This document is an investor presentation from ARC Resources that contains forward-looking statements regarding ARC's projections, expectations, and beliefs relating to future production, reserves, exploration and development plans. It notes key metrics like current production of 92,800 boed, reserves of 572 mmboe, and an annualized dividend yield of 18%. It also outlines ARC's focus on oil and liquids-rich gas development in its core areas and production growth from areas like the Montney formation, while maintaining capital discipline and delivering returns to investors.

1. ARC Resources
Investor Presentation
January, 2013

2. FORWARD LOOKING STATEMENTS
This presentation contains forward-looking information as to ARC’s internal projections, expectations or beliefs relating to future events or
future performance and includes information as to our future well inventory in our core areas, our exploration and development drilling and
other exploitation plans for 2012 and beyond, and related production expectations, the volume of ARC's oil and gas reserves and the
volume of ARC's gas resources in the NE BC Montney (as defined herein), the recognition of additional reserves and the capital required
to do so, the life of ARC's reserves, the volume and product mix of ARC's oil and gas production, future results from operations and
operating metrics. These statements represent management’s expectations or beliefs concerning, among other things, future operating
results and various components thereof or the economic performance of ARC Resources. The projections, estimates and beliefs
contained in such forward-looking statements are based on management's assumptions relating to the production performance of ARC’s
oil and gas assets, the cost and competition for services, the continuation of ARC’s historical experience with expenses and production,
changes in the capital expenditure budgets, future commodity prices, continuing access to capital and the continuation of the current
regulatory and tax regime in Canada and necessarily involve known and unknown risks and uncertainties, such as changes in oil and gas
prices, infrastructure constraints in relation to the development of the Montney in British Columbia, risks associated with the degree of
certainty in resource assessments and including the business risks discussed in the annual MD&A and related to management’s
assumptions, which may cause actual performance and financial results in future periods to differ materially from any projections of future
performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or
circumstances could cause actual results to differ materially from those predicted. Other than the 2012 Guidance which is updated and
discussed quarterly, ARC does not undertake to update any forward looking information in this document whether as to new information,
future events or otherwise except as required by securities laws and regulations.
We have adopted the standard of 6 mcf:1 bbl when converting natural gas to barrels of oil equivalent ("boes"). Boes may be misleading,
particularly if used in isolation. A boe conversion ratio of 6 mcf per barrel is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current
price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the
6:1 conversion ratio may be misleading as an indication of value.
Contained in the “Strategy” section is forward-looking information. The reader is cautioned that assumptions used in the preparations of
such information, particularly those pertaining to dividends, production levels, operating costs and drilling results, although considered
reasonable by the Company at the time of preparation, may prove to be incorrect. A number of factors, including, but not limited to:
commodity prices, reservoir performance, weather, drilling performance and industry conditions, may cause the actual results achieved to
vary from projections, anticipated results or other information provided herein and the variations may be material. Consequently, there is
no representation by the Company that actual results achieved will be the same in whole or in part as those presented herein.

3. CORPORATE OVERVIEW
Production (2012 YTD) 92,800 boed
Liquids 36,000 boed
Natural gas 341 mmcfd
Crude Oil
Reserves (2P Gross) 572 mmboe NE BC/ NW AB
Liquids-rich Gas
17 year RLI (1)
Dry Gas
NORTH AB
Current monthly dividend $0.10
Annualized total return 18% (2) REDWATER
11% (3)
Enterprise value ~$8 billion (4) PEMBINA
Shares outstanding ~309 MM (5) SE SASK/
MANITOBA
Daily average trading volume 1.4 million shares S AB/
SW SASK
Net debt (millions) $691 (1.0 X cash flow)(5)
Member of S&P TSX 60 Index
(1) Based on 2012 production guidance of 91,000-94,000 boe/d.
(2) Annualized total return since inception to December 31, 2012, including December 2012 dividend, and assuming DRIP participation.
(3) Annualized total return December 31, 2007 (last 5 years).
(4) Market Capitalization as at December 31, 2012 and net debt as at September 30, 2012.
(5) As at September 30, 2012 based on annualized YTD 2012 cash flow.

4. 2012 FOCUS ON OIL AND LIQUIDS
• Oil and liquids comprised 40% of third quarter 2012 production while contributing 78% of
third quarter revenue
• Drilled 106 gross operated wells year-to-date (99% oil and liquids-rich)
• Grew crude oil and liquids production 16% to >35,600 boe/d in Q3 2012 (relative to Q3
2011) with significant growth at Ante Creek, Pembina and Goodlands
3%
Q4 Revenue
2%
22%
34%
Q4 Production 6%
Q3 Production Q3 Revenue
60%
3% 70%
Crude Oil
Condensate
NGL’s
Natural Gas

5. VALUE PROPOSITION
• We believe that top performing companies all have the following attributes:
– Great assets
– Operational excellence
– Capital discipline
– Management that delivers results
• At ARC our focus since inception has been on
“Risk Managed Value Creation”
• It is not a question of growth or income but of how best to create value
for our owners
• Current dividend of $0.10 per month

6. PRODUCTION GROWTH
Production Growth - Montney and Non-Montney
100,000
Montney Gas (boe/d)
Montney Oil/Liquids (bbls/d)
Non-Montney Gas (boe/d)
Non-Montney Liquids (boe/d)
80,000
Forecast
Total Non-Montney production
Production (Boe/d)
60,000
40,000
20,000
Forecast
Forecast
-

7. INCOME AND GROWTH
ARC HAS DELIVERED BOTH
• ARC has a 16 year history of risk managed value creation
- Provided an 18% annual total return since inception
- Paid out $4.6 billion in total dividends - $28.58/share
- Grown absolute production from 9,500 boe/d to ~93,000 boe/d, – the Montney provides
the opportunity for substantial future growth
- Grown debt and dividend adjusted reserves & production by ~ 10% annually
100,000
Production History
15% CAGR*
75,000
Gas Liquids
Boe/d
50,000
Proved
25,000 Undeveloped
20%
0
2012Q3
2002
2009
1996
1997
1998
1999
2000
2001
2003
2004
2005
2006
2007
2008
2010
2011
* Compound annual growth rate

