arc resources - february 2013 investor presentation

ARC Resources

Investor PresentationFebruary, 2013

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.

FORWARD LOOKING STATEMENTS

Production (2012 Annual) 93,500 boed

Liquids 36,400 boed

Natural gas 343 mmcfd

Reserves (2P Gross) 607 mmboe17.5 year RLI (1)

Current monthly dividend $0.10

Annualized total return 18% (2)

7.5% (3)

Enterprise value ~$8 billion (4)

Shares outstanding ~309 MM (5)

Daily average trading volume 1.1 million shares

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.

CORPORATE OVERVIEW

NE BC/ NW AB

NORTH AB

REDWATER

PEMBINA

S AB/SW SASK

SE SASK/MANITOBA

Crude Oil

Liquids-rich Gas

Dry Gas

2012 FINANCIAL AND OPERATIONAL PERFORMANCE

Three Months Ended December 31

Year Ended December 31

(CDN$ millions, except per share and per boe amounts) 2012 2011 2012 2011

Production (boe/d) Gas Liquids

95,72561%39%

92,02164%36%

93,54661%39%

83,41662%38%

Revenue Gas Liquids

374.2106.3267.9

385.9112.2273.7

1,386.8329.3

1,057.5

1,435.6434.0

1,001.6

Funds from operations Per share

208.40.68

226.60.79

719.82.42

844.32.95

Operating Income Per share

59.20.19

74.70.26

163.20.55

293.51.02

Dividends Per share

92.50.30

86.70.30

357.41.20

344.01.20

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

• 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

VALUE PROPOSITION

ForecastForecast

1998-01

1998-06

1998-11

1999-04

1999-09

2000-02

2000-07

2000-12

2001-05

2001-10

2002-03

2002-08

2003-01

2003-06

2003-11

2004-04

2004-09

2005-02

2005-07

2005-12

2006-05

2006-10

2007-03

2007-08

2008-01

2008-06

2008-11

2009-04

2009-09

2010-02

2010-07

2010-12

2011-05

2011-10

2012-03

2012-08

2013-01

2013-06

2013-11 -

20,000

40,000

60,000

80,000

100,000

Production Growth - Montney and Non-Montney

Montney Gas (boe/d)Montney Oil/Liquids (bbls/d)Non-Montney Gas (boe/d)Non-Montney Liquids (boe/d)

Prod

uctio

n (B

oe/d

)

Total Non-Montney production

Fo

reca

st

PRODUCTION GROWTH

Proved Undeveloped 20%

• 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

0

25,000

50,000

75,000

100,000

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Boe

/d

Production History

Gas

Liquids

15% CAGR*

* Compound annual growth rate

INCOME AND GROWTHARC HAS DELIVERED BOTH

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 20120%

100%

200%

300%

400%

500%

600%

700%

AcquisitionsDevelopment

• 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

200 PER CENT RESERVE REPLACEMENT 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

-

1.0

2.0

3.0

4.0

5.0

6.0

$-

$5.00

$10.00

$15.00

$20.00

$25.00

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Re

cycl

e R

atio

FD&A Costs and Recycle Ratio(1)

FD&A

F&D

Recycle Ratio

(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.

CAPITAL EFFICIENCYEXCELLENT FD&A PERFORMANCE IN 2012

• 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

SUSTAINABLE DIVIDEND$4.6 BILLION IN DIVIDENDS SINCE INCEPTION

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 $-

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

0%

20%

40%

60%

80%

100%

Cash Flow per Share Dividend per Share

Payout Ratio Payout Ratio including DRIP

$/sh

are

Pay

ou

t R

atio

%

Historic Dividends and Funds from Operations

• Focus on crude oil and liquids development resulted in 15% growth in crude oil and 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 Production

Q4 Revenue

34%

2%61%

3%

68%

5%

24%

3%

2012 Production

2012Revenue

Crude Oil

Condensate

NGL’s

Natural Gas

FOCUS ON OIL AND LIQUIDS15% OIL AND LIQUIDS PRODUCTION GROWTH IN 2012

Understand our Advantaged PositionM

ak

e t

ime

to

Th

ink

Str

ate

gic

all

yL

ev

era

ge

ou

r Ad

va

nta

ge

d P

os

ition

Be Dynamic and Flexible to Changing Conditions

RISKMANAGED

VALUECREATION

Operational Excellence

Financial Flexibility

Top Talent and Strong Leadership

Culture

High Quality,Long Life

Assets

OUR STRATEGYRISK MANAGED VALUE CREATION

• 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

STRATEGIC OVERVIEWSUMMARY

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.

