDP (%)	14	—	14	16	—		17
Debt (%)	8	100	8	32	100		28
Total (%)	100	100	100	100	100		100

(1) 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, 2014, ARC has recorded an ARO liability of $527.7 million ($475.4 million at December 31, 2013) 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 2.8 per cent (3.2 per cent at December 31, 2013).

Accretion charges of $3.7 million and $7.6 million for the three and six months ended June 30, 2014 ($3.1 million and $6.3 million for 2013), 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, 2014 was $3.1 million and $6.3 million ($3.2 million and $6.9 million for 2013), 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 $66 million in total over the next 42 years. The balance of this fund totaled $32.8 million at June 30, 2014, compared to $32.6 million at December 31, 2013. Under the terms of ARC’s investment policy, cash in the reclamation fund can only be invested in Canadian or US Government securities, investment-grade corporate bonds, or investment-grade short-term money market securities.

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

ARC Resources Ltd. Page 23

Capitalization, Financial Resources and Liquidity

A breakdown of ARC’s capital structure as at June 30, 2014 and December 31, 2013 is outlined in Table 26:

Table 26

Capital Structure and Liquidity ($ millions, except per cent and ratio amounts)	June 30, 2014	December 31, 2013
Long-term debt (1)	903.7	901.3
Working capital deficit (2)	158.2	110.2
Net debt obligations (3)	1,061.9	1,011.5
Market value of common shares (4)	10,283.1	9,287.9
Total capitalization (3)	11,345.0	10,299.4
Net debt as a percentage of total capitalization	9.4	9.8
Net debt to annual funds from operations (3)	0.9	1.2

(1) Includes a current portion of long-term debt of $46 million at June 30, 2014 and $42.1 million at December 31, 2013.

(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, 2014 multiplied by the closing share price of $32.49 at June 30, 2014 (closing share price of $29.57 at December 31, 2013).

At June 30, 2014, ARC had total available credit facilities of $2 billion with debt of $903.7 million currently drawn. After its $158.2 million working capital deficit, ARC has available credit of $891.1 million. ARC’s long-term debt balance includes a current portion of $46 million at June 30, 2014 ($42.1 million at December 31, 2013), reflecting principal payments that are due to be paid within the next 12 months. ARC intends to finance these obligations by drawing on its syndicated credit facility at the time the payments are due.

ARC’s debt agreements contain a number of covenants, all of which were met as at June 30, 2014. These agreements are available at www.sedar.com. ARC calculates its covenants four times annually. The major financial covenants are described below:

Table 27

Covenant description	Estimated Position at June 30, 2014 (1)
Long-term debt and letters of credit not to exceed three times annualized net income before non-cash items, income taxes and interest expense	0.8
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	0.8
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 4.69 per cent.

ARC Resources Ltd. Page 24

Shareholders’ Equity

At June 30, 2014, there were 316.5 million shares outstanding, an increase of 2.4 million shares over the balance of shares issued at December 31, 2013. The increase was attributable to shares issued to participants in the DRIP and SDP.

At June 30, 2014, ARC had 2.6 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 $24.04 per share. These options vest in equal parts on the fourth and fifth anniversaries of the grant date. The first tranche will vest on March 24, 2015.

Dividends

In the second quarter of 2014, ARC declared dividends totaling $94.8 million ($0.30 per share) compared to $93.4 million ($0.30 per share) during the second quarter of 2013.

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 for a minimum period of six months 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 well positioned to sustain current dividend levels despite the volatile commodity price environment. ARC’s second quarter dividend was 32 per cent of funds from operations (32 per cent of funds from operations for the six months ended June 30, 2014), a level which ARC believes is reasonable given the current commodity price environment. ARC’s business model is dynamic and dividend levels and capital spending are continually assessed in light of current and forecast market conditions.

Subsequent to June 30, 2014, ARC's Board of Directors approved a modification to the DRIP and SDP whereby the discount applicable to common shares acquired or issued under both plans will be reduced to three per cent from five per cent. The change will take effect for the September 15, 2014 dividend payment for shareholders on record as of August 31, 2014.

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, 2014, ARC confirmed that a dividend of $0.10 per common share designated as an eligible dividend will be paid on August 15, 2014 to shareholders of record on July 31, 2014. The ex-dividend date is July 29, 2014.

Please refer to ARC’s website at www.arcresources.com for details of the estimated monthly dividend amounts and dividend dates for 2014.

Environmental Initiatives Impacting ARC

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

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Contractual Obligations and Commitments

Table 28 discloses ARC's contractual obligations and commitments at June 30, 2014 and the associated minimum future payments:

Table 28

	Payments Due by Period
Contractual Obligations and Commitments ($ millions)	1 Year	2-3 Years	4-5 Years	Beyond 5 Years	Total
Debt repayments (1)	46.0	74.2	273.7	509.8	903.7
Interest payments (2)	35.7	63.1	53.0	63.0	214.8
Reclamation fund contributions (3)	3.6	6.6	6.1	49.9	66.2
Purchase commitments	46.1	18.2	13.9	7.9	86.1
Transportation commitments	45.6	62.7	56.2	109.8	274.3
Operating leases	15.5	28.9	26.7	64.1	135.2
Risk management contract premiums (4)	—	6.1	1.2	—	7.3
Total contractual obligations and commitments	192.5	259.8	430.8	804.5	1,687.6

(1) Long-term and current portion of long-term debt.