8. STRATEGY
RISK MANAGED VALUE CREATION
Understand our Advantaged Position
Leverage our Advantaged Position
Make time to Think Strategically
Financial Operational
Flexibility Excellence
RISK
MANAGED
VALUE
CREATION
High Quality, Top Talent
Long Life and Strong
Assets Leadership
Culture
Be Dynamic and Flexible to Changing Conditions

9. STRATEGIC OVERVIEW
SUMMARY
• ARC’s strategy has delivered exceptional results to date
– We will continue to provide income and profitable growth to our investors
• Where do we go from here?
– Continued focus on meaningful oil and gas accumulations
– Our strategic initiatives will focus on:
• Operational excellence
• Developing the Montney – near term growth is forecast as an outcome
of the quality of our opportunities
• Realization of the value embedded in our assets through the
development of our large potential resources through advanced recovery
methods or application of new technologies
• Opportunistic acquisitions to add to our meaningful resource
play presence
• Maintaining balance sheet strength and financial flexibility

10. 2013 Budget
and Guidance

11. 2013 BUDGET
STRATEGIC OBJECTIVES
The 2013 Budget will:
• Focus on oil and liquids opportunities
• Invest in high rate of return natural gas opportunities to sustain
current production
• Leverage dominant presence and technical expertise in resource
plays
• Invest in infrastructure to set stage for growth in 2014
• Optimize capital efficiencies through active cost management and
enhanced commercialization of development
• Manage production decline rates by pacing growth
• Preserve ARC’s strong financial position and balance sheet strength

12. 2013 CAPITAL PROGRAM
SETTING THE STAGE FOR 2014 PRODUCTION GROWTH
• $830 million capital program (~178 gross operated wells) with majority of spending
in oil and liquids-rich gas plays and infrastructure.
NE BC - $324MM(1)
~36 gross operated wells
2013 Capital Budget
NE BC - $324MM*
(2)
~44,500 boe/dgross operated wells
~36 Volumes
~$100MM42,099 boe/d
directed towards NORTHERN AB - $211MM(1) Year
~37 NORTHERN AB - $211MM*
facilities at Parkland/Tower towards gross gross operated wells
operated wells Capital Average Gross Net
~$100MM directed ~37
~15,000 boe/d(2) $MM (boe/d) Wells Wells
facilities at Parkland/Tower 14,163 boe/d
Operated* 774 84,500 178 160
Parkland/Tower, Dawson
Non-Operated 56 10,600 103 10
REDWATER - $10MM(1)
REDWATER - $10MM*
0 wells Total 830 95,000 281 170
0 wells
~3,600 boe/d(2)
3,539 boe/d *Corporate $22 MM
PEMBINA - $131MM (1)
~54 gross operated - $131MM*
PEMBINA
wells ~54 gross operated wells
~11,000 boe/d(2)
9,220 boe/d
S. AB/SW SASK - $6MM(1) SE SASK/MANITOBA - $126MM(1)
0 wells AB/SW SASK - $6MM* gross operated wells
SE ~51
~7,900 boe/d(2)
0 wells ~12,600 boe/d(2)
6,214 boe/d
(1) Includes Operated and Non-operated.
(2) 2013 annual average production.

13. 2013 BUDGET
2013/2014 Production Growth
2013 Budget - Volumes (BOED)
All Properties
PO DEV OPT EXPLORE
140,000
2014 base production, does not
show 2014 CAPEX program
120,000
100,000
80,000 Base Decline ~22%
Base Decline ~22%
Base Decline ~22%
60,000
40,000
• Overall Corporate base decline of ~ 22%.
• Oil and Liquids production increases ~ 5%.
20,000
• Gas production grows by ~2%.
• Risks to the plan: commodity prices, timing issues and cost pressures related to service sector demand
for equipment and personnel, regulatory approvals and liquids sales pipeline capacities.
0

14. 2013 BUDGET
FOCUS ON OIL AND LIQUIDS
• 91% of budget focused on oil/liquids drilling and infrastructure
2013 Capital by
Commodity
($ millions)
$22
NE BC/NW AB $56
NORTHERN AB
$171
$581
~85% spending on oil and ~100% spending on oil and
liquids-rich gas liquids-rich gas
Focus: Parkland/Tower, Focus: Ante Creek
2013 Drills by
Dawson
Commodity
PEMBINA
(# of Gross Operated Wells)
9
16
~100% spending on oil and SE SASK/ MB 153
liquids-rich gas
Focus: Cardium
Oil
~100% spending on oil Liquids-rich
Focus: Goodlands Gas
Other

15. 2013 BUDGET
($ millions) 2011 (Actual) 2012 (Estimate) 2013 (Budget)
Development 396 400 563
Development – Facilities 92 70 162
Maintenance 21 27 35
Optimization 14 9 13
Exploration & Seismic 94 52 11
Enhanced Oil Recovery 20 21 27
Land 75 4 -
Other 14 17 19
Total Capital $726 $600 $830
(1) Other capital of $19 million comprises capitalized General and Administrative Expenses (“G&A”) including a portion of Long-Term Incentive Plan
(“LTIP” or the “Whole Unit Plan”) expense, information technology and corporate office capital.

16. 2013 GUIDANCE
2012 Guidance 2012 YTD Actual 2013 Guidance
Oil (bbls/d) 30,000 – 31,000 30,955 32,000 – 34,000
Condensate (bbls/d) 2,100 – 2,500 2,368 1,800 – 2,000
Gas (mmcf/d) 340 – 350 341 340 – 350
NGL’s (bbls/d) 2,100 – 2,600 2,644 2,400 – 2,800
Total (boe/d) 91,000 – 94,000 92,814 93,000 – 97,000
Operating costs 9.50 – 9.70 9.61 9.50 – 9.70
Transportation costs 1.30 – 1.40 1.30 1.40 – 1.50
G&A expenses (1) 2.45 – 2.60 2.78 2.50 – 2.70
Interest 1.20 – 1.30 1.33 1.20 – 1.30
Income Taxes (2) 0.90 – 1.05 1.03 1.05 – 1.15
Capital expenditures (millions) (3) 600 830
418
Land expenditures and minor net property
acquisitions ($ millions) (4) 25 - 50 31 -
Weighted average shares outstanding (millions) (5) 297 293 311
(1) The 2013 G&A expense before Long-Term Incentive Plan approximates $90 million ($1.75 - $1.90 per boe).
(2) 2013 Corporate tax estimate will vary depending on level of commodity prices.
(3) The $830 million 2013 capital budget does not include land and net property acquisitions as this amount is unbudgeted.
(4) Based on weighted average shares plus the dilutive impact of share options outstanding during the period.