MO

BIL>>

1996

1997

1998

ORIO

N>>19

99

AnteC

reek

>>20

00

STARTECH>>20

0120

02

STAR>>20

0320

04

NPCU/Red

water

>>20

0520

0620

0720

0820

09

STORM

>>20

1020

1120

12

0

100

200

300

400

500

600

700

Gas

Liquids

mm

bo

e

INTERNAL DEVELOPMENT MONTNEY

18% CAGR

• 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)

Crude oil

25%

Natural Gas69%

NGL's6%

2P Reserves

33%

25%

40%

Probable Proved Producing

Proved Undeveloped

Proved Non-Producing 2%

KEY RESERVE INFORMATION18% COMPOUND ANNUAL GROWTH

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.

NE B.C. MONTNEYVAST RESOURCE BASE

• 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

Natural Gas Resource Categories (1) (2) (3) (4)

0% Porosity Cut-Off (Tcf)

3% Porosity Cut-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

MONTNEY GROWTH ASSETSRESERVES AND RESOURCES

Oil Resource Categories (1) (2) (3)

3% Porosity Cut-Off (mmbbls)

6% Porosity Cut-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, 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.

(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”).

Reserves and Economic Contingent Resources (1)(2)

2012 Best Estimate

2011 Best Estimate

Natural Gas (Tcf) Reserves (3) 2.1 1.9Economic Contingent Resources 4.2 4.1Natural Gas Liquids (mmbbls) (4) Reserves (3) 24.7 21.1Economic Contingent Resources 111.2 101.0Oil (mmbbls) Reserves (3) 7.6 0.1Economic Contingent Resources 12.6 0.5

Prospective Resources (1)(2)

2012 Best Estimate

2011 Best Estimate

Natural gas (Tcf) 3.8 4.0Natural 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.

MONTNEY GROWTH ASSETSRESERVES AND RESOURCES

(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.

2013 Budget

NE BC - $324MM*~36 gross operated wells 42,099 boe/d~$100MM directed towards facilities at Parkland/TowerParkland/Tower, Dawson

NORTHERN AB - $211MM*~37 gross operated wells14,163 boe/d

2013 CAPITAL PROGRAMSETTING THE STAGE FOR 2014 PRODUCTION GROWTH

PEMBINA - $131MM*~54 gross operated wells9,220 boe/d

• $830 million capital program (~178 gross operated wells) with majority of spending in oil and liquids-rich gas plays and infrastructure.

REDWATER - $10MM*0 wells3,539 boe/d

SE AB/SW SASK - $6MM*0 wells6,214 boe/d

NE BC - $324MM(1)

~36 gross operated wells ~44,500 boe/d(2)

~$100MM directed towards facilities at Parkland/Tower

NORTHERN AB - $211MM(1)

~37 gross operated wells~15,000 boe/d(2)

PEMBINA - $131MM(1)


REDWATER - $10MM(1)

0 wells~3,600 boe/d(2)

S. AB/SW SASK - $6MM(1)

0 wells~7,900 boe/d(2)

SE SASK/MANITOBA - $126MM(1)


2013 Capital Budget

Capital $MM

Volumes Year

Average (boe/d)

Gross Wells

NetWells

Operated* 774 84,500 178 160

Non-Operated 56 10,600 103 10

Total 830 95,000 281 170

*Corporate $22 MM

(1) Includes Operated and Non-operated.(2) 2013 annual average production.

