ARC Resources provides an investor presentation detailing its oil and gas reserves, production growth, and financial performance. Some key points include: - ARC's proved plus probable reserves totaled 607 million barrels of oil equivalent as of December 31, 2012. - Between 2012 and 1997, ARC grew its proved plus probable reserves at a compound annual growth rate of 18%. - ARC replaced over 200% of its 2012 production at a finding and development cost of $9.34 per barrel of oil equivalent.

1. ARC
Resources
Investor Presentation
February, 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 2013 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 2013 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 Annual) 93,500 boed
Liquids 36,400 boed
Natural gas 343 mmcfd
Crude Oil
Reserves (2P Gross) 607 mmboe NE BC/ NW AB
Liquids-rich Gas
17.5 year RLI (1)
Dry Gas
NORTH AB
Current monthly dividend $0.10
Annualized total return 18% (2) REDWATER
7.5% (3)
Enterprise value ~$8 billion (4) PEMBINA
Shares outstanding ~309 MM (5) SE SASK/
MANITOBA
Daily average trading volume 1.1 million shares S AB/
SW SASK
Net debt (millions) $745 (1.0 X cash flow)(5)
Member of S&P TSX 60 Index
(1) Based on 2013 production guidance midpoint of 95,000 boe/d.
(2) Annualized total return since inception to January 31, 2012, including January 2012 dividend, and assuming DRIP participation.
(3) Annualized five year total return from January 31, 2008 (last 5 years).
(4) Market Capitalization as at February 1, 2013 and net debt as at December 31, 2012.
(5) As at December 31, 2012 based on annualized 2012 cash flow.

4. 2012 FINANCIAL AND
OPERATIONAL PERFORMANCE
Three Months Ended Year Ended
December 31 December 31
(CDN$ millions, except per share and per boe amounts) 2012 2011 2012 2011
Production (boe/d) 95,725 92,021 93,546 83,416
Gas 61% 64% 61% 62%
Liquids 39% 36% 39% 38%
Revenue 374.2 385.9 1,386.8 1,435.6
Gas 106.3 112.2 329.3 434.0
Liquids 267.9 273.7 1,057.5 1,001.6
Funds from operations 208.4 226.6 719.8 844.3
Per share 0.68 0.79 2.42 2.95
Operating Income 59.2 74.7 163.2 293.5
Per share 0.19 0.26 0.55 1.02
Dividends 92.5 86.7 357.4 344.0
Per share 0.30 0.30 1.20 1.20
Capital expenditures 190.2 195.0 608.0 726.0
Net debt outstanding 745.6 909.7 745.6 909.7
Weighted average number of shares outstanding
(millions) 308.4 288.3 297.2 286.6
Netback (pre-hedging) 26.85 27.55 24.17 29.16

5. VALUE PROPOSITION
• We believe that top performing companies all have the following attributes:
– Great assets
– Operational excellence
– Capital discipline
– Management that delivers results
– Strong balance sheet with financial flexibility
• 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 - $28.68/share
- Grown absolute production from 9,500 boe/d to ~95,000 boe/d, – the Montney provides
the opportunity for substantial future growth
- Grown debt and dividend adjusted reserves & production by ~ 10% annually
Production History
100,000 15% CAGR*
Gas
75,000
Liquids
Boe/d
50,000
Proved
Undeveloped
25,000 20%
0
1997
1998
1999
2001
2002
2003
2005
2006
2007
2008
2009
2010
2011
2012
1996
2000
2004
* Compound annual growth rate

8. 200 PER CENT
RESERVE REPLACEMENT IN 2012
• 2012 is the fifth consecutive year of greater than 200% reserve replacement
• Increase in 2P reserves of 6% to 607 mmboe
• Replaced 214% of crude oil and liquids reserves, increasing 9% to 186 mmbbls
• Reserves have more than doubled over the past five years, providing a clear line of sight
for resource development
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 2012