17. Asset Overview

18. ASSET OVERVIEW
• ARC’s key assets with the greatest value creation opportunities and
highest future reserves contributions are:
• Ante Creek – oil resource play
• Parkland/Tower/Attachie/Septimus – liquids-rich gas resource play
• Pembina Cardium – oil resource play
• Goodlands and SE Saskatchewan – oil resource play
• Dawson – natural gas resource play
• Sunrise/Sunset – natural gas resource play
• ARC plans to develop these opportunities, subject to a supportive
commodity price environment, over the next five years
• Highlights from a few of these key areas will be covered in this
presentation

19. Pembina Revitalizing a
Mature Oil Field

20. PEMBINA
ASSET DETAILS
Net production (boe/d) – Q3 2012 11,300
Cardium production ~80%
Production split % (liquids/gas) ~75%/25%
Land (Cardium net sections) 132
Working Interest ~78%
Reserves (2P mmboe) Cardium 41.6
Reserve Life Index 14.2
2012 Plans/Accomplishments
• ARC is the second largest operator in the
Pembina area
• 29 Hz Cardium wells drilled year-to-date 2012
• Encouraging results on recent Buck Creek
horizontals

21. PEMBINA
OIL AND LIQUIDS GROWTH
ARC HAS GROWN LIQUIDS PRODUCTION IN THIS MATURE FIELD
Pembina ~19% Increase in Oil & Liquids Production since 2006
14,000
12,000
10,000
8,000
Boe/d
Q3 2012 - 8,200 boe/d
6,000 Q1 2006 - 6,900 boe/d oil and liquids
oil and liquids
4,000
Forecast
2,000 gas
oil & liquids
0
Q1 2006
Q2 2006
Q3 2006
Q4 2006
Q1 2007
Q2 2007
Q3 2007
Q4 2007
Q1 2008
Q2 2008
Q3 2008
Q4 2008
Q1 2009
Q2 2009
Q3 2009
Q4 2009
Q1 2010
Q2 2010
Q3 2010
Q4 2010
Q1 2011
Q2 2011
Q3 2011
Q4 2011
Q1 2012
Q2 2012
Q3 2012
Q4 2012

22. PEMBINA
CARDIUM DEVELOPMENT ECONOMICS
250 Key Metrics
DCET Capex per well ($MM) 2.3
Reserves per well (Mboe) 171
200
IP (1 mo) (boe/d) 227
IP (12 mo) (boe/d) 90
Economics ($85/bbl) $4/GJ $3/GJ
IRR (% AT) 52% 50%
150 Recycle Ratio 3.9 3.8
Rate (boepd)
100
50
0
0 6 12 18 24 30 36
Months On Production
• All economics run at FLAT price forecasts with C$85/bbl and $3/GJ AECO

23. PEMBINA
2013 BUDGET – $131MM
2013 Budget - Volumes (BOED)
Operated and Non-Operated
PO DEV OPT
14,000
12,000
10,000
8,000
Base DeclineBase Decline ~23%
~23%
Base Decline ~23%
6,000
4,000
• Drill 54 gross operated wells throughout the Pembina area.
• Grow operated production to >10,000 boed and total production to over ~12,000 boed.
2,000
• Continue to optimize waterfloods throughout the area by spending $9 MM (gross) on drilling
water injection wells, converting wells producers to injectors and injection stimulations.
0

24. Ante Creek A Montney
Oil Success Story

25. ANTE CREEK
ASSET DETAILS
Net production (boe/d) – Q3 2012 10,500
Liquids (bbls/d) 5,400
Gas (mmcf/d) 31
Production split % (liquids/gas) ~50/50
Land (Montney net sections) 263
Working Interest ~99%
Reserves (2P mmboe) 47.2
Liquids (mmbbls) 20.2
Gas (bcf) 162
Reserve Life Index 18.2
2012 Plans/Accomplishments
• 30 mmcf/d gas plant commissioned in late February,
alleviating capacity constraints
• Growth in oil and liquids production in 2012
• Production to increase through 2013 as we “drill to fill”
new gas plant

26. ANTE CREEK
2012 ACCOMPLISHMENTS
Ante Creek Production
16,000 16,000
• 30 mmcf/d gas plant commissioned in
14,000 14,000 late February, alleviating capacity
constraints
12,000 12,000 • Growth in oil and liquids production
in 2012
10,000 10,000
• Production to increase through 2013
Sales (boe/d)
8,000 8,000
as we “drill to fill” new gas plant
• Drill 21 Hz wells by year-end 2012
6,000 6,000
• Successful delineation step out
4,000 4,000
locations to extend pool boundaries
• Added 12 sections of land year-to-date
2,000 2,000 through Crown land sales and asset
acquisitions
- -
2008 2009 2010 2011 2012 2013 • Transition to pad drilling to minimize
Liquids (F) Gas (F) Liquids Gas environmental footprint and optimize
operational efficiency

27. ANTE CREEK
MONTNEY DEVELOPMENT ECONOMICS
450
Key Metrics
DCET Capex per well ($MM) 4.0
400
Reserves per well (Mboe) 283
IP (1 mo) (boe/d) 400
350
IP (12 mo) (boe/d) 245
Economics ($85/bbl) $4/GJ $3/GJ
300
IRR (% AT) 45% 35%
Recycle Ratio 2.1 2.0
250
BOE/D
200
150
100
50
0
0 6 12 18 24 30 36
Months
• All economics run at FLAT price forecasts with C$85/bbl and $3 GJ AECO
• Liquid yield assumptions – NGL 21 bbl/mmcf, COND 9.5 bbl/mmcf