2013 BUDGET2013/2014 Production Growth

Base Decline ~22%

Base Decline ~22%

2013

-01

2013

-02

2013

-03

2013

-04

2013

-05

2013

-06

2013

-07

2013

-08

2013

-09

2013

-10

2013

-11

2013

-12

2014

-01

2014

-02

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2013 Budget - Volumes (BOED)All Properties

PO DEV OPT EXPLORE

2014 base production, does not show 2014 CAPEX program

• Overall Corporate base decline of ~ 22%.• Oil and Liquids production increases ~ 5%. • 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.

Base Decline ~22%

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

ASSET OVERVIEW

ASSET OVERVIEWWESTERN CANADA

• Tower• Parkland

• Dawson

Septimus •

Sunset/Sunrise •

Sundown •

Attachie •

• Ante Creek

• Jenner

• Redwater

• Pembina

• Hatton

• GoodlandsLougheed • • Midale• Weyburn

Natural Gas

Liquids-rich gas

Crude Oil

Montney Growth Assets Base Assets

Blueberry •

A MontneyOil Success StoryAnte

Creek

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%

Reserves (2P mmboe) 47.7

Liquids (mmbbls) 20.9

Gas (bcf) 160

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

10-36 Gas Plant

10-07 Gas Plant

0

200

400

600

800

1,000

1,200

30 Day Average Daily IP Rate (boe/d)

ARC GasARC LiquidsOthers GasOthers Liquids

(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.

ARC Average IP ~ 350 boe/d

• ARC’s Ante Creek/Kaybob Montney drill and complete costs are <75% of industry average.

• 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

ANTE CREEK OIL – OPERATIONAL EXCELLENCEINDUSTRY LEADING CAPITAL EFFICIENCY

0 6 12 18 24 30 360

50

100

150

200

250

300

350

400

450

Months

BO

E/D

Key Metrics

DCET Capex per well ($MM) 4.0

Reserves per well (Mboe) 283

IP (1 mo) (boe/d) 400

IP (12 mo) (boe/d) 245

Economics ($85/bbl) $4/GJ $3/GJ

IRR (% AT) 45% 35%

Recycle Ratio 2.1 2.0

• 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

ANTE CREEK MONTNEY DEVELOPMENT ECONOMICS

ANTE CREEK2013 BUDGET – $186MM OPERATED

2013

-01

2013

-02

2013

-03

2013

-04

2013

-05

2013

-06

2013

-07

2013

-08

2013

-09

2013

-10

2013

-11

2013

-12

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2013 Budget - Volumes (BOED)Operated

PO DEV OPT

• 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.

Base Decline ~28%

British Columbia

Montney Gasand Liquids

MONTNEY LANDSWORLD 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.

MONTNEY LANDSSIGNIFICANT 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

0

50

100

150

200

250

300

350

400

ECA RDS ARX MUR TLM PRQ TOU CNQ CR PPY PGF

3Q20

12 P

rodu

ctio

n -m

mcf

e/d

Thou

sand

s

B.C. Montney Gross Operated Raw Gas Production (mmcfe/d)*

Source: ITG IR, raw data provided by geoSCOUT * - includes wellhead condensate

0

50

100

150

200

250

300

350

400

450

ECA RDS MUR ARX TLM PRQ TOU CNQ CR CAN PPY PGF

B.C. Montney HZ Wells - Rig Released Wells - by Operator

Source: ITG IR, raw data provided by geoSCOUT CAN = Canbriam (Private)Wells licensed since Jan. 1, 2003

BC Montney Hz Wells – Rig Released by Operator (since Jan 1, 2003)

BC Montney Gross Operated Raw Gas Production (mmcfe/d)

(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.

MONTNEY HORIZONTAL WELLS30 DAY HZ IP RATES GLACIER - TOWN

ARC’S MONTNEY WELLS HAVE EXCEEDED EXPECTATIONS

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Pro

duction R

ate

(m

cf/d)

ARC

Others

Other Wells P50 = 3.4 Mmcf/d

ARC Wells P50 = 5.2 Mmcf/d

Liquids Rich Gas

Parkland/Tower

PARKLAND/TOWEREVALUATING POTENTIAL AND DEVELOPING EXISTING LANDS

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.

