ARC Resources - December 2012 Investor Presentation

ARC Resources Investor Presentation December, 2012

This presentation contains forward-looking information as to ARC’s internal projections, expectations or beliefs relating to future events or

future performance and includes information as to our future well inventory in our core areas, our exploration and development drilling and

other exploitation plans for 2012 and beyond, and related production expectations, the volume of ARC's oil and gas reserves and the

volume of ARC's gas resources in the NE BC Montney (as defined herein), the recognition of additional reserves and the capital required

to do so, the life of ARC's reserves, the volume and product mix of ARC's oil and gas production, future results from operations and

operating metrics. These statements represent management’s expectations or beliefs concerning, among other things, future operating

results and various components thereof or the economic performance of ARC Resources. The projections, estimates and beliefs

contained in such forward-looking statements are based on management's assumptions relating to the production performance of ARC’s

oil and gas assets, the cost and competition for services, the continuation of ARC’s historical experience with expenses and production,

changes in the capital expenditure budgets, future commodity prices, continuing access to capital and the continuation of the current

regulatory and tax regime in Canada and necessarily involve known and unknown risks and uncertainties, such as changes in oil and gas

prices, infrastructure constraints in relation to the development of the Montney in British Columbia, risks associated with the degree of

certainty in resource assessments and including the business risks discussed in the annual MD&A and related to management’s

assumptions, which may cause actual performance and financial results in future periods to differ materially from any projections of future

performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or

circumstances could cause actual results to differ materially from those predicted. Other than the 2012 Guidance which is updated and

discussed quarterly, ARC does not undertake to update any forward looking information in this document whether as to new information,

future events or otherwise except as required by securities laws and regulations.

We have adopted the standard of 6 mcf:1 bbl when converting natural gas to barrels of oil equivalent ("boes"). Boes may be misleading,

particularly if used in isolation. A boe conversion ratio of 6 mcf per barrel is based on an energy equivalency conversion method primarily

applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current

price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the

6:1 conversion ratio may be misleading as an indication of value.

Contained in the “Strategy” section is forward-looking information. The reader is cautioned that assumptions used in the preparations of

such information, particularly those pertaining to dividends, production levels, operating costs and drilling results, although considered

reasonable by the Company at the time of preparation, may prove to be incorrect. A number of factors, including, but not limited to:

commodity prices, reservoir performance, weather, drilling performance and industry conditions, may cause the actual results achieved to

vary from projections, anticipated results or other information provided herein and the variations may be material. Consequently, there is

no representation by the Company that actual results achieved will be the same in whole or in part as those presented herein.

FORWARD LOOKING STATEMENTS

Production (2012 YTD) 92,800 boed

Liquids 36,000 boed

Natural gas 341 mmcfd

Reserves (2P Gross) 572 mmboe

17 year RLI (1)

Current monthly dividend $0.10

Annualized total return 18% (2)

13% (3)

Enterprise value ~$8 billion (4)

Shares outstanding ~308 MM (5)

Daily average trading volume 1.4 million shares

Net debt (millions) $691 (1.0 X cash flow)(5)

Member of S&P TSX 60 Index

(1) Based on 2012 production guidance of 91,000-94,000 boe/d.

(2) Annualized total return since inception to November 30, 2012, including November 2012 dividend, and assuming DRIP participation.

(3) Annualized total return November 30, 2007 (last 5 years).

(4) Market Capitalization as at November 30, 2012 and net debt as at September 30, 2012.

(5) As at September 30, 2012.

CORPORATE OVERVIEW

NE BC/ NW AB

NORTH AB

REDWATER

PEMBINA

S AB/

SW SASK

SE SASK/

MANITOBA

Crude Oil

Liquids-rich Gas

Dry Gas

• Oil and liquids comprised 40% of third quarter 2012 production while contributing 78% of

third quarter revenue

• Drilled 106 gross operated wells year-to-date (99% oil and liquids-rich)

• Grew crude oil and liquids production 16% to >35,600 boe/d in Q3 2012 (relative to Q3

2011) with significant growth at Ante Creek, Pembina and Goodlands

Q4 Production

Q4 Revenue

34%

3%

60%

3%

70%

6%

22%

2%

Q3 Production Q3 Revenue

Crude Oil

Condensate

NGL’s

Natural Gas

2012 FOCUS ON OIL AND LIQUIDS

• We believe that top performing companies all have the following attributes:

– Great assets

– Operational excellence

– Capital discipline

– Management that delivers results

• At ARC our focus since inception has been on

“Risk Managed Value Creation”

• It is not a question of growth or income but of how best to create value

for our owners

• Current dividend of $0.10 per month

VALUE PROPOSITION

Forecast Forecast -

20,000

40,000

60,000

80,000

100,000

Pro

du

ctio

n (

Bo

e/d

)

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)

Total Non-Montney production

Fo

recast

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 $4.5 billion in total dividends - $28.48/share

- Grown absolute production from 9,500 boe/d to ~93,000 boe/d, – the Montney provides

the opportunity for substantial future growth

- Grown debt and dividend adjusted reserves & production by ~ 10% annually

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

Q3

Bo

e/d

Production History

Gas Liquids

15% CAGR*

* Compound annual growth rate

INCOME AND GROWTH ARC HAS DELIVERED BOTH

Understand our Advantaged Position

Ma

ke

tim

e t

o T

hin

k S

tra

teg

ica

lly

Le

ve

ra

ge

ou

r A

dv

an

tag

ed

Po

sitio

n

Be Dynamic and Flexible to Changing Conditions

RISK

MANAGED

VALUE

CREATION

Operational

Excellence

Financial Flexibility

Top Talent and Strong Leadership

Culture

High Quality, Long Life

Assets

STRATEGY RISK 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 OVERVIEW SUMMARY

2013 Budget

and Guidance

2013 BUDGET STRATEGIC OBJECTIVES

The 2013 Budget will:

• Focus on oil and liquids opportunities

• Invest in high rate of return natural gas opportunities to sustain

current production

• Leverage dominant presence and technical expertise in resource

plays

• Invest in infrastructure to set stage for growth in 2014

• Optimize capital efficiencies through active cost management and

enhanced commercialization of development

• Manage production decline rates by pacing growth

• Preserve ARC’s strong financial position and balance sheet strength

NE BC - $324MM* ~36 gross operated wells

42,099 boe/d

~$100MM directed towards

facilities at Parkland/Tower

Parkland/Tower, Dawson

NORTHERN AB - $211MM* ~37 gross operated wells

14,163 boe/d

2013 CAPITAL PROGRAM SETTING THE STAGE FOR 2014 PRODUCTION GROWTH

PEMBINA - $131MM* ~54 gross operated wells

9,220 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 wells

3,539 boe/d

SE AB/SW SASK - $6MM*

0 wells

6,214 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)


~15,000 boe/d(2)

PEMBINA - $131MM(1)

~54 gross operated

wells

~11,000 boe/d(2)

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)


~12,600 boe/d(2)

2013 Capital Budget

Capital

$MM

Volumes

Year

Average

(boe/d)

Gross

Wells

Net

Wells

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 BUDGET 2013/2014 Production Growth

Base Decline ~22%

Base Decline ~22%

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%

2013 BUDGET FOCUS ON OIL AND LIQUIDS

~85% spending on oil and

liquids-rich gas

Focus: Parkland/Tower,

Dawson

NE BC/NW AB

SE SASK/ MB

PEMBINA

NORTHERN AB

~100% spending on oil

Focus: Goodlands


liquids-rich gas

Focus: Ante Creek


liquids-rich gas

Focus: Cardium

2013 Capital by

Commodity ($ millions)

2013 Drills by

Commodity

(# of Gross Operated Wells)

• 91% of budget focused on oil/liquids drilling and infrastructure

$581

$171

$56 $22

153

16 9

Oil

Liquids-rich

Gas

Other

2013 BUDGET

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

Development

Development – Facilities

396

92

400

70

563

162

Maintenance 21 27 35

Optimization 14 9 13

Exploration & Seismic 94 52 11

Enhanced Oil Recovery 20 21 27

Land 75 4 -

Other 14 17 19

Total Capital $726 $600 $830

(1) Other capital of $19 million comprises capitalized General and Administrative Expenses (“G&A”) including a portion of Long-Term Incentive Plan

(“LTIP” or the “Whole Unit Plan”) expense, information technology and corporate office capital.