9. CAPITAL EFFICIENCY
EXCELLENT FD&A PERFORMANCE IN 2012
• Replaced 200% of production at an all in FD&A cost of $9.34/boe(1)
• 2012 recycle ratio of 2.7 times based on F&D of $9.01/boe(1) and pre-hedging netback of
$24.17/boe
• Three year FD&A of $7.80 before FDC
FD&A Costs and Recycle Ratio (1)
$25.00 6.0
FD&A
5.0
$20.00 F&D
Recycle Ratio
4.0
Recycle Ratio
$15.00
3.0
$10.00
2.0
$5.00
1.0
$- -
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
(1) FD&A and F&D for 2P reserves before Future Development Capital (“FDC”)
(2) FD&A costs including FDC were $13.26/boe and $13.30/boe, respectively, for 2012 and three year average.

10. SUSTAINABLE DIVIDEND
$4.6 BILLION IN DIVIDENDS SINCE INCEPTION
• The dividend is a critical component of our business strategy
• Sustained dividend levels through commodity price cycles due to quality of assets, active
hedging program and balance sheet strength
Historic Dividends and Funds from Operations
$5.00
100%
$4.50
$4.00
80%
$3.50
Payout Ratio %
$3.00
60%
$/share
$2.50
$2.00 40%
$1.50
$1.00 20%
$0.50
$- 0%
1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Cash Flow per Share Dividend per Share Payout Ratio Payout Ratio including DRIP

11. FOCUS ON OIL AND LIQUIDS
15% OIL AND LIQUIDS PRODUCTION GROWTH
•
IN 2012 oil and liquids development resulted in 15% growth in crude oil and
Focus on crude
liquids production to ~36,400 boe/d in 2012 primarily at Ante Creek, Pembina and
Goodlands
• Crude oil and liquids comprised 39% of total 2012 production while contributing 76% of
total year revenue
• Drilled 144 gross operated wells in 2012 (98% oil and liquids-rich)
Q4 Revenue
3% 3%
24%
34%
Q4 Production
2012 2012
5%
Production Revenue
61% Crude Oil
2% 68%
Condensate
NGL’s
Natural Gas

12. OUR 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

13. 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

14. 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, 2012 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, 2012, inflation and exchange rates used in the evaluation are based on GLJ's January 1, 2013 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.

15. KEY RESERVE INFORMATION
18% COMPOUND ANNUAL GROWTH
• Reserves as of December 31, 2012 (mmboe)
- Proved Producing 201 (100 mmboe liquids, 607 bcf gas)
- Total Proved 364 (127 mmbbls liquids, 1.4 Tcf gas)
- Proved Plus Probable 607 (186 mmbbls liquids, 2.5 Tcf gas)
700
18% CAGR
Probable Proved
600
Producing
Gas 33%
40%
500 Liquids
Proved
mmboe
400 Undeveloped
25% Proved
300 Non-Producing 2%
2P Reserves
200 NGL's
6%
Crude
100
oil
25%
0
Natural
Gas
69%
INTERNAL DEVELOPMENT
MONTNEY

16. 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, 2013 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.

17. MONTNEY GROWTH ASSETS
RESERVES AND RESOURCES
• Independent Resources Evaluation conducted by GLJ effective December 31, 2012
• In addition to the 50.1 Tcf of natural gas resource, an oil resource of 1.5 billion barrels was identified at
Tower
• The amount of natural gas and liquids ultimately recovered from ARC‟s NEBC Montney resource will be
primarily a function of the future price of both commodities
0% Porosity Cut- 3% Porosity Cut-
Natural Gas Resource Categories (1) (2) (3) (4) Off (Tcf) Off (Tcf)
Total Petroleum Initially In Place (TPIIP) 50.1 38.5
Discovered Petroleum Initially In Place (DPIIP) 27.2 22.3
Undiscovered Petroleum Initially In Place (UPIIP) 22.9 16.2
(1) TPIIP, DPIIP and UPIIP have been estimated using a zero percent porosity cut-off which means that all gas bearing rock has been incorporated into the
calculations.
(2) The Resource Categories do not include the free oil/liquids.
(3) All volumes in table are company gross and raw gas volumes.
(4) TPIIP and DPIIP include 0.7 Tcf of solution gas associated with Tower oil.
3% Porosity Cut- 6% Porosity Cut-
Oil Resource Categories (1) (2) (3) Off (mmbbls) Off (mmbbls)
Total Petroleum Initially In Place (TPIIP) 1,467.0 640.1
Discovered Petroleum Initially In Place (DPIIP) 1,467.0 640.1
(1) TPIIP and DPIIP have been estimated using a three percent porosity cut-off for oil due to lower mobility for oil relative to gas.
(2) All volumes in table are company gross.
(3) The oil DPIIP is a Stock Tank Barrel (“STB”).