(2) Fixed interest payments on senior notes.

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

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

In addition to the above risk management contract premiums, ARC has commitments related to its risk management program (see Note 8 "Financial Instruments and Market Risk Management" of the financial statements). As the premiums are related to the underlying risk management contract, they have been recorded at fair market value at June 30, 2014 on the balance sheet as part of risk management contracts.

ARC enters into commitments for capital expenditures in advance of the expenditures being made. At any given point in time, it is estimated that ARC has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the capital expenditures in a future period. ARC’s 2014 capital budget of $975 million has been approved by the Board.

ARC is involved in litigation and claims arising in the normal course of operations. Management is of the opinion that pending litigation will not have a material impact on ARC’s financial position or results of operations and therefore Table 28 does not include any commitments for outstanding litigation and claims.

Subsequent to June 30, 2014, ARC entered into transportation commitments that have an aggregate obligation of $105 million effective for the years 2015 through 2026. These commitments are in addition to those included in the table above.

Off-Balance Sheet Arrangements

ARC has certain lease agreements, all of which are reflected in the Contractual Obligations and Commitments table (Table 28), 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, 2014.

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;

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• 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 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.

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, 2013.

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;

• operational matters;

• reserves and resources estimates;

• depletion of reserves and maintenance of dividend;

• counterparty risk;

• variations in interest rates and foreign exchange rates;

• changes in income tax legislation;

• changes in government royalty legislation;

• acquisitions;

• environmental concerns and related impact on operations; and

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

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

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PROJECT RISKS

ARC manages a variety of small and large projects and plans to spend $975 million on capital projects throughout 2014. 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, 2014 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, 2014.

FINANCIAL REPORTING UPDATE

Changes in Accounting Policies

As of January 1, 2014, the Company adopted several new IFRS interpretations and amendments in accordance with the transitional provisions of each standard. A brief description of each new accounting policy and its impact on the Company's financial statements follows below:

• IAS 36 "Impairment of Assets" has been amended to reduce the circumstances in which the recoverable amount of cash generating units "CGUs" is required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. The retrospective adoption of these amendments will only impact ARC's disclosures in the notes to the financial statements in periods when an impairment loss or impairment reversal is recognized.

• IAS 39 "Financial Instruments: Recognition and Measurement" has been amended to clarify that there would be no requirement to discontinue hedge accounting if a hedging derivative was novated, provided certain criteria are met. The retrospective adoption of the amendments does not have any impact on ARC's financial statements.

• IFRIC 21 "Levies" was developed by the IFRS Interpretations Committee ("IFRIC") and is applicable to all levies imposed by governments under legislation, other than outflows that are within the scope of other standards (e.g., IAS 12 "Income Taxes") and fines or other penalties for breaches of legislation. The interpretation clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant

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legislation, occurs. It also clarifies that a levy liability is accrued progressively only if the activity that triggers payment occurs over a period of time, in accordance with the relevant legislation. Lastly, the interpretation clarifies that a liability should not be recognized before the specified minimum threshold to trigger that levy is reached. The retrospective adoption of this interpretation does not have any impact on ARC's financial statements.

Future Accounting Policy Changes

In February 2014, the IASB tentatively decided to require an entity to apply IFRS 9 "Financial Instruments" for annual periods beginning on or after January 1, 2018. IFRS 9 is still available for early adoption. The full impact of the standard on ARC's financial statements will not be known until changes are finalized.

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. The standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2017, with earlier adoption permitted. IFRS 15 will be applied by ARC on January 1, 2017 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”), operating income, 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 option expense, and is further adjusted to include any portion of unrealized gains and losses on risk management contracts settled annually that relate to current period production. ARC considers funds from operations to be a key measure of operating performance as it demonstrates ARC’s ability to generate the necessary funds to fund future growth through capital investment and to repay debt. Management believes that such a measure provides a better assessment of ARC’s operations on a continuing basis by eliminating certain non-cash charges and charges that are nonrecurring, while respecting that certain risk management contracts that are settled on an annual basis are intended to protect prices on product sales occurring throughout the year. From a business perspective, the most directly comparable measure of funds from operations calculated in accordance with GAAP is net income.

Net Debt

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

Total Capitalization

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

Forward-looking Information and Statements

This MD&A contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect," "anticipate," "continue," "estimate," "objective," "ongoing," "may," "will," "project," "should," "believe," "plans," "intends," "strategy," and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this MD&A contains forward-looking information

ARC Resources Ltd. Page 29

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 2014 under the heading “2014Annual Guidance and Financial Highlights,” ARC's views on oil differentials under the heading "Commodity Prices Prior to Hedging," ARC’s intentions in the future regarding hedging under the heading “Risk Management,” ARC’s view as to the increased transportation costs under the heading “Operating and Transportation Expenses,” the estimated future payments under the RSU and PSU Plan under the heading “Long-Term Incentive Plans – Restricted Share Unit & Performance Share Unit Plan, Share Option Plan, and Deferred Share Unit Plan,” the information relating to the 2014 capital program under the heading “Capital Expenditures, Acquisitions and Dispositions,” 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.