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

Reserve Life Index 18 24Farm-in Lands

• Producing Formation:Upper Montney Gross thickness 100mNet pay 90mPorosity 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)

PARKLAND LAYERED DEVELOPMENT

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

400 m

200 m

50 m

200 m

Upper #1 Upper #2

Lower Montney

Layered Well Placement

2/10/2011

2/24/2011

3/10/2011

3/24/2011

4/7/2011

4/21/2011

5/5/2011

5/19/2011

6/2/2011

6/16/2011

6/30/2011

7/14/2011

7/28/2011

8/11/2011

8/25/2011

9/8/2011

9/22/2011

10/6/2011

10/20/2011

11/3/2011

11/17/2011

12/1/2011

12/15/2011

12/29/2011

1/12/2012

1/26/2012

2/9/2012

2/23/2012

3/8/2012

3/22/2012

4/5/2012

4/19/2012

5/3/2012

5/17/2012

5/31/2012

6/14/2012

6/28/2012

7/12/2012

7/26/2012

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Upper MTY Well #1 (10 Stage) Upper MTY Well #2 (9 Stage) Lower MTY Well (9 Stage)

Rate

Mcf

d

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 360

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Months

Gas

Rat

e (M

cf/d

)

PARKLAND MONTNEY DEVELOPMENT ECONOMICS

• 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

Key Metrics


Reserves per well (Bcf) 5.8

IP (1 mo) (MMcf/d) 5.0

IP (12 mo) (MMcf/d) 4.0


IRR (% AT) 79% 54%


-

500

1,000

1,500

2,000

2,500

2010 2011 2012 2013

Sa

les

(b

oe

/d)

Tower Production

Gas (Forecast)

Liquids (Forecast)

Gas

Liquids

2012 Accomplishments:

• 2012 Operated Program average 30 day IP rate: 375 boe/d per well

• Production volumes limited due to liquid handling restrictions

• First of two 8 well development pads to be completed in 2013; spud in late October 2012

2013 Plans:

• 60 mmcf/d gas processing and liquids handling facility expected on-stream early 2014; site clearing and pile driving commenced

• Continue with pad drilling program in 2014 – expect ‘step’ production profile as all wells brought on at one time (8 wells per pad)

TOWER2012 ACCOMPLISHMENTS

(1) ARC purchased the Tower property in August 2010.

ARC purchased the Tower

property in 2010

• 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

TOWER OPERATIONAL EXCELLENCE - MINIMIZING FOOTPRINT

0 6 12 18 24 30 360

100

200

300

400

500

600

Months

Pro

du

ctio

n R

ate

(bo

e/d

)TOWERMONTNEY DEVELOPMENT ECONOMICS

Key Metrics



IP (1 mo) (boe/d) 500

IP (12 mo) (boe/d) 260


IRR (% AT) 41% 37%


• 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%

TOWER/PARKLAND2013 BUDGET – $249MM OPERATED

2014 base production, does not include 2014 CAPEX program

2013

-01

2013

-02

2013

-03

2013

-04

2013

-05

2013

-06

2013

-07

2013

-08

2013

-09

2013

-10

2013

-11

2013

-12

2014

-01

2014

-02

0

5,000

10,000

15,000

20,000

25,000


PO DEV OPT

Base Decline ~21%

• 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.

DawsonWorld Class Asset

DAWSONASSET DETAILS

Net production (boe/d) –Q4 2012 28,800

Liquids (bbls/d) 800

Gas (mmcf/d) 168

Production split % (liquids/gas) ~97% gas

Land (Montney net sections) 130


Reserves (2P mmboe) 181

Liquids (mmbbls) 5.2

Gas (bcf) 1,052


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 mmcfdCompressor Station

120 mmcfd Gas Plant

• 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

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 360

1,000

2,000

3,000

4,000

5,000

6,0002013 Type Curve

2012 Type Curve

2009-2011 Type Curve

2008 Type Curve

Months on Production

Gas R

ate

(Mcf

/d)

DAWSON TYPE CURVE GROWTH

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 360

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Months

Gas R

ate

(Mcf

/d)

Key Metrics




IP (12 mo) (MMcf/d) 4.8


IRR (% AT) 72% 44%


• 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

DAWSON MONTNEY DEVELOPMENT ECONOMICS

DAWSON2013 BUDGET – $52MM OPERATED

2013-

01

2013-

02

2013-

03

2013-

04

2013-

05

2013-

06

2013-

07

2013-

08

2013-

09

2013-

10

2013-

11

2013-

12

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000


PO DEV

• 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.