18. MONTNEY GROWTH ASSETS
RESERVES AND RESOURCES
2012 Best 2011 Best
Reserves and Economic Contingent Resources (1)(2) Estimate Estimate
Natural Gas (Tcf)
Reserves (3) 2.1 1.9
Economic Contingent Resources 4.2 4.1
Natural Gas Liquids (mmbbls) (4)
Reserves (3) 24.7 21.1
Economic Contingent Resources 111.2 101.0
Oil (mmbbls)
Reserves (3) 7.6 0.1
Economic Contingent Resources 12.6 0.5
(1) All DPIIP other than cumulative production, reserves, and ECR has been categorized as unrecoverable.
(2) All volumes in table are company gross and sales volumes.
(3) For reserves, the volume under the heading Best Estimate are 2P reserves.
(4) The liquid yields are based on average yield over the producing life of the property.
2012 Best 2011 Best
Prospective Resources (1)(2) Estimate Estimate
Natural gas (Tcf) 3.8 4.0
Natural gas liquids (mmbbls) 113.6 98.0
(1) All UPIIP other than Prospective Resources has been categorized as unrecoverable. GLJ estimated DPIIP values using a porosity cut-off of three per cent for
natural gas and six per cent for oil.
(2) All volumes in table are company gross and sales volumes.

19. 2013 Budget

20. Total Company
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.

21. 2013 BUDGET
2013/2014 Production Growth
2013 Budget - Volumes (BOED)
All Properties
OPT DEV PO ACTUAL
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

22. Asset Overview

23. ASSET OVERVIEW
• ARC‟s key assets with the greatest value creation opportunities and highest
future reserves contributions are:
Montney Growth Assets
• Ante Creek – oil resource play
• Parkland/Tower– oil and liquids-rich gas resource play
• Dawson – natural gas resource play
• West Montney – liquids-rich and natural gas resource play
Base Assets
• Pembina Cardium – oil resource play
• Goodlands and SE Saskatchewan – oil resource play
• ARC plans to develop these opportunities, subject to a supportive commodity
price environment, over the next five years

24. ASSET OVERVIEW
WESTERN CANADA
Montney Growth Assets Base Assets
Blueberry •
Attachie •
• Tower
Septimus •
• Parkland
Sunset/Sunrise • • Dawson
Sundown •
• Ante Creek
• Redwater Natural Gas
• Pembina Liquids-rich gas
• Hatton Crude Oil
• Weyburn
• Jenner • Midale • Goodlands
Lougheed •

25. Ante A Montney
Oil Success Story
Creek

26. ANTE CREEK
ASSET DETAILS
Net production (boe/d) – Q4 2012 10,300
Liquids (bbls/d) 5,100
Gas (mmcf/d) 32
Production split % (liquids/gas) ~50/50
Land (Montney net sections) 267
Working Interest ~99%
10-07 Gas Plant
Reserves (2P mmboe) 47.7
Liquids (mmbbls) 20.9
Gas (bcf) 160
10-36 Gas Plant Reserve Life Index 11
2013 Plans
• Increase production to ~15,000 boe/d by end of 2013
as we “drill to fill” new gas plant
• Transition to pad drilling to minimize environmental
footprint and optimize operational efficiency