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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 ration 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

NGLs        natural gas liquids

NYMEX        New York Mercantile Exchange

PP&E        property, plant and equipment

PSU        Performance Share Unit

RSU        Restricted Share Unit

SDP        Stock Dividend Program

WTI        West Texas Intermediate

ARC Resources Ltd. Page 31

QUARTERLY HISTORICAL REVIEW

($ millions, except per share amounts)	2014			2013							2012
FINANCIAL	Q2		Q1	Q4	Q3		Q2		Q1		Q4		Q3
Sales of crude oil, natural gas, condensate, NGLs and other income	567.0		551.4	425.0	417.4		403.4		378.5		375.4		329.9
Per share, basic (1)	1.79		1.75	1.36	1.34		1.30		1.22		1.22		1.10
Per share, diluted (1)	1.79		1.75	1.35	1.34		1.30		1.22		1.22		1.10
Funds from operations (2)	295.8		292.3	237.8	220.4		201.2		202.4		208.4		164.9
Per share, basic (1)	0.94		0.93	0.76	0.71		0.65		0.65		0.68		0.55
Per share, diluted (1)	0.93		0.93	0.76	0.71		0.65		0.65		0.68		0.55
Net income (loss)	147.4		29.4	13.6	86.9		93.3		46.9		84.5		(24.3	)
Per share, basic (1)	0.47		0.09	0.04	0.28		0.30		0.15		0.27		(0.08	)
Per share, diluted (1)	0.47		0.09	0.04	0.28		0.30		0.15		0.27		(0.08	)
Operating income (3)	116.9		117.0	49.1	73.3		53.9		47.6		59.1		26.6
Per share, basic (1)	0.37		0.37	0.16	0.23		0.17		0.15		0.19		0.09
Per share, diluted (1)	0.37		0.37	0.16	0.23		0.17		0.15		0.19		0.09
Dividends declared	94.8		94.5	94.0	93.7		93.4		92.9		92.5		90.6
Per share (1)	0.30		0.30	0.30	0.30		0.30		0.30		0.30		0.30
Total assets	5,988.7		5,949.5	5,736.0	5,599.2		5,548.1		5,612.7		5,627.1		5,578.8
Total liabilities	2,531.1		2,580.7	2,339.9	2,156.6		2,132.6		2,229.9		2,230.4		2,207.0
Net debt outstanding (4)	1,061.9		1,096.0	1,011.5	936.5		883.7		855.1		745.6		691.0
Weighted average shares outstanding	315.9		314.7	313.5	312.2		310.9		309.6		308.2		299.7
Weighted average shares outstanding, diluted	316.6		315.2	313.9	312.5		311.2		309.8		308.4		299.9
Shares outstanding, end of period	316.5		315.3	314.1	312.8		311.5		310.2		308.9		307.5
CAPITAL EXPENDITURES
Geological and geophysical	3.5		5.9	6.6	4.5		3.1		5.0		4.2		5.1
Drilling and completions	181.6		159.1	140.9	179.2		106.7		141.6		129.1		98.2
Plant and facilities	49.4		75.0	58.8	65.6		59.8		83.5		48.4		28.1
Administrative assets	1.6		2.0	1.4	1.0		1.1		1.1		2.8		0.7
Total capital expenditures	236.1		242.0	207.7	250.3		170.7		231.2		184.5		132.1
Undeveloped land purchased at Crown land sales	16.6		5.8	3.5	8.9		0.7		1.2		5.7		1.0
Total capital expenditures including undeveloped land purchases	252.7		247.8	211.2	259.2		171.4		232.4		190.2		133.1
Acquisitions	5.5		30.7	12.4	12.6		2.4		9.0		2.1		10.0
Dispositions	(31.8	)	—	0.5	(53.6	)	(28.2	)	(8.5	)	(0.3	)	(2.5	)
Total capital expenditures, land purchases and net acquisitions and dispositions	226.4		278.5	224.1	218.2		145.6		232.9		192.0		140.6
OPERATING
Production
Crude oil (bbl/d)	35,317		37,478	35,542	31,438		31,635		32,505		32,938		30,732
Condensate (bbl/d)	4,462		2,887	2,580	2,235		2,150		2,032		1,767		2,325
Natural gas (mmcf/d)	397.2		369.6	359.4	348.9		340.8		348.6		348.2		323.2
NGLs (bbl/d)	4,179		3,743	2,868	2,687		2,859		2,831		2,978		2,587
Total (boe/d)	110,165		105,699	100,883	94,515		93,436		95,472		95,725		89,511
Average realized prices, prior to hedging
Crude oil ($/bbl)	102.14		95.58	82.85	101.43		89.18		83.00		80.50		81.43
Condensate ($/bbl)	103.72		100.11	88.72	96.70		91.08		101.53		86.70		87.65
Natural gas ($/mcf)	4.99		5.60	3.61	2.94		3.89		3.37		3.32		2.45
NGLs ($/bbl)	39.51		48.54	41.47	36.80		29.25		37.48		36.13		31.05
Oil equivalent ($/boe)	56.44		57.91	45.51	47.94		47.36		43.84		42.49		39.99
TRADING STATISTICS
($, based on intra-day trading)
High	33.68		30.66	29.95	28.65		28.90		27.64		26.00		26.25
Low	30.30		27.52	25.68	24.71		25.73		23.12		22.32		21.50
Close	32.49		30.45	29.57	26.27		27.53		26.84		24.44		23.90
Average daily volume (thousands)	1,037		1,248	1,030	1,004		1,074		1,151		1,146		1,282

(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 "Operating Income" and “Non-GAAP Measures” contained within this MD&A.