Base Decline ~28%

WEST MONTNEY Long-term Growth Opportunity

WEST MONTNEYASSET DETAILS

Net production (boe/d)- Q4 2012 3,760

Liquids (bbls/d) 90

Gas (mmcf/d) 22.0

Land (net Montney sections) 214


Reserves (2P mmboe) 131

Liquids (mmbbls) 11

Gas (bcf)

Reserve Life Index

723

88

Attachie

Tower

ParklandSeptimus

Sunset

Sunrise

Sundown

Dawson

Blueberry

WEST MONTNEYOPERATIONAL EXCELLENCE – DEVELOPMENT PLANNING

WEST MONTNEY SUNRISE PRODUCTION – OUTPERFORMING EXPECTATIONS

Montney A Sunrise A2-25 Hz

Montney B Sunrise B2-25 Hz

• Realized positive technical revisions in Sunrise based on 2-25 Hz well pad performance. Estimated Ultimate Recovery (EUR) is Cumulative Production + 2P Reserves.

MTYA (Raw)Cum to Dec.31, 2012: 2.2 BcfARC EUR Forecast: 11 – 14 BcfGLJ 2011 EUR: 7 BcfGLJ 2012 EUR: 10 Bcf

MTYB (Raw)Cum to Dec. 31, 2012: 2.3 BcfARC EUR Forecast: 10 – 13 BcfGLJ 2011 (2P) EUR: 6 BcfGLJ 2012 (2P) EUR: 10 Bcf

0 6 12 18 24 30 360

1,000

2,000

3,000

4,000

5,000

6,000

Months

Gas

Rat

e m

cf/d

SUNRISEMONTNEY SUNRISE DEVELOPMENT ECONOMICS

Key Metrics




IP (12 mo) (MMcf/d) 4.5


IRR (% AT) 51% 32%


• 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)

Significant cash flow, stable production

Base Assets

BASE ASSETS

Natural Gas

Crude Oil

• Jenner

• Redwater

• Pembina

• Hatton

• GoodlandsLougheed • • Midale• Weyburn

Montney Growth Assets Base Assets

Revitalizing aMature Oil FieldPembi

na

PEMBINAASSET DETAILS

Net production (boe/d) – Q4 2012 12,300

Cardium production ~82%

Production split % (liquids/gas) ~75%/25%

Land (Cardium net sections) 134


Reserves (2P mmboe) Cardium 49.4


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)

PEMBINAOIL AND LIQUIDS GROWTH

ARC HAS GROWN LIQUIDS PRODUCTION IN THIS MATURE FIELD

Fo

reca

st

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

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

Boe/

d

Pembina ~33% Increase in Oil & Liquids Production since 2006

gas

oil & liquids

Q1 2006 - 6,900 boe/doil and liquids

Q4 2012 - 9,200 boe/doil and liquids

• ARC’s average drill and complete costs are 80% of industry average

• ARC $1.9 MM per well vs. Industry $2.4 MM per well (1)

• ARC’s Cardium well performance is comparable to industry peer average

(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.