27. ANTE CREEK OIL – OPERATIONAL
EXCELLENCE
• INDUSTRY LEADINGand complete costs are <75% of industry average.
ARC‟s Ante Creek/Kaybob Montney drill CAPITAL EFFICIENCY
• ARC $3.8 MM per well vs. Industry $5.3 MM per well (1)
• ARC‟s Ante Creek average 30 day IP rate in the Ante Creek/Kaybob area is comparable to Industry
1,200
30 Day Average Daily IP Rate (boe/d)
1,000
800 ARC Gas
ARC Liquids
Others Gas
Others Liquids
600 ARC Average IP
~ 350 boe/d
400
200
0
(1) Source information from Well Completions & Frac Database – Canadian Discovery Ltd. and Introspec Energy Group Inc., wells rig released Jan 2011 to current.
(2) All reported wells from 60-20W5 to 69-26W5. Taken within first month of production, includes only those originally licensed to ARC and does not include wells acquired by ARC.
All wells have Oil IP3 > 0.

28. 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

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

30. British Montney Gas
and Liquids
Columbia

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 ~235
mmcf/d natural gas and 2,600 bbls/d
oil and liquids with Dawson
contributing approximately 165
mmcf/d
• New, 60 mmcf/d gas plant with 130
bbls/mmcf of liquids handling capacity
approved for Parkland/Tower. Site
clearing commenced and plant is
expected to be on-stream in early
2014.
• Ideally positioned with access to west
coast and other Alberta markets.

32. MONTNEY LANDS
SIGNIFICANT MONTNEY PRESENCE
• ARC has a significant presence in B.C. and Alberta Montney
• First to drill B.C. Montney horizontal well in 2005 at Dawson
BC Montney Hz Wells – Rig Released by BC Montney Gross Operated Raw Gas
B.C.Operator (since Jan - by Operator
Montney HZ Wells - Rig Released Wells 1, 2003) B.C. MontneyProductionGas Production (mmcfe/d)*
Gross Operated Raw (mmcfe/d)
450 400
Thousands
400 350
350
300
3Q2012 Production - mmcfe/d
300
250
250
200
200
150
150
100
100
50 50
0 0
ECA RDS MUR ARX TLM PRQ TOU CNQ CR CAN PPY PGF ECA RDS ARX MUR TLM PRQ TOU CNQ CR PPY PGF
CAN = Canbriam (Private)
Source: ITG IR, raw data provided by geoSCOUT Wells licensed since Jan. 1, 2003 Source: ITG IR, raw data provided by geoSCOUT * - i ncl udes wellhead condensate

33. MONTNEY HORIZONTAL WELLS
30 DAY HZ IP RATES GLACIER - TOWN
ARC’S MONTNEY WELLS HAVE EXCEEDED EXPECTATIONS
16,000
14,000
ARC
Others
12,000
10,000
Production Rate (mcf/d)
ARC Wells P50 = 5.2 Mmcf/d
8,000
Other Wells P50 = 3.4 Mmcf/d
6,000
4,000
2,000
0
(1) Graph represents peak calendar day IP rates for the first month of production to November 2012.
(2) Region includes all horizontal wells from NE BC and NW AB Montney.