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

ARC Resources Ltd. Page 32

ARC RESOURCES LTD.
CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)
(Cdn$ millions)	June 30, 2014		December 31, 2013
ASSETS
Current assets
Cash and cash equivalents	6.4		—
Short-term investment	4.7		3.6
Accounts receivable	216.4		176.5
Prepaid expenses	14.0		15.6
Risk management contracts (Note 8)	0.5		4.4
	242.0		200.1
Reclamation fund	32.8		32.6
Risk management contracts (Note 8)	27.6		61.2
Intangible exploration and evaluation assets (Note 4)	292.7		265.4
Property, plant and equipment (Note 5)	5,145.4		4,928.5
Goodwill	248.2		248.2
Total assets	5,988.7		5,736.0
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities	368.0		274.5
Current portion of long-term debt (Note 6)	46.0		42.1
Current portion of asset retirement obligations (Note 7)	25.1		25.1
Dividends payable	31.7		31.4
Risk management contracts (Note 8)	45.6		12.9
	516.4		386.0
Risk management contracts (Note 8)	4.6		0.6
Long-term debt (Note 6)	857.7		859.2
Long-term incentive compensation liability (Note 10)	17.9		26.1
Other deferred liabilities	16.6		17.5
Asset retirement obligations (Note 7)	502.6		450.3
Deferred taxes	615.3		600.2
Total liabilities	2,531.1		2,339.9
Commitments and contingencies (Note 11)
SHAREHOLDERS’ EQUITY
Shareholders’ capital	3,871.7		3,800.8
Contributed surplus	6.9		3.8
Deficit	(421.0	)	(408.5	)
Total shareholders’ equity	3,457.6		3,396.1
Total liabilities and shareholders’ equity	5,988.7		5,736.0

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 33

ARC RESOURCES LTD.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (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)	2014		2013		2014		2013
REVENUE
Sales of crude oil, natural gas, condensate, natural gas liquids and other income	567.0		403.4		1,118.4		781.9
Royalties	(80.4	)	(59.6	)	(160.4	)	(107.8	)
	486.6		343.8		958.0		674.1
Gain (loss) on risk management contracts (Note 8)	(10.6	)	62.1		(120.0	)	63.3
	476.0		405.9		838.0		737.4
EXPENSES
Transportation	20.3		17.3		38.4		29.4
Operating	91.3		87.5		176.7		162.3
Intangible exploration and evaluation expenses (Note 4)	1.7		—		1.7		—
General and administrative	19.0		22.3		38.9		51.2
Interest and financing charges	11.2		10.3		23.2		20.6
Accretion of asset retirement obligations (Note 7)	3.7		3.1		7.6		6.3
Depletion, depreciation and amortization (Note 5)	160.4		129.7		310.2		262.9
Loss (gain) on foreign exchange	(25.4	)	25.2		3.6		40.5
Gain on short-term investment (Note 12)	(0.5	)	(0.5	)	(1.1	)	(0.7	)
Gain on disposal of petroleum and natural gas properties	—		(17.0	)	—		(34.4	)
	281.7		277.9		599.2		538.1
Provision for income taxes
Current	23.3		6.6		47.0		12.7
Deferred	23.6		28.1		15.0		46.4
	46.9		34.7		62.0		59.1
Net income and comprehensive income	147.4		93.3		176.8		140.2
Net income per share (Note 9)
Basic	0.47		0.30		0.56		0.45
Diluted	0.47		0.30		0.56		0.45

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 34

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		Total Shareholders’ Equity
December 31, 2012	3,670.2		1.7	(275.2	)	3,396.7
Shares issued for cash	0.5		—	—		0.5
Shares issued pursuant to the dividend reinvestment program	61.4		—	—		61.4
Shares issued pursuant to the stock dividend program	2.3		—	—		2.3
Share option expense (Note 10)	—		0.7	—		0.7
Comprehensive income	—		—	140.2		140.2
Dividends declared	—		—	(186.3	)	(186.3	)
June 30, 2013	3,734.4		2.4	(321.3	)	3,415.5
December 31, 2013	3,800.8		3.8	(408.5	)	3,396.1
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
Share option expense (Note 10)	—		1.2	—		1.2
Comprehensive income	—		—	176.8		176.8
Dividends declared	—		—	(189.3	)	(189.3	)
June 30, 2014	3,871.7		6.9	(421.0	)	3,457.6