28. ANTE CREEK
2013 BUDGET – $186MM OPERATED
2013 Budget - Volumes (BOED)
Operated
PO DEV OPT
16,000
14,000
12,000
10,000
8,000
Base Decline ~28%
6,000
4,000
• Drill 34 wells and grow production to 15,000 boed by the end of 2013.
2,000
• Drill 4 step-out wells to hold land (expiries) and prove up undeveloped land base.
0

29. British Columbia Montney Gas
and Liquids

30. NE B.C. MONTNEY
VAST RESOURCE BASE
We engaged GLJ to provide a resources evaluation of our properties at Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown and
Blueberry located in northeastern British Columbia and at Pouce Coupe located in northwestern Alberta (collectively, the "Evaluated Areas" or "NE BC
Montney"). The evaluation procedures employed by GLJ are in compliance with standards contained in the Canadian Oil and Gas Evaluation Handbook
("COGE Handbook") and the evaluation is based on GLJ's January 1, 2012 pricing
The estimates of Economic Contingent Resources (or ECR), DPIIP, TPIIP, UPIIP and Prospective Resources should not be confused with reserves and
readers should review the definitions and notes set forth at the end of this presentation. Actual natural gas resources may be greater than or less than
the estimates provided herein.
There is no certainty that it will be commercially viable to produce any of the resources that are categorized as discovered resources. There is no
certainty that any portion of ARC's resources that have been categorized as undiscovered resources will be discovered. Furthermore, if discovered, there
is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. Unless indicated otherwise in this presentation,
all references to ECR volumes are Best Estimate ECR volumes.
Continuous development through multi-year exploration and development programs and significant levels of future capital expenditures are required in
order for additional resources to be recovered in the future. The principal risks that would inhibit the recovery of additional reserves relate to the potential
for variations in the quality of the Montney formation where minimal well data currently exists, access to the capital which would be required to develop
the resources, low gas prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the
required services at the appropriate cost, and the effectiveness of fraccing technology and applications. The contingencies that prevent the ECR from
being classified as reserves are due to the early evaluation stage of these potential development opportunities. Additional drilling, completion, and test
results are required before these contingent resources are converted to reserves and a larger component of DPIIP is converted to ECR.
Projects have not been defined to develop the resources in the Evaluated Areas as at the evaluation date. Such projects, in the case of the Montney
resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints,
ARC's policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of ARC on gas
prices, the results of exploration and development activities of ARC and others in the area and possible infrastructure capacity constraints.
See “Definitions of Oil and Gas Reserves and Resources” in this presentation.

31. MONTNEY LANDS
WORLD CLASS RESOURCE
• NE BC Montney lands are a major
growth engine.
• Significant opportunity to grow
liquids production.
• Total BC Montney production of 240
mmcf/d with Dawson contributing
approximately 160 mmcf/d.
• New, 60 mmcf/d gas plant with 130
bbls/mmcf of liquids handling
capacity planned for Parkland/Tower
in early 2014.
• Ideally positioned with access to
west coast and other Alberta
markets.

32. NE B.C. MONTNEY
RESERVES AND RESOURCES
• Very early stage in reserve booking cycle:
• 2P Reserves (1.9 Tcf) plus Cum Prod only 5.3% of TPIIP at 3%
cut-off (4.2% at 0% cut-off).
• Best Estimate ECR estimated to be 4.1 Tcf resulting in total
recovery including 2P reserves and Cum Prod to date of only
15.7% of TPIIP at 3% cut-off (12.3% at 0% cut-off).
• ARC estimates the 2P Reserves plus ECR (6.0 Tcf) can support a
peak production rate of 800 mmcf/d for 10 years.
• Estimated Prospective Resources of 4.0 Tcf (“Best Estimate”) results
in a total potential recovery factor of ~20% - 25% of the TPIIP.
Recovery factors at that level could support a peak production rate of
>1.3 Bcf/d for 10 years.

33. MONTNEY GROWTH ASSETS
EXCEEDING EXPECTATIONS
ARC’S MONTNEY GAS WELLS HAVE THE BEST INITIAL PRODUCTIVITY
NE BC/NW AB Montney Gas Wells - P50 Peak Calendar Month Daily IP
Source information: Accumap - NEBC NWAB Montney horizontals peak month IP July 2012.

34. Parkland/Tower Liquids
Rich Gas

35. PARKLAND/TOWER
EVALUATING POTENTIAL AND DEVELOPING
EXISTING LANDS
Parkland Tower
Net production (boe/d) 7,200 800
Tower
Liquids (bbls/d) 930 500
Gas (mmcf/d) 39 1.7
Land (net sections) 23 56
Working Interest ~84% ~90%
Reserves (2P mmboe) 49.7 4.5
Liquids (mmbbls) 8.4 1.4
Gas (bcf) 247.0 19.2
Parkland
Reserve Life Index 16 37
2012 Plans/Accomplishments
• 11 wells drilled at Tower since late 2011
• 8 wells now tied-in at Tower, with restricted production rates as result of liquids handling facility limitations
• Application submitted to construct two 60 mmcf/d gas plants with 130 bbls/mmcf liquids handling capacity.
Pending approval, will commence construction in 2013 with commissioning of the first phase in early 2014.