2012 Guidance 2012 YTD Actual 2013 Guidance

Oil (bbls/d) 30,000 – 31,000 30,955 32,000 – 34,000

Condensate (bbls/d) 2,100 – 2,500 2,368 1,800 – 2,000

Gas (mmcf/d) 340 – 350 341 340 – 350

NGL’s (bbls/d) 2,100 – 2,600 2,644 2,400 – 2,800

Total (boe/d) 91,000 – 94,000 92,814 93,000 – 97,000

Operating costs 9.50 – 9.70 9.61 9.50 – 9.70

Transportation costs 1.30 – 1.40 1.30 1.40 – 1.50

G&A expenses (1) 2.45 – 2.60 2.78 2.50 – 2.70

Interest 1.20 – 1.30 1.33 1.20 – 1.30

Income Taxes (2) 0.90 – 1.05 1.03 1.05 – 1.15

Capital expenditures (millions) (3) 600 418 830

Land expenditures and minor net property

acquisitions ($ millions) (4) 25 - 50 31 -

Weighted average shares outstanding (millions) (5) 297 293 311

2013 GUIDANCE

(1) The 2013 G&A expense before Long-Term Incentive Plan approximates $90 million ($1.75 - $1.90 per boe).

(2) 2013 Corporate tax estimate will vary depending on level of commodity prices.

(3) The $830 million 2013 capital budget does not include land and net property acquisitions as this amount is unbudgeted.

(4) Based on weighted average shares plus the dilutive impact of share options outstanding during the period.

Asset Overview

• ARC’s key assets with the greatest value creation opportunities and

highest future reserves contributions are:

• Ante Creek – oil resource play

• Parkland/Tower/Attachie/Septimus – liquids-rich gas resource play

• Pembina Cardium – oil resource play

• Goodlands and SE Saskatchewan – oil resource play

• Dawson – natural gas resource play

• Sunrise/Sunset – natural gas resource play

• ARC plans to develop these opportunities, subject to a supportive

commodity price environment, over the next five years

• Highlights from a few of these key areas will be covered in this

presentation

ASSET OVERVIEW

Revitalizing a

Mature Oil Field Pembina

PEMBINA ASSET DETAILS

Net production (boe/d) – Q3 2012 11,300

Cardium production ~80%

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

Land (Cardium net sections) 132

Working Interest ~78%

Reserves (2P mmboe) Cardium 41.6

Reserve Life Index 14.2

2012 Plans/Accomplishments

• ARC is the second largest operator in the

Pembina area

• 29 Hz Cardium wells drilled year-to-date 2012

• Encouraging results on recent Buck Creek

horizontals

PEMBINA OIL AND LIQUIDS GROWTH

ARC HAS GROWN LIQUIDS PRODUCTION IN THIS MATURE FIELD

Fo

rec

as

t

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Q1

200

6

Q2

200

6

Q3

200

6

Q4

200

6

Q1

200

7

Q2

200

7

Q3

200

7

Q4

200

7

Q1

200

8

Q2

200

8

Q3

200

8

Q4

200

8

Q1

200

9

Q2

200

9

Q3

200

9

Q4

200

9

Q1

201

0

Q2

201

0

Q3

201

0

Q4

201

0

Q1

201

1

Q2

201

1

Q3

201

1

Q4

201

1

Q1

201

2

Q2

201

2

Q3

201

2

Q4

201

2

Bo

e/d

Pembina ~19% Increase in Oil & Liquids Production since 2006

gas

oil & liquids

Q1 2006 - 6,900 boe/doil and liquids

Q3 2012 - 8,200 boe/doil and liquids

0

50

100

150

200

250

0 6 12 18 24 30 36

Rate

(b

oep

d)

Months On Production

Key Metrics

DCET Capex per well ($MM) 2.3

Reserves per well (Mboe) 171

IP (1 mo) (boe/d) 227

IP (12 mo) (boe/d) 90

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

IRR (% AT) 52% 50%

Recycle Ratio 3.9 3.8

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

PEMBINA CARDIUM DEVELOPMENT ECONOMICS

PEMBINA 2013 BUDGET – $131MM

Base Decline ~23% Base Decline ~23%

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 54 gross operated wells 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%

A Montney

Oil Success Story Ante Creek

ANTE CREEK ASSET DETAILS


Liquids (bbls/d) 5,400

Gas (mmcf/d) 31

Production split % (liquids/gas) ~50/50

Land (Montney net sections) 263


Reserves (2P mmboe) 47.2

Liquids (mmbbls) 20.2

Gas (bcf) 162



• 30 mmcf/d gas plant commissioned in late February,

alleviating capacity constraints

• Growth in oil and liquids production in 2012

• Production to increase through 2013 as we “drill to fill”

new gas plant

• 30 mmcf/d gas plant commissioned in

late February, alleviating capacity

constraints

• Growth in oil and liquids production

in 2012

• Production to increase through 2013

as we “drill to fill” new gas plant

• Drill 21 Hz wells by year-end 2012

• Successful delineation step out

locations to extend pool boundaries

• Added 12 sections of land year-to-date

through Crown land sales and asset

acquisitions

• Transition to pad drilling to minimize

environmental footprint and optimize

operational efficiency

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2008 2009 2010 2011 2012 2013