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 35

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)	2014		2013		2014		2013
CASH FLOW FROM OPERATING ACTIVITIES
Net income and comprehensive income	147.4		93.3		176.8		140.2
Add items not involving cash:
Unrealized loss (gain) on risk management contracts	(14.8	)	(63.8	)	74.4		(60.4	)
Accretion of asset retirement obligations (Note 7)	3.7		3.1		7.6		6.3
Depletion, depreciation and amortization (Note 5)	160.4		129.7		310.2		262.9
Intangible exploration and evaluation expenses (Note 4)	1.7		—		1.7		—
Unrealized loss (gain) on foreign exchange	(25.7	)	25.2		3.3		40.3
Gain on disposal of petroleum and natural gas properties	—		(17.0	)	—		(34.4	)
Deferred tax expense	23.6		28.1		15.0		46.4
Other (Note 12)	(0.5	)	(0.7	)	(0.9	)	(1.0	)
Net change in other liabilities (Note 12)	(1.1	)	2.6		(14.6	)	(1.0	)
Change in non-cash working capital (Note 12)	40.3		14.6		20.8		(24.0	)
	335.0		215.1		594.3		375.3
CASH FLOW FROM FINANCING ACTIVITIES
Issuance (repayment) of long-term debt under revolving credit facilities, net	(26.9	)	—		31.9		—
Repayment of senior notes	(33.0	)	(30.9	)	(33.0	)	(30.9	)
Issue of common shares	—		0.2		—		0.5
Cash dividends paid	(59.1	)	(61.0	)	(117.4	)	(122.3	)
	(119.0	)	(91.7	)	(118.5	)	(152.7	)
CASH FLOW FROM INVESTING ACTIVITIES
Acquisition of petroleum and natural gas properties (Note 5)	(5.5	)	(2.4	)	(36.2	)	(11.4	)
Disposal of petroleum and natural gas properties	31.8		28.2		31.8		36.7
Property, plant and equipment development expenditures (Note 5)	(244.4	)	(170.3	)	(471.5	)	(401.5	)
Intangible exploration and evaluation asset expenditures (Note 4)	(8.3	)	(1.1	)	(29.0	)	(2.3	)
Net reclamation fund contributions	(1.0	)	(1.2	)	(0.2	)	(0.7	)
Change in non-cash working capital (Note 12)	8.2		(53.1	)	35.7		(27.5	)
	(219.2	)	(199.9	)	(469.4	)	(406.7	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(3.2	)	(76.5	)	6.4		(184.1	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	9.6		87.0		—		194.6
CASH AND CASH EQUIVALENTS, END OF PERIOD	6.4		10.5		6.4		10.5
The following are included in cash flow from operating activities:
Income taxes paid in cash	7.4		9.2		20.6		42.7
Interest paid in cash	12.4		10.7		23.9		21.3

See accompanying notes to the condensed interim consolidated financial statements.

ARC Resources Ltd. Page 36

NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

June 30, 2014 and 2013

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, 2013. 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 of ARC’s audited consolidated financial statements for the year ended December 31, 2013. All accounting policies and methods of computation followed in the preparation of these financial statements are consistent with those of the previous financial year, except as noted in Note 3 "Changes in Accounting Policies" in these financial statements. There have been no changes to the use of estimates or judgments since December 31, 2013.

The financial statements include the accounts of ARC and its wholly owned subsidiaries, ARC Resources General Partnership and 1504793 Alberta Ltd. All inter-entity transactions have been eliminated.

These financial statements were authorized for issue by the Board of Directors on July 30, 2014.

3. CHANGES IN ACCOUNTING POLICIES

As of January 1, 2014, the Company adopted several new IFRS interpretations and amendments in accordance with the transitional provisions of each standard. A brief description of each new accounting policy and its impact on the Company's financial statements follows below:

• IAS 36 "Impairment of Assets" has been amended to reduce the circumstances in which the recoverable amount of cash generating units "CGUs" is required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. The retrospective adoption of these amendments will only impact ARC's disclosures in the notes to the financial statements in periods when an impairment loss or impairment reversal is recognized.

• IAS 39 "Financial Instruments: Recognition and Measurement" has been amended to clarify that there would be no requirement to discontinue hedge accounting if a hedging derivative was novated, provided certain criteria are met. The retrospective adoption of the amendments does not have any impact on ARC's financial statements.

• IFRIC 21 "Levies" was developed by the IFRS Interpretations Committee ("IFRIC") and is applicable to all levies imposed by governments under legislation, other than outflows that are within the scope of other standards (e.g., IAS 12 "Income Taxes") and fines or other penalties for breaches of legislation. The interpretation clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. It also clarifies that a levy liability is accrued progressively only if the activity that triggers payment occurs over a period of time, in accordance with the relevant legislation. Lastly, the interpretation clarifies that a liability should not be recognized before the specified minimum threshold to trigger that levy is reached. The retrospective adoption of this interpretation does not have any impact on ARC's financial statements.

ARC Resources Ltd. Page 37

Future Accounting Policy Changes

In February 2014, the IASB tentatively decided to require an entity to apply IFRS 9 "Financial Instruments" for annual periods beginning on or after January 1, 2018. IFRS 9 is still available for early adoption. The full impact of the standard on ARC's financial statements will not be known until changes are finalized.

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. The standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2017, with earlier adoption permitted. IFRS 15 will be applied by ARC on January 1, 2017 and the Company is currently evaluating the impact of the standard on ARC's financial statements.