36. PARKLAND
LAYERED DEVELOPMENT
• Producing Formation:
Upper Montney
Gross thickness 100m
Net pay 90m
Porosity 6%
Permeability 0.01 to 0.1 mD
• Large DGIP volumes in Parkland, currently have
modest recoveries per well
• 100 Bcf DGIP per section, ~100 meters of pay
• EUR/well typically ~ 5 Bcf (20% Recovery factor)
• Recovery factor low relative to developed areas

37. PARKLAND
LAYERED WELL PERFORMANCE
• Drilled and completed 2 wells in upper sand of the Upper Montney
and 1 well offset in the lower sand in 2011
• All wells had similar IP, ranging from 4.7 – 5.1 MMcfd
• No pressure response between the upper wells and the lower
Montney well to date
• Lack of vertical communication indicates potential of
un-stimulated rock
• Lower sand Montney performance to date in line with upper
type well
Layered Well Placement
7,000
Upper #1 Upper #2 6,000
400 m 5,000
Rate Mcfd
4,000
3,000
Lower Montney
50 m 2,000
1,000
200 m 200 m 0
Upper MTY Well #1 (10 Stage) Upper MTY Well #2 (9 Stage) Lower MTY Well (9 Stage)

38. PARKLAND
MONTNEY DEVELOPMENT ECONOMICS
Key Metrics
7,000 DCET Capex per well ($MM) 5.2
Reserves per well (Bcf) 5.8
6,000 IP (1 mo) (MMcf/d) 5.0
IP (12 mo) (MMcf/d) 4.0
Economics ($85/bbl) $4/GJ $3/GJ
5,000
IRR (% AT) 79% 54%
Gas Rate (Mcf/d)
Recycle Ratio 4.2 3.3
4,000
3,000
2,000
1,000
0
0 6 12 18 24 30 36
Months
• All economics run at FLAT price forecasts with C$85/bbl and $3/GJ AECO
• Liquid yield assumptions – 11 bbl/mmcf C5+, 13 bbl/mmcf NGL

39. TOWER
2012 ACCOMPLISHMENTS
Tower Production
2,500 2,500 • Drilled 8 Hz wells Q3 YTD
• 2012 Operated Program average
30 day IP rate: 375 boe/d per well
2,000 2,000
• Production volumes limited due to
liquid handling restrictions
• Granted a Royalty Infrastructure
1,500 1,500
Sales (boe/d)
Credit Grant for gathering system
• BC OGC reclassified all Tower
1,000 1,000
producing wells and upcoming well
ARC purchased licenses to oil wells
the Tower
property in 2010
• Gas plant application submitted to
500 500
regulatory body OGC for
120 mmcfd gas plant and
liquids handling facility
- -
2010 2011 2012 2013
Liquids (F) Gas (F) Liquids Gas
(1) ARC purchased the Tower property in August 2010.

40. TOWER
OPERATIONAL EXCELLENCE - MINIMIZING FOOTPRINT
• Pad drilling will substantially minimize
surface land footprint
• Expect 8 to 16 wells per pad
depending on reservoir characteristics
• Considerable cost savings related to
pad development compared to single
well leases, up to 20%
• Numerous operational and capital
efficiencies due to pad development:
reduced rig moves; single lease to
survey, acquire and build;
consolidated facilities, electricity to
one site, single trunk line
• The cycle time from spud to on
production is extended by 5 months
for an 8 well pad. All wells are drilled
and completed before production
commences

41. TOWER
MONTNEY DEVELOPMENT ECONOMICS
600 Key Metrics
DCET Capex per well ($MM) 5.3
Reserves per well (Mboe) 400
500 IP (1 mo) (boe/d) 500
IP (12 mo) (boe/d) 260
Economics ($85/bbl) $4/GJ $3/GJ
400 IRR (% AT) 41% 37%
Production Rate (boe/d)
Recycle Ratio 3.3 3.1
300
200
100
0
0 6 12 18 24 30 36
Months
• All economics run at FLAT price forecasts with C$85/bbl and $3/GJ AECO
• Difference between EDM and quality & transport adjustments = +4.25 $/bbl
• Liquid yield assumptions – 79.2 bbl/MMcf, shrinkage = 20.6%

42. TOWER/PARKLAND
2013 BUDGET – $249MM OPERATED
2013 Budget - Volumes (BOED)
Operated
PO DEV OPT
25,000
20,000
2014 base
production, does not include 2014 CAPEX program
15,000
10,000
Base Decline ~21%
5,000
• Drill 24 horizontal wells.
• Construct the oil handling, gas processing and pipeline infrastructure with a planned start-up in early 2014
• Significant capital being spent in 2013 with volumes coming on-stream in 2014.
0

43. Dawson World Class
Asset

44. DAWSON
ASSET DETAILS
Net production (boe/d) – YTD 2012 25,300
Liquids (bbls/d) 700
Gas (mmcf/d) 160
45 mmcf/d
Compressor Production split % (liquids/gas) ~97% gas
Station
120 mmcf/d Land (Montney net sections) 130
Gas Plant
Working Interest ~96%
Reserves (2P mmboe) 174
Liquids (mmbbls) 5.0
Gas (bcf) 1,012
Reserve Life Index 16.8
2012 Plans/Accomplishments
• Inventory of completed gas wells to be tied-in
throughout remainder of 2012 and into 2013
• Maintain 2012 production flat at 165 mmcf/d

45. DAWSON
RESERVE GROWTH
• Reserve growth from 2008 – 2010 due to PUD assignment driven by repeated success
of our drilling program and improved well confidence
• Reserve growth from 2011 driven by modest PUD adds and overall improved
performance expectations from individual wells
• Higher confidence in production performance and repeatability is evident on assigned
EUR/well and field recovery factor
50% 7.0
45%
6.0
40%
Assigned EUR/Well (Bcf)
Field Recovery Factor
35% 5.0
30%
4.0
25%
3.0
20%
15% 2.0
10%
Field Recovery Factor
1.0
5% Assigned EUR/Well (Bcf)
0% 0.0
2008 2009 2010 2011

46. DAWSON
TYPE CURVE GROWTH
• 2008 type curve analysis was completed using initial production results and verified with
a vertical well production multiplier
• 2009-2011 Type curve used P90 IP’s with decline analysis and assigned decline
exponent rate
• 2012 Type curve realized the consistent flat production, coupled with a sharp decline
exponent rate
• 2013 type curve uses historical pressure and production data from 60+ wells to estimate
existing remaining reserves and forecast future wells
6,000
2013 Type Curve
5,000 2012 Type Curve
2009-2011 Type Curve
Gas Rate (Mcf/d)
4,000
2008 Type Curve
3,000
2,000
1,000
0
0 3 6 9 12 15 18 21 24 27 30 33 36
Months on Production