Sale

s (

bo

e/d

)

Ante Creek Production

Liquids (F) Gas (F) Liquids Gas

ANTE CREEK 2012 ACCOMPLISHMENTS

0

50

100

150

200

250

300

350

400

450

0 6 12 18 24 30 36

BO

E/D

Months

Key Metrics



IP (1 mo) (boe/d) 400

IP (12 mo) (boe/d) 245


IRR (% AT) 45% 35%


• 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 CREEK 2013 BUDGET – $186MM OPERATED

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 Gas

and Liquids

We engaged GLJ to provide a resources evaluation of our properties at Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown and

Blueberry located in northeastern British Columbia and at Pouce Coupe located in northwestern Alberta (collectively, the "Evaluated Areas" or "NE BC

Montney"). The evaluation procedures employed by GLJ are in compliance with standards contained in the Canadian Oil and Gas Evaluation Handbook

("COGE Handbook") and the evaluation is based on GLJ's January 1, 2012 pricing

The estimates of Economic Contingent Resources (or ECR), DPIIP, TPIIP, UPIIP and Prospective Resources should not be confused with reserves and

readers should review the definitions and notes set forth at the end of this presentation. Actual natural gas resources may be greater than or less than

the estimates provided herein.

There is no certainty that it will be commercially viable to produce any of the resources that are categorized as discovered resources. There is no

certainty that any portion of ARC's resources that have been categorized as undiscovered resources will be discovered. Furthermore, if discovered, there

is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. Unless indicated otherwise in this presentation,

all references to ECR volumes are Best Estimate ECR volumes.

Continuous development through multi-year exploration and development programs and significant levels of future capital expenditures are required in

order for additional resources to be recovered in the future. The principal risks that would inhibit the recovery of additional reserves relate to the potential

for variations in the quality of the Montney formation where minimal well data currently exists, access to the capital which would be required to develop

the resources, low gas prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the

required services at the appropriate cost, and the effectiveness of fraccing technology and applications. The contingencies that prevent the ECR from

being classified as reserves are due to the early evaluation stage of these potential development opportunities. Additional drilling, completion, and test

results are required before these contingent resources are converted to reserves and a larger component of DPIIP is converted to ECR.

Projects have not been defined to develop the resources in the Evaluated Areas as at the evaluation date. Such projects, in the case of the Montney

resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints,

ARC's policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of ARC on gas

prices, the results of exploration and development activities of ARC and others in the area and possible infrastructure capacity constraints.

See “Definitions of Oil and Gas Reserves and Resources” in this presentation.

NE B.C. MONTNEY VAST RESOURCE BASE

MONTNEY LANDS WORLD CLASS RESOURCE

• NE BC Montney lands are a major

growth engine.

• Significant opportunity to grow

liquids production.

• Total BC Montney production of 240

mmcf/d with Dawson contributing

approximately 160 mmcf/d.

• New, 60 mmcf/d gas plant with 130

bbls/mmcf of liquids handling

capacity planned for Parkland/Tower

in early 2014.

• Ideally positioned with access to

west coast and other Alberta

markets.

• Very early stage in reserve booking cycle:

• 2P Reserves (1.9 Tcf) plus Cum Prod only 5.3% of TPIIP at 3%

cut-off (4.2% at 0% cut-off).

• Best Estimate ECR estimated to be 4.1 Tcf resulting in total

recovery including 2P reserves and Cum Prod to date of only

15.7% of TPIIP at 3% cut-off (12.3% at 0% cut-off).

• ARC estimates the 2P Reserves plus ECR (6.0 Tcf) can support a

peak production rate of 800 mmcf/d for 10 years.

• Estimated Prospective Resources of 4.0 Tcf (“Best Estimate”) results

in a total potential recovery factor of ~20% - 25% of the TPIIP.

Recovery factors at that level could support a peak production rate of

>1.3 Bcf/d for 10 years.