4. INTANGIBLE EXPLORATION AND EVALUATION ASSETS

Carrying amount
Balance, December 31, 2013	265.4
Additions	29.0
Intangible exploration and evaluation expenses	(1.7	)
Balance, June 30, 2014	292.7

5. PROPERTY, PLANT AND EQUIPMENT

Cost	Development and Production Assets		Administrative Assets		Total
Balance, December 31, 2013	6,858.5		54.9		6,913.4
Additions	468.0		3.5		471.5
Acquisitions	36.2		—		36.2
Change in asset retirement cost	79.5		—		79.5
Dispositions	(135.3	)	—		(135.3	)
Balance, June 30, 2014	7,306.9		58.4		7,365.3
Accumulated depletion, depreciation, amortization and impairment
Balance, December 31, 2013	(1,963.1	)	(21.8	)	(1,984.9	)
Depletion, depreciation and amortization	(307.1	)	(3.1	)	(310.2	)
Accumulated depletion and impairment associated with dispositions	75.2		—		75.2
Balance, June 30, 2014	(2,195.0	)	(24.9	)	(2,219.9	)
Carrying amounts
Balance, December 31, 2013	4,895.4		33.1		4,928.5
Balance, June 30, 2014	5,111.9		33.5		5,145.4

For the three and six months ended June 30, 2014, $9.7 million and $18.8 million of direct and incremental general and administrative expenses were capitalized to property, plant and equipment ("PP&E") ($8.8 million and $18.9 million for the three and six months ended June 30, 2013), respectively.

In the first quarter of 2014, ARC entered an agreement to dispose of certain non-core shallow gas assets located in southwestern Saskatchewan for proceeds of $32.7 million. The liabilities associated with the disposed assets were asset retirement obligations with a book value of $28.5 million. The transaction closed on April 15, 2014.

ARC Resources Ltd. Page 38

6. LONG-TERM DEBT

	June 30, 2014	December 31, 2013
Syndicated credit facilities
Cdn$ denominated	137.8	99.8
Working capital facility	—	6.1
Senior notes
Master Shelf Agreement
5.42% US$ note	40.0	39.9
4.98% US$ note	53.4	53.2
2004 Note Issuance
4.62% US$ note	—	6.8
5.10% US$ note	10.2	15.3
2009 note issuance
7.19% US$ note	28.8	43.1
8.21% US$ note	37.4	37.2
6.50% Cdn$ note	11.6	17.4
2010 note issuance
5.36% US$ note	160.1	159.5
2012 note issuance
3.31% US$ note	64.1	63.8
3.81% US$ note	320.3	319.2
4.49% Cdn$ note	40.0	40.0
Total long-term debt outstanding	903.7	901.3
Long-term debt due within one year	46.0	42.1
Long-term debt due beyond one year	857.7	859.2

As at June 30, 2014, the fair value of all senior notes is $776.8 million ($785.9 million as at December 31, 2013), compared to a carrying value of $765.9 million ($795.4 million as at December 31, 2013).

7. ASSET RETIREMENT OBLIGATIONS

	Six Months Ended June 30, 2014		Year Ended December 31, 2013
Balance, beginning of period	475.4		532.9
Increase in liabilities relating to development activities	6.0		12.8
Increase (decrease) in liabilities relating to change in estimate and discount rate	73.5		(53.4	)
Settlement of reclamation liabilities	(6.3	)	(18.5	)
Accretion	7.6		12.5
Dispositions	(28.5	)	(10.9	)
Balance, end of period	527.7		475.4
Expected to be incurred within one year	25.1		25.1
Expected to be incurred beyond one year	502.6		450.3

The Bank of Canada's long-term risk-free bond rate of 2.78 per cent (3.24 per cent at December 31, 2013) and an inflation rate of 2 per cent (2 per cent at December 31, 2013) were used to calculate the present value of the asset retirement obligations at June 30, 2014.

ARC Resources Ltd. Page 39

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 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 endedJune 30, 2014.

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 40

The following is a summary of ARC's financial assets and financial liabilities that are subject to offsetting as at June 30, 2014 and December 31, 2013:

	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, 2014
Risk management contracts
Current asset	14.0		(13.5	)	0.5		—		0.5
Long-term asset	48.0		(20.2	)	27.8		(0.2	)	27.6
Current liability	(60.5	)	13.5		(47.0	)	1.4		(45.6	)
Long-term liability	(25.0	)	20.2		(4.8	)	0.2		(4.6	)
Net position	(23.5	)	—		(23.5	)	1.4		(22.1	)
As at December 31, 2013
Risk management contracts
Current asset	13.7		(9.2	)	4.5		(0.1	)	4.4
Long-term asset	63.3		(1.6	)	61.7		(0.5	)	61.2
Current liability	(22.6	)	9.2		(13.4	)	0.5		(12.9	)
Long-term liability	(2.3	)	1.6		(0.7	)	0.1		(0.6	)
Net position	52.1		—		52.1		—		52.1

Risk Management Contracts

The following is a summary of all risk management contracts in place, excluding premiums, as at June 30, 2014. Risk management contract premiums have been disclosed as commitments in Note 11.