34. Liquids
Parkland/Tow Rich Gas
er

35. PARKLAND/TOWER
EVALUATING POTENTIAL AND DEVELOPING
EXISTING LANDS
Parkland Tower
Net production Q4 2012 (boe/d) 7,600 1,200
Liquids (bbls/d) 940 770
Gas (mmcf/d) 40 2.5
Land (net sections) 23 56
Working Interest ~84% ~90%
Reserves (2P mmboe) 50.8 15.1
Liquids (mmbbls) 8.5 8.5
Gas (bcf) 254 39.7
Farm-in Lands
Reserve Life Index 18 24
2013 Plans
• 11 wells drilled at Tower in 2012, 14 wells drilled since late 2011
• Nine operated wells now tied-in at Tower, with restricted production rates as result of liquids handling facility
limitations
• First of two, eight well pads spud in Q4 2012; continue with pad drilling program in 2013
• Received regulatory approval to construct two 60 mmcf/d gas processing and liquids handling facilities. Site
clearing started late Dec 2012; expect to commission 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)

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)

39. TOWER
2012 ACCOMPLISHMENTS
Tower Production 2012 Accomplishments:
2,500
• 2012 Operated Program average 30
day IP rate: 375 boe/d per well
2,000
Gas (Forecast) • Production volumes limited due to
Liquids (Forecast) liquid handling restrictions
Gas
1,500 Liquids • First of two 8 well development
Sales (boe/d)
pads to be completed in 2013; spud
ARC purchased in late October 2012
1,000
the Tower
property in 2010 2013 Plans:
• 60 mmcf/d gas processing and
500
liquids handling facility expected
on-stream early 2014; site clearing
-
and pile driving commenced
2010 2011 2012 2013
• Continue with pad drilling program
in 2014 – expect „step‟ production
profile as all wells brought on at
one time (8 wells per pad)
(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
Production Rate (boe/d)
400 IRR (% AT) 41% 37%
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
DEV PO ACTUAL
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
0 • Significant capital being spent in 2013 with volumes coming on-stream in 2014.

43. World Class
Dawson
Asset

44. DAWSON
ASSET DETAILS
Net production (boe/d) –Q4 2012 28,800
Liquids (bbls/d) 800
Gas (mmcf/d) 168
45 mmcfd
Compressor Production split % (liquids/gas) ~97% gas
Station
120 mmcfd Land (Montney net sections) 130
Gas Plant
Working Interest ~96%
Reserves (2P mmboe) 181
Liquids (mmbbls) 5.2
Gas (bcf) 1,052
Reserve Life Index 17
2013 Plans
• Inventory of completed gas wells to be tied-in
during first half of 2013
• Drill 9 wells in 2013,maintain 2013 production flat
at 165 mmcf/d

45. 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

46. 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

47. DAWSON
2013 BUDGET – $52MM OPERATED
2013 Budget - Volumes (BOED)
Operated
PO ACTUAL
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

48. Long-term
WEST MONTNEY Opportunity
Growth

49. WEST MONTNEY
ASSET DETAILS
Net production (boe/d)- Q4 2012 3,760
Liquids (bbls/d) 90
Gas (mmcf/d) 22.0
Blueberry
Land (net Montney sections) 214
Working Interest ~90%
Attachie Reserves (2P mmboe) 131
Liquids (mmbbls) 11
Tower
Gas (bcf) 723
Septimus Parkland
Reserve Life Index 88
Sunset
Dawson
Sunrise
Sundown

50. WEST MONTNEY
OPERATIONAL EXCELLENCE – DEVELOPMENT
PLANNING

51. WEST MONTNEY
SUNRISE PRODUCTION – OUTPERFORMING
EXPECTATIONS
• Realized positive technical revisions in Sunrise based on 2-25 Hz well pad performance.
Estimated Ultimate Recovery (EUR) is Cumulative Production + 2P Reserves.
Montney A Sunrise A2-25 Hz MTYA (Raw)
Cum to Dec.31, 2012: 2.2 Bcf
ARC EUR Forecast: 11 – 14 Bcf
GLJ 2011 EUR: 7 Bcf
GLJ 2012 EUR: 10 Bcf
Montney B Sunrise B2-25 Hz
MTYB (Raw)
Cum to Dec. 31, 2012: 2.3 Bcf
ARC EUR Forecast: 10 – 13 Bcf
GLJ 2011 (2P) EUR: 6 Bcf
GLJ 2012 (2P) EUR: 10 Bcf

52. 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)