47. DAWSON
MONTNEY DEVELOPMENT ECONOMICS
7,000 Key Metrics
DCET Capex per well ($MM) 5.2
6,000 Reserves per well (Bcf) 7.1
IP (1 mo) (MMcf/d) 5.0
IP (12 mo) (MMcf/d) 4.8
5,000 $4/GJ $3/GJ
Economics ($85/bbl)
IRR (% AT) 72% 44%
Gas Rate (Mcf/d)
4,000 Recycle Ratio 3.8 2.8
3,000
2,000
1,000
0
0 6 12 18 24 30 36
Months
• All economics run at FLAT price forecasts with C$85/bbl and $3/GJ AECO
• Liquid yield assumptions – 3.1bbl/mmcf C5, 0.7bbl/mmcf C4, 0.4bbl/mmcf C3

48. DAWSON
2013 BUDGET – $52MM OPERATED
2013 Budget - Volumes (BOED)
Operated
PO DEV
35,000
30,000
25,000
20,000
Base Decline ~28%
15,000
10,000
5,000
• Dawson is a world-class asset that continues to exceed expectations.
• Drill 9 horizontal Montney wells, on two pads, add compression to 1-34 compressor station
and optimize gas plant.
0

49. WEST MONTNEY Long-term
Growth Opportunity

50. WEST MONTNEY
ASSET DETAILS
Net production (boe/d)- Q3 2012 3,450
Liquids (bbls/d) 30
Gas (mmcf/d) 20.5
Land (net Montney sections) 211
Working Interest ~93%
Reserves (2P mmboe) 112
Liquids (mmbbls) 7
Gas (bcf) 628
Year # Hz Wells Drilled
2009 4 non-op
2010 4 operated
1 non-op
2011 5 operated
2012 Estimate 2 operated
1 non-op
2013 Budget 2 operated

51. WEST MONTNEY
OPERATIONAL EXCELLENCE – DEVELOPMENT PLANNING

52. WEST MONTNEY
SUNRISE PRODUCTION – OUTPERFORMING EXPECTATIONS
• Expect positive technical revisions in Sunrise based on 2-25 Hz well pad performance
Montney A Sunrise A2-25 Hz
Cum to date: 2 Bcf
EUR Forecast: 11 – 14 Bcf
GLJ 2011 (2P) EUR: 7 Bcf
Montney B Sunrise B2-25 Hz Cum to date: 2 Bcf
EUR Forecast: 10 – 13 Bcf
GLJ 2011 (2P) EUR: 6 Bcf

53. SUNRISE
MONTNEY SUNRISE DEVELOPMENT ECONOMICS
Key Metrics
DCET Capex per well ($MM) 5.5
Reserves per well (Bcf) 9.7
6,000
IP (1 mo) (MMcf/d) 5.2
IP (12 mo) (MMcf/d) 4.5
5,000 Economics ($85/bbl) $4/GJ $3/GJ
Gas Rate mcf/d
IRR (% AT) 51% 32%
4,000 Recycle Ratio 4.5 3.2
3,000
2,000
1,000
0
0 6 12 18 24 30 36
Months
• All economics run at FLAT price forecasts with C$85/bbl; $3/GJ AECO
• Liquid yield: Condensate 1 bbls/MMcf, Propane 3 bbls/MMcf, Butane 1 bbls/MMcf (assume ARC Plant scenario)

54. Summary

55. WHY INVEST IN ARC RESOURCES
• ARC is a top-tier oil and natural gas producer focused on “Risk Managed Value Creation”
• Extensive land position in top quality resource plays provides significant growth opportunity.
• Significant near-term oil and liquids growth opportunities
• Significant long-term natural gas growth opportunity in B.C. Montney
• Diverse inventory of high quality oil, liquids-rich gas and natural gas development
opportunities provides optionality through commodity price cycles
• History of proven performance
• Grown absolute production from 9,500 boe/d to ~93,000 boe/d to date
• Grown P+P reserves from 47 mmboe to 572 mmboe to date
• Progressive approach of applying new technologies to “unlock” value
• Proven track record of “Operational Excellence” in both cost management and safety
• Solid balance sheet with protective hedging program
• Experienced management team with track record of delivering results

56. PRODUCTION GROWTH
Production Growth - Montney and Non-Montney
100,000
Montney Gas (boe/d)
Montney Oil/Liquids (bbls/d)
Non-Montney Gas (boe/d)
Non-Montney Liquids (boe/d)
80,000
Forecast
Total Non-Montney production
Production (Boe/d)
60,000
40,000
20,000
Forecast
Forecast
-

57. Appendix

58. 2012 FINANCIAL AND
OPERATIONAL PERFORMANCE
Q3 2012 YTD Q3 2012
(CDN$ millions, except per share and per boe amounts) 2012 2011 2012 2011
Production (boe/d) 89,511 85,178 92,814 80,517
Gas 60% 64% 61% 61%
Liquids 40% 36% 39% 39%
Revenue 329.4 351.3 1,012.6 1,049.7
Gas 72.9 116.9 223.0 321.8
Liquids 256.5 234.4 789.6 727.9
Funds from operations 164.9 213.5 511.4 617.6
Per share 0.55 0.74 1.74 2.15
Operating Income 26.6 68.0 104.1 217.4
Per share 0.09 0.24 0.35 0.76
Dividends 90.6 86.2 264.9 257.5
Per share 0.30 0.30 0.90 0.90
Capital expenditures 133.1 229.3 417.8 531.0
Net debt outstanding 691.0 870.1 691.0 870.1
Weighted average number of shares outstanding
(millions) 299.7 287.1 293.4 286.0
Netback (pre-hedging) 23.04 26.62 23.25 29.77

59. ACCESS TO CAPITAL
DEBT
Debt raised from three different sources:
1. Bank Credit Facility - $1.9 billion plus $25 million overdraft facility, 12 banks under
facility
• $nil drawn under credit facility as at September 30, 2012
• The credit facility was extended to August 3, 2016
• Pre-approval for an additional $250 million (Accordion)
2. Long-term notes
• Private Placement market
• Currently have US$631MM and CDN$63MM drawn (Q3 2012)
3. Prudential Master Shelf
• Direct long-term relationship with major insurance company
• Currently have US$106.3 MM drawn out of capacity of US$225MM (Q3 2012)
• Term extended to April 14, 2015