Financial WTI Crude Oil Contracts
			Volume	Bought Put	Sold Put	Sold Call
Term		Contract	bbl/d	US$/bbl (1)	US$/bbl (1)	US$/bbl
1-Jul-14	31-Dec-14	Collar	5,000	90.00	—	100.00 (2)
1-Jul-14	30-Sep-14	Collar	8,000	90.00	—	100.00 (1)
1-Jul-14	31-Dec-14	3-Way	5,000	90.00	70.00	100.00(1)
1-Oct-14	31-Dec-14	Collar	2,000	90.00	—	100.00 (1)
1-Oct-14	31-Dec-14	Collar	6,000	90.00	—	100.00 (1)
1-Jan-15	30-Jun-15	Collar	4,000	90.00	—	100.00 (1)
1-Jan-15	30-Jun-15	Collar	2,000	90.00	—	102.50 (1)

(1) Settled on the monthly average price.

(2) Settled on the annual average price.

Financial WTI Crude Oil First vs Second Month Calendar Spread Contracts(3)
			Volume	Spread
Term		Contract	bbl/d	US$/bbl
1-Jul-14	31-Dec-14	Swap	4,000	0.51
1-Jul-14	31-Dec-14	Put	2,000	0.40

(3) Settled on the monthly average price.

Financial NYMEX Natural Gas Swap Contracts (4)
			Volume	Sold Swap
Term		Contract	mmbtu/d	US$/mmbtu
1-Jul-14	31-Dec-14	Swap	110,000	4.07

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

ARC Resources Ltd. Page 41

Financial NYMEX Natural Gas Contracts (5)
			Volume	Bought Put	Sold Call
Term		Contract	mmbtu/d	US$/mmbtu	US$/mmbtu
1-Jul-14	31-Dec-14	Collar	130,000	4.00	4.25
1-Jan-15	31-Mar-15	Collar	75,000	4.00	4.50
1-Jan-15	31-Dec-15	Collar	60,000	4.00	5.00
1-Jan-15	31-Dec-15	Collar	30,000	4.00	4.75
1-Apr-15	31-Dec-15	Collar	65,000	4.00	4.25
1-Apr-15	31-Dec-17	Collar	10,000	4.00	4.50
1-Jan-16	31-Dec-17	Collar	90,000	4.00	5.00
1-Jan-18	31-Dec-18	Collar	50,000	4.00	5.00

(5) NYMEX Henry Hub "Last Day" Settlement

Financial AECO Basis Swap Contracts
			Volume	Ratio Sold Swap %
Term		Contract	mmbtu/d	AECO/NYMEX (6)
1-Jul-14	31-Dec-14	Swap	190,000	89.8
1-Jan-15	31-Dec-17	Swap	130,000	90.5
1-Jan-18	30-Jun-18	Swap	40,000	90.3
1-Jul-18	30-Jun-19	Swap	20,000	90.8

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

Foreign Exchange Contracts (7)
			Volume	Bought Put	Sold Call
Term		Contract	US$ millions/month	Cdn$/US$	Cdn$/US$
1-Jul-14	31-Dec-14	Collar	33.0	1.0418	1.0836
1-Jan-15	31-Dec-15	Collar	2.0	1.0400	1.0925

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

Foreign Exchange Swap Contracts (8)
			Volume	Sold Swap	Limit Price
Term		Contract	US$ millions/month	Cdn$/US$	Cdn$/US$ (9)
1-Jul-14	31-Dec-14	Swap	2.0	1.0505	—
1-Jul-14	31-Dec-14	Limit Swap	9.0	1.0456	1.1163
1-Jan-15	31-Dec-15	Limit Swap	2.0	1.0525	1.1350

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

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

Financial Electricity Heat Rate Contracts (10)
			Volume	Heat Rate
Term		Contract	MWh	GJ/MWh
1-Jul-14	31-Dec-17	Heat Rate Swap	20	13.71

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

Financial Electricity Contracts (11)
			Volume	Bought Swap
Term		Contract	MWh	Cdn$/MWh
1-Jul-14	31-Dec-16	Fixed Rate Swap	5	51.00

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

ARC Resources Ltd. Page 42

9. SHAREHOLDERS’ CAPITAL

(thousands of shares)	Six Months Ended June 30, 2014		Year Ended December 31, 2013
Common shares, beginning of period	314,067		308,888
Cancelled shares	(47	)	—
Dividend reinvestment program	1,913		4,611
Stock dividend program	575		568
Common shares, end of period	316,508		314,067

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

	Three Months Ended June 30		Six Months Ended June 30
(thousands of shares)	2014	2013	2014	2013
Weighted average common shares	315,917	310,881	315,314	310,240
Dilutive impact of share options	657	351	599	310
Weighted average common shares - diluted	316,574	311,232	315,913	310,550

Dividends declared for the three and six months ended June 30, 2014 and 2013 were $0.30and $0.60 per common share.

On July 16, 2014, 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, 2014. The dividend payment date is August 15, 2014. Of the $31.7 million in dividends payable at June 30, 2014, $2.9 million is payable in common shares under the Stock Dividend Program ($2.6 million at December 31, 2013).

10. 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, 2014:

(number of units, thousands)	RSUs		PSUs		DSUs
Balance, December 31, 2013	638		1,492		159
Granted	163		239		27
Distributed	(144	)	(190	)	—
Forfeited	(15	)	(10	)	—
Balance, June 30, 2014	642		1,531		186

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

	Six Months Ended June 30, 2014	Six Months Ended June 30, 2013
General and administrative expense	9.2	20.7
Operating expense	2.5	2.9
PP&E	1.7	3.1
Total compensation charges	13.4	26.7
Cash payments	17.3	15.7

At June 30, 2014, $46.9 million of compensation amounts payable were included in accounts payable and accrued liabilities on the balance sheet ($42.6 million at December 31, 2013) and $17.9 million was included in long-term incentive compensation liability ($26.1 million at December 31, 2013). A recoverable amount of $0.6 million was included in accounts receivable at June 30, 2014 ($0.6 million at December 31, 2013).