53. Base Significant cash
flow, stable
production
Assets

54. BASE ASSETS
Montney Growth Assets Base Assets
Natural Gas
• Redwater Crude Oil
• Pembina
• Hatton
• Weyburn
• Jenner • Midale • Goodlands
Lougheed •

55. Pembin Revitalizing a
Mature Oil Field
a

56. PEMBINA
ASSET DETAILS
Net production (boe/d) – Q4 2012 12,300
Cardium production ~82%
Production split % (liquids/gas) ~75%/25%
Land (Cardium net sections) 134
Working Interest ~79%
Reserves (2P mmboe) Cardium 49.4
Reserve Life Index 15
2013 Plans
• ARC is the second largest operator in the Pembina area
• Continued focus on long term value through prudent reservoir and waterflood management
• 11-31 Berrymoor plant expansion expected on stream May 2013
• Drill 52 Hz wells and two vertical injectors throughout the Pembina area (operated)

57. PEMBINA
OIL AND LIQUIDS GROWTH
ARC HAS GROWN LIQUIDS PRODUCTION IN THIS MATURE FIELD
Pembina ~33% Increase in Oil & Liquids Production since 2006
14,000
12,000
10,000
8,000
Boe/d
Q4 2012 - 9,200 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

58. PEMBINA OIL – OPERATIONAL
EXCELLENCE INDUSTRY LEADING
• ARC‟s average drill and complete costs are 80% of industry average
CAPITALMM per well vs. Industry $2.4 MM per well
• ARC $1.9
EFFICIENCY (1)
• ARC‟s Cardium well performance is comparable to industry peer average
450
Cardium Area IP Average (3 Month Rate)
400
350 ARC Others
300
250
IP3 (boe/d)
ARC Average Oil IP
200 ~ 137 bbls/d
150
100
50
-
(1) Source information from Well Completions & Frac Database – Canadian Discovery Ltd. and Introspec Energy Group Inc., wells rig released Jan 2011 to Nov 2012.
(2) IP3 data from Accumap - includes wells with greater than 750hrs, wells within TWP 47-49 RNG 5-10W5, on production after January 1, 2008.

60. PEMBINA
2013 BUDGET – $131MM
2013 Budget - Volumes (BOED)
Operated and Non-Operated
DEV PO ACTUAL
14,000
12,000
10,000
8,000
Base DeclineBase Decline ~23%
~23%
Base Decline ~23%
6,000
4,000
• Drill 52 gross operated Hz wells and 2 vertical injectors throughout the Pembina area.
2,000 • Grow operated production to >10,000 boed and total production to over ~12,000 boed.
• 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

61. SE SASKATCHEWAN Solid Long-life
OIL
Assets

62. SE SASKATCHEWAN / MANITOBA
OIL
ASSET DETAILS
Net production (boe/d) – Q4 2012 12,200 2013 Plans:
Production split 99% liquids • Continue to drill horizontally in a number of
properties that were previously only vertically
Land (net sections) 241 exploited.
Working Interest ~81% • Drilling 51 gross operated wells in 2013 with
significant focus at Goodlands in Manitoba.
Reserves (2P mmboe) 48.1
• Continued focus on long term value through
Reserves Life Index 11 prudent reservoir and waterflood management

64. Summary

65. 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 ~95,000 boe/d to date
• Grown P+P reserves from 47 mmboe to 607 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

66. 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
-

67. Appendix

68. 2013 BUDGET
($ millions) 2011 (Actual) 2012 (Actual) 2013 (Budget)
Development 396 408 563
Development – Facilities 92 73 162
Maintenance 21 23 35
Optimization 14 6 13
Exploration & Seismic 94 49 11
Enhanced Oil Recovery 20 21 27
Land 75 10 -
Other 14 18 19
Total Capital $726 $608 $830
(1) Other 2013 budgeted 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.