60. DEBT MATURITIES
SPREAD OVER TIME
• ARC’s long-term notes are structured so that they mature over a number of years; this
reduces refinancing risk
• ARC’s undrawn credit facility of $1.2 billion (after debt and equity proceeds) allows for
significant flexibility to repay debt
Long-term Principal Note Repayment Schedule
120
100
80
C$ Millions
60
40
20
0
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

61. HEDGE POSITIONS
AS OF NOVEMBER 7, 2012
Summary of Hedge Positions as at November 7, 2012 (1)
Nov – Dec 2012 2013 2014 2015 - 2017
Crude Oil – WTI (2):
(US$/bbl) US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d
Ceiling $ 91.11 18,000 $ 104.01 14,992 - - - -
Floor $ 90.00 18,000 $ 95.01 14,992 - - - -
Sold Floor $ 63.44 16,000 $ 64.17 11,984 - - - -
Crude Oil Floors as % of 2012
Guidance (3) 55% 43% -
Natural Gas – Nymex (3): US$/mmbtu mmbtu/d US$/mmbtu mmbtu/d US$/mmbtu mmbtu/d US$/mmbtu mmbtu/d
$ 3.48
Ceiling 175,000 3.93 157,041 $ 4.83 90,000 $ 5.00 60,000
$ 3.48
Floor 175,000 3.39 157,041 $ 4.00 90,000 $ 4.00 60,000
Natural Gas Floors as % of 2012
Guidance (3) 50% 46% 26% 17%
Total Floors as % of 2012 Guidance (3) 51% 43% 16% 11%
(1) The prices and volumes noted above represent averages for several contracts representing different periods and the average price for the portfolio of options listed above does not
have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes.
(2) For 2012 and 2013, all floor positions settle against the monthly average WTI price, providing protection against monthly volatility. Positions establishing the “Ceiling” have been sold
against either the monthly average or the annual average WTI price. In the case of settlements on annual positions, ARC will only have a negative settlement if prices average
above the strike price for an entire year, providing ARC with greater potential upside price participation for individual months.
(3) Based on 2012 guidance of 92,500 boe/d for 2012 hedge positions and based on 2013 guidance midpoint of 95,000 boe/d for 2013, 2014 and 2015-2017 hedge positions. Crude
oil floors as a % of production are based on guidance volumes for crude oil and condensate production for the respective period.

62. RESERVES AND RESOURCES
The discussion in this presentation in respect of reserves and resources is subject to a number of cautionary statements,
assumptions and risks as set forth below and elsewhere in this presentation. See also the definitions of oil and gas reserves
and resources found at the end of this presentation.
The reserves data set forth in this presentation is based upon an evaluation by GLJ Petroleum Consultants Ltd. ("GLJ") with
an effective date of December 31, 2011 using forecast prices and costs. The reserves evaluation was prepared in
accordance with National Instrument 51-101 ("NI 51-101"). Crude oil, natural gas and natural gas liquids benchmark
reference pricing, as at December 31, 2011, inflation and exchange rates used in the evaluation are based on GLJ's
January 1, 2012 pricing. Reserves included herein are stated on a company gross basis (working interest before deduction
of royalties without including any royalty interests) unless noted otherwise.
There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The
recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only
and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid
reserves may be greater than or less than the estimates provided herein.
See also ”NE B.C. Montney Vast Resource Base”, for further discussion regarding reserves and resources.
See “Definitions of Oil and Gas Reserves and Resources” in this presentation.

63. KEY RESERVE INFORMATION
19% COMPOUND ANNUAL GROWTH
• Reserves as of December 31, 2011* (mmboe)
- Proved Producing 209 (98 mmboe liquids, 655 bcf gas)
- Total Proved 360 (123 mmboe liquids, 1,419 bcf gas)
- Proved Plus Probable 572 (170 mmboe liquids, 2,413 bcf gas)
700
19% CAGR
600 Probable Proved
Producing
Gas 37%
36%
500 Liquids
Proved
mmboe
400 Undeveloped
25% Proved
300 Non-Producing 2%
2P Reserves
200
NGL's
6% Crude
100 oil
24%
0
Natural
Gas
70%
INTERNAL DEVELOPMENT
MONTNEY

64. 385 PER CENT
RESERVE REPLACEMENT IN 2011
• Fourth consecutive year of greater than 200% reserve replacement through the drill bit
• Proved plus probable reserves increased 18% to 572 mmboe after divest of non-core assets
with 14.6 mmboe of 2P reserves
700%
Acquisitions
600% Development
500%
400%
300%
200%
100%
0%
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

65. MONTNEY GROWTH ASSETS
RESERVES AND RESOURCES
• Independent Resources Evaluation conducted by GLJ effective December 31, 2011
• The amount of natural gas and NGLs which is ultimately recovered from ARC’s NEBC Montney
resource will be primarily a function of the future price of both commodities
3% Porosity Cut- 0% Porosity
Resource Categories (1) (2) Off (Tcf) Cut-Off (Tcf)
Total Petroleum Initially In Place (TPIIP) 39.6 50.4
Discovered Petroleum Initially In Place (DPIIP) 21.2 25.5
Undiscovered Petroleum Initially In Place (UPIIP) 18.4 24.9
Reserves and Economic Contingent Resources (3)(7)(8) Best Estimate
Natural Gas (Tcf)
Reserves (4) 1.9
Economic Contingent Resources 4.1
Natural Gas Liquids (mmbbls) (6)
Reserves 21.1
Economic Contingent Resources 101.0
Prospective Resources (3)(8) Best Estimate
Natural gas (Tcf) 4.0
Natural gas liquids (mmbbls) (6) 98.0
1) The resource categories do not include free liquids or associated solution gas in the Tower field.
2) All volumes in table are company gross and raw gas volumes.
3) All DPIIP other than cumulative production, reserves, and ECR and all UPIIP other than Prospective Resources has been categorized as unrecoverable.
4) For reserves, the volume under the heading Low Estimate are proved reserves, the volume under the heading Best Estimate are 2P reserves and the number under the heading High Estimate are 2P plus possible reserves.
5) This volume is an arithmetic sum of multiple estimates of reserves, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of
individual classes of reserves and appreciate the differing probabilities associated with each class.
6) The liquid yields are based on average yield over the producing life of the property.
7) Cumulative production has been 0.2 Tcf on a raw basis.
8) All volumes in table are company gross and sales volumes.