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Share Option Plan

ARC estimates the fair value of share options granted using a binomial-lattice option pricing model. The grant date fair values of the share option plans were $3.6 million, or $8.40 per option outstanding for the 2011 grant, $5.5 million, or $5.25 per option outstanding for the 2012 grant, $5.6 million, or $7.87 per option outstanding for the 2013 grant, and $5.8 million, or $10.21 per option outstanding for the 2014 grant. The first vesting is expected to occur on March 24, 2015. The following assumptions were used to arrive at the estimated fair value at the date of the options grants:

	Six Months Ended June 30, 2014	Six Months Ended June 30, 2013
Grant date share price ($)	20.20 - 32.94	20.20 - 27.15
Exercise price ($) (1)	17.80 - 32.94	19.00 - 27.15
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 $0.5 million and $1.1 million relating to the share option plan for the three and six months ended June 30, 2014 ($0.3 million and $0.7 million for the three and six months ended June 30, 2013), respectively. During the six months endedJune 30, 2014, $0.1 million of direct and incremental share option expenses were capitalized to PP&E (less than $0.1 million for the six months ended June 30, 2013).

The changes in total share options outstanding and related weighted average exercise prices for the six months ended June 30, 2014 were as follows:

	Share Options (number of units, thousands)		Weighted Average Exercise Price ($)
Balance, December 31, 2013	2,022		22.12
Granted	569		32.94
Forfeited	(19	)	22.18
Balance, June 30, 2014	2,572		24.04
Exercisable, June 30, 2014	—		—

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11. COMMITMENTS AND CONTINGENCIES

The following is a summary of ARC’s contractual obligations and commitments as at June 30, 2014:

	Payments Due by Period
	1 Year	2-3 Years	4-5 Years	Beyond 5 Years	Total
Debt repayments (1)	46.0	74.2	273.7	509.8	903.7
Interest payments (2)	35.7	63.1	53.0	63.0	214.8
Reclamation fund contributions (3)	3.6	6.6	6.1	49.9	66.2
Purchase commitments	46.1	18.2	13.9	7.9	86.1
Transportation commitments	45.6	62.7	56.2	109.8	274.3
Operating leases	15.5	28.9	26.7	64.1	135.2
Risk management contract premiums (4)	—	6.1	1.2	—	7.3
Total contractual obligations and commitments	192.5	259.8	430.8	804.5	1,687.6

(1) Long-term and current portion of long-term debt.

(2) Fixed interest payments on senior notes.

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

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

In addition to the above risk management contract premiums, ARC has commitments related to its risk management program (see Note 8). As the premiums are related to the underlying risk management contracts, they have been recorded at fair market value at June 30, 2014 on the balance sheet as part of risk management contracts.

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

ARC is involved in litigation and claims arising in the normal course of operations. Such claims are not expected to have a material impact on ARC’s results of operations or cash flows.

Subsequent to June 30, 2014, ARC entered into transportation commitments with an aggregate obligation of $105 million and are effective for the years 2015 through 2026. These commitments are not included in the table above.

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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 the operating and general and administrative expense line items.

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

	Three Months Ended		Six Months Ended
	June 30		June 30
	2014	2013	2014	2013
Operating	7.9	9.6	17.2	16.1
General and administrative	19.3	20.5	38.9	48.9
Total employee compensation expenses	27.2	30.1	56.1	65.0

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	2014		2013		2014		2013
Accounts receivable	18.9		(4.7	)	(38.8	)	(9.5	)
Accounts payable and accrued liabilities	30.2		(34.3	)	93.7		(42.7	)
Prepaid expenses	(0.6	)	0.5		1.6		0.7
Total	48.5		(38.5	)	56.5		(51.5	)
Relating to:
Operating activities	40.3		14.6		20.8		(24.0	)
Investing activities	8.2		(53.1	)	35.7		(27.5	)
Total change in non-cash working capital	48.5		(38.5	)	56.5		(51.5	)

	Three Months Ended				Six Months Ended
	June 30				June 30
Other Non-Cash Items	2014		2013		2014		2013
Non-cash lease inducement	(0.5	)	(0.5	)	(0.9	)	(1.0	)
Gain on short-term investment	(0.5	)	(0.5	)	(1.1	)	(0.7	)
Share option expense	0.5		0.3		1.1		0.7
Total other non-cash items	(0.5	)	(0.7	)	(0.9	)	(1.0	)

	Three Months Ended				Six Months Ended
	June 30				June 30
Net Change in Other Liabilities	2014		2013		2014		2013
Long-term incentive compensation liability	2.1		3.9		(8.2	)	5.6
Risk management contracts	(0.1	)	1.9		(0.1	)	0.3
Asset retirement obligations	(3.1	)	(3.2	)	(6.3	)	(6.9	)
Total net change in other liabilities	(1.1	)	2.6		(14.6	)	(1.0	)

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