69. 2013 GUIDANCE
2012 Guidance 2012 Actual 2013 Guidance
Oil (bbls/d) 30,000 – 31,000 31,454 32,000 – 34,000
Condensate (bbls/d) 2,100 – 2,500 2,217 1,800 – 2,000
Gas (mmcf/d) 340 – 350 342.9 340 – 350
NGL‟s (bbls/d) 2,100 – 2,600 2,728 2,400 – 2,800
Total (boe/d) 91,000 – 94,000 93,546 93,000 – 97,000
Operating costs 9.50 – 9.70 9.40 9.50 – 9.70
Transportation costs 1.30 – 1.40 1.29 1.40 – 1.50
G&A expenses (1) 2.45 – 2.60 2.84 2.50 – 2.70
Interest 1.20 – 1.30 1.32 1.20 – 1.30
Income Taxes (2) 0.90 – 1.05 0.87 1.05 – 1.15
Capital expenditures (millions) (3) 600 830
608
Net property and undeveloped land
acquisitions ($ millions) (4) 25 - 50 32 -
Weighted average shares outstanding (millions) (5) 297 297 311
(1) The 2013 G&A expense before Long-Term Incentive Plan approximates $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.

70. ACCESS TO CAPITAL
DEBT
Debt raised from three different sources:
1. Bank Credit Facility - $1.0 billion plus $25 million overdraft facility, 12 banks under
facility
• Undrawn as at December 31, 2012
• Term extends to August 3, 2016
• Pre-approval for an additional $250 million (Accordion)
2. Long-term notes
• Private Placement market
• Currently have US$631 million and CDN$63 million drawn (Q4 2012)
3. Prudential Master Shelf
• Direct long-term relationship with major insurance company
• Currently have US$97 million drawn out of capacity of US$225 million (Q4 2012)
• Term extends to April 14, 2015

71. 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 $1.0 billion allows for significant flexibility to repay debt
Long-term Notes Principal Repayment Schedule
120
100
80
C$ Millions
60
40
20
0
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
2004 Series A 4.62% 2004 Series B 5.10% Pru MS Series C 5.42% 2009 Series C 7.19%
2009 Series D 8.21% Pru MS Series D 4.98% 2009 Series E 6.50% 2010 Series F 5.36%
2012 Series G 3.31% 2012 Series H 3.81% 2012 Series I 4.49%
Assumes USD/CAD exchange rate = $1.00

72. HEDGE POSITIONS
AS OF FEBRUARY 6, 2013
Summary of Hedge Positions as at February 6, 2013 (1)
2013 2014 2015 - 2017
Crude Oil – WTI (2):
(US$/bbl) US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d
Ceiling 104.01 14,992 100.00 2,479 - -
Floor 95.01 14,992 90.00 2,479 - -
Sold Floor 64.17 11,984 70.00 1,240 - -
Crude Oil Floors as % of Guidance (3) 43% 6% -
Natural Gas – Nymex (3):
(US$/mmbtu) US$/mmbtu mmbtu/d US$/mmbtu mmbtu/d US$/mmbtu mmbtu/d
Ceiling 3.95 168,767 $ 4.83 90,000 $ 5.00 60,000
Floor 3.41 168,767 $ 4.00 90,000 $ 4.00 60,000
Natural Gas Floors as % of Guidance (3) 49% 23% 15%
Total Floors as % of Guidance (3) 45% 16% 9%
(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 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 annual average WTI price or a six month average WTI price. In the case of settlements on annual and six month term positions, ARC will only have a negative settlement if prices
average above the strike price for an entire year or the six month period, respectively. These positions provide ARC with greater potential upside price participation for individual months.
(3) Based on 2013 guidance midpoint of 95,000 boe/d for 2013, and 2014 production estimate of 110,000 boe/d (60% natural gas, 40% crude oil and liquids) for 2014 through 2017 hedge
levels. Crude oil floors as a % of production are based on guidance volumes for crude oil and condensate production for the respective period.

73. 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.

74. 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. 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.
Forecast

75. 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