66. MONTNEY HORIZONTAL WELLS
30 DAY HZ IP RATES GLACIER - TOWN
ARC’S DAWSON/PARKLAND WELLS HAVE EXCEEDED EXPECTATIONS
14,000
12,000
10,000
Production Rate (mcf/d)
ARC Others
8,000
ARC P50
5.2 Mmcf/d
6,000
Other Wells P50
3.3 Mmcf/d
4,000
2,000
0
1 101 201 301 401 501 601 701 801 901 1001
(1) Graph represents peak calendar day IP rates for the first month of production to July 2012.
(2) Region includes all horizontal wells from NE BC and NW AB Montney.

67. SE SASKATCHEWAN OIL Solid Long-life
Assets

68. SE SASKATCHEWAN OIL
ASSET DETAILS R28 R27 R26 R25 R24 R23 R22 R21 R20 R19 R18 R17 R16 R15 R14 R13 R12 R11 R10 R9 R8 R7 R6 R5 R4 R3 R2 R1W2 R34 R33 R32 R31 R30 R29 R28 R27 R26 R25 R24 R23 R22W1
T14 T14
T13 T13
T12 T12
T11 T11
T10
Parkman T10
T9 T9
T8 T8
T7 Lougheed Midale T7
T6
North Browning T6
T5
Landscape T5
T4
Radville Weir Hill T4
T3
Bromhead Glen Ewen T3
T2 T2
T1
Oungre Elmore
T1
File: IR Annual Presentation SESKMB. Datum: NAD27 Projection: Stereographic Center: N49.54139 W103.04696 Created in AccuMap™, a product of IH
Net production (boe/d) – Q3 2012 9,300 Year # Hz Wells
Drilled
Production split 99% liquids 2009 11
Land (net sections) 232 2010 17
2011 21
Working Interest ~77%
2012 Estimate 35
Reserves (2P mmboe) 42 2013 Budget 29

69. SE SASKATCHEWAN OIL
2012 ACCOMPLISHMENTS
SE SK Production
14,000 14,000
• Increased total production in area
by 11% to 9,300 boe/d, relative to
12,000 12,000
Q3 2011
10,000 10,000
• Drilled 29 wells to the end of Q3 and
plan to drill 35 wells to year-end
• Continued to drill horizontally in a
Sales (boe/d)
8,000 8,000
number of properties that were
6,000 6,000
previously only vertically exploited
• Facility upgrades continue to be a
4,000 4,000 priority to support development
volumes
2,000 2,000 • Continued work on waterfloods in
Lougheed, Oungre, Skinner Lake
- -
2008 2009 2010 2011 2012 2013
Liquids (F) Gas (F) Liquids Gas

70. DEFINITIONS OF OIL AND GAS
RESERVES AND RESOURCES
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known
accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established
technology; and specified economic conditions, which are generally accepted as being reasonable. reserves are classified according to the
degree of certainty associated with the estimates as follows:
Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual
remaining quantities recovered will exceed the estimated proved reserves.
Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the
actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the
actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
Resources encompasses all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations,
including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. “Total resources” is equivalent
to “Total Petroleum Initially-In-Place”. Resources are classified in the following categories:
Total Petroleum Initially-In-Place (“TPIIP”) is that quantity of petroleum that is estimated to exist originally in naturally occurring
accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations,
prior to production, plus those estimated quantities in accumulations yet to be discovered.
Discovered Petroleum Initially-In-Place (“DPIIP”) is that quantity of petroleum that is estimated, as of a given date, to be contained in
known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production,
reserves, and contingent resources; the remainder is unrecoverable.
Forecast
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known
accumulations using established technology or technology under development but which are not currently considered to be
commercially recoverable due to one or more contingencies.

71. DEFINITIONS OF OIL AND GAS
RESERVES AND RESOURCES
Economic Contingent Resources are those contingent resources which are currently economically recoverable.
Undiscovered Petroleum Initially-In-Place (“UPIIP”) is that quantity of petroleum that is estimated, on a given date, to be contained
in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as
“prospective resources” and the remainder as “unrecoverable.”
Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from
undiscovered accumulations by application of future development projects.
Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future
development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or
technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented
by subsurface interaction of fluids and reservoir rocks.
Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and
resources as follows:
Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual
remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent
probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the
actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be
at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best
estimate.
High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the
Forecast
actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10
percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

72. This presentation contains forward-looking statements that may be identified by words like
“outlook”, “estimates” and similar expressions. These forward-looking statements are based on
certain assumptions that involve a number of risks and uncertainties and are not guarantees of
future performance. Reference is made to the section titled “Forward Looking Statements” at the
beginning of the presentation and also to the November 7, 2012 news release titled “ARC Resources
Ltd. Announces an $830 Million Capital Budget For 2013, Setting the Stage for Significant
Production Growth in 2014” which may be found on SEDAR at www.sedar.com and which are
hereby incorporated by reference in this presentation and which outline a number of assumptions,
risks and uncertainties associated with forward looking statements. Actual results could differ
materially as a result of changes to ARC’s plans, the impact of changes in commodity prices,
general economic, market and business conditions as well as production, development and
operating performance and other risks associated with oil and gas operations.
For further information about ARC Resources please visit our website www.arcresources.com
Or contact:
Investor Relations
E-mail: ir@arcresources.com
T 403.503.8600 F 403.509.6417
Toll Free 1.888.272.4900
ARC Resources Ltd.
1200, 308 – 4 Avenue S.W.
Calgary, AB T2P 0H7