PEMBINA OIL – OPERATIONAL EXCELLENCE INDUSTRY LEADING CAPITAL EFFICIENCY

-

50

100

150

200

250

300

350

400

450

IP3

(boe

/d)

Cardium Area IP Average (3 Month Rate)

ARC Others

ARC Average Oil IP~ 137 bbls/d

0 6 12 18 24 30 360

2

4

6

8

10

12

Months On Production

Rat

e (b

oep

d)

Key Metrics



IP (1 mo) (boe/d) 227

IP (12 mo) (boe/d) 90


IRR (% AT) 52% 50%


• All economics run at FLAT price forecasts with C$85/bbl and $3/GJ AECO

PEMBINA CARDIUM DEVELOPMENT ECONOMICS

PEMBINA2013 BUDGET – $131MM

Base Decline ~23%Base Decline ~23%

2013

-01

2013

-02

2013

-03

2013

-04

2013

-05

2013

-06

2013

-07

2013

-08

2013

-09

2013

-10

2013

-11

2013

-12

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2013 Budget - Volumes (BOED)Operated and Non-Operated

PO DEV OPT

• Drill 52 gross operated Hz wells and 2 vertical injectors throughout the Pembina area.• 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.

Base Decline ~23%

SE SASKATCHEWAN OILSolid Long-life Assets

Net production (boe/d) – Q4 2012

12,200

Production split 99% liquids

Land (net sections) 241


Reserves (2P mmboe) 48.1

Reserves Life Index 11

SE SASKATCHEWAN / MANITOBA OILASSET DETAILS

2013 Plans:

• Continue to drill horizontally in a number of properties that were previously only vertically exploited.

• Drilling 51 gross operated wells in 2013 with significant focus at Goodlands in Manitoba.

• Continued focus on long term value through prudent reservoir and waterflood management

Key Metrics



IP (1 mo) (boe/d) 124

IP (12 mo) (boe/d) 72

Economics ($85/bbl) (gas not conserved)

IRR (% AT) 70%

Recycle Ratio 2.3

• All economics run at FLAT price forecasts with C$85/bbl

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 360

20

40

60

80

100

120

140

Months

Oil

Rat

e b

bl/

dGOODLANDS OILSPEARFISH DEVELOPMENT ECONOMICS

Summary

• 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

WHY INVEST IN ARC RESOURCES

ForecastForecast

1998-01

1998-06

1998-11

1999-04

1999-09

2000-02

2000-07

2000-12

2001-05

2001-10

2002-03

2002-08

2003-01

2003-06

2003-11

2004-04

2004-09

2005-02

2005-07

2005-12

2006-05

2006-10

2007-03

2007-08

2008-01

2008-06

2008-11

2009-04

2009-09

2010-02

2010-07

2010-12

2011-05

2011-10

2012-03

2012-08

2013-01

2013-06

2013-11 -

20,000

40,000

60,000

80,000

100,000

Production Growth - Montney and Non-Montney

Montney Gas (boe/d)Montney Oil/Liquids (bbls/d)Non-Montney Gas (boe/d)Non-Montney Liquids (boe/d)

Prod

uctio

n (B

oe/d

)

Total Non-Montney production

Fo

reca

st

PRODUCTION GROWTH

Appendix

2013 BUDGET

($ millions) 2011 (Actual) 2012 (Actual) 2013 (Budget)

DevelopmentDevelopment – Facilities

39692

40873

563162

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.

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)600 608 830

Net property and undeveloped land acquisitions ($ millions) (4) 25 - 50 32 -

Weighted average shares outstanding (millions) (5) 297 297 311

2013 GUIDANCE

(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.

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

ACCESS TO CAPITALDEBT

• 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

DEBT MATURITIESSPREAD OVER TIME

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20240

20,000,000

40,000,000

60,000,000

80,000,000

100,000,000

120,000,000Long-term Notes Principal Repayment Schedule

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

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%

HEDGE POSITIONSAS OF FEBRUARY 6, 2013

(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.

Forecast

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. 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.

DEFINITIONS OF OIL AND GASRESERVES AND RESOURCES

Forecast

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.

DEFINITIONS OF OIL AND GASRESERVES AND RESOURCES

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 RelationsE-mail: [email protected] 403.503.8600 F 403.509.6417Toll Free 1.888.272.4900ARC Resources Ltd.1200, 308 – 4 Avenue S.W.Calgary, AB T2P 0H7

http://www.sedar.com/

arc resources - february 2013 investor presentation

Documents