NE B.C. MONTNEY RESERVES AND RESOURCES

ARC’S MONTNEY GAS WELLS HAVE THE BEST INITIAL PRODUCTIVITY

Source information: Accumap - NEBC NWAB Montney horizontals peak month IP July 2012.

NE BC/NW AB Montney Gas Wells - P50 Peak Calendar Month Daily IP

MONTNEY GROWTH ASSETS EXCEEDING EXPECTATIONS

Liquids

Rich Gas Parkland/Tower

PARKLAND/TOWER EVALUATING POTENTIAL AND DEVELOPING

EXISTING LANDS


• 11 wells drilled at Tower since late 2011

• 8 wells now tied-in at Tower, with restricted production rates as result of liquids handling facility limitations

• Application submitted to construct two 60 mmcf/d gas plants with 130 bbls/mmcf liquids handling capacity.

Pending approval, will commence construction in 2013 with commissioning of the first phase in early 2014.

Parkland Tower

Net production (boe/d) 7,200 800

Liquids (bbls/d) 930 500

Gas (mmcf/d) 39 1.7

Land (net sections) 23 56

Working Interest ~84% ~90%

Reserves (2P mmboe) 49.7 4.5

Liquids (mmbbls) 8.4 1.4

Gas (bcf) 247.0 19.2

Reserve Life Index 16 37 Parkland

Tower

• Producing Formation:

Upper Montney

Gross thickness 100m

Net pay 90m

Porosity 6%

Permeability 0.01 to 0.1 mD

• Large DGIP volumes in Parkland, currently have

modest recoveries per well

• 100 Bcf DGIP per section, ~100 meters of pay

• EUR/well typically ~ 5 Bcf (20% Recovery factor)

• Recovery factor low relative to developed areas

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

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Rat

e M

cfd

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

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

0 6 12 18 24 30 36

Gas R

ate

(M

cf/

d)

Months

PARKLAND MONTNEY DEVELOPMENT ECONOMICS


• 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%


• Drilled 8 Hz wells Q3 YTD

• 2012 Operated Program average

30 day IP rate: 375 boe/d per well

• Production volumes limited due to

liquid handling restrictions

• Granted a Royalty Infrastructure

Credit Grant for gathering system

• BC OGC reclassified all Tower

producing wells and upcoming well

licenses to oil wells

• Gas plant application submitted to

regulatory body OGC for

120 mmcfd gas plant and

liquids handling facility

TOWER 2012 ACCOMPLISHMENTS

-

500

1,000

1,500

2,000

2,500

-

500

1,000

1,500

2,000

2,500

2010 2011 2012 2013

Sale

s (

bo

e/d

)

Tower Production


(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

100

200

300

400

500

600

0 6 12 18 24 30 36

Pro

du

cti

on

Rate

(b

oe/d

)

Months

TOWER MONTNEY DEVELOPMENT ECONOMICS

Key Metrics



IP (1 mo) (boe/d) 500

IP (12 mo) (boe/d) 260


IRR (% AT) 41% 37%



• Difference between EDM and quality & transport adjustments = +4.25 $/bbl

• Liquid yield assumptions – 79.2 bbl/MMcf, shrinkage = 20.6%

TOWER/PARKLAND 2013 BUDGET – $249MM OPERATED

2014 base

production, does not include 2014 CAPEX program

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.

Dawson

World Class

Asset

DAWSON ASSET DETAILS

Net production (boe/d) – YTD 2012 25,300

Liquids (bbls/d) 700

Gas (mmcf/d) 160

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

Land (Montney net sections) 130


Reserves (2P mmboe) 174

Liquids (mmbbls) 5.0

Gas (bcf) 1,012



• Inventory of completed gas wells to be tied-in

throughout remainder of 2012 and into 2013

• Maintain 2012 production flat at 165 mmcf/d

120 mmcf/d

Gas Plant

45 mmcf/d

Compressor

Station

• Reserve growth from 2008 – 2010 due to PUD assignment driven by repeated success

of our drilling program and improved well confidence

• Reserve growth from 2011 driven by modest PUD adds and overall improved

performance expectations from individual wells

• Higher confidence in production performance and repeatability is evident on assigned

EUR/well and field recovery factor

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

2008 2009 2010 2011

Field Recovery Factor

Assigned EUR/Well (Bcf)

DAWSON RESERVE 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

0

1,000

2,000

3,000

4,000

5,000

6,000

0 3 6 9 12 15 18 21 24 27 30 33 36

Gas

Rat

e (

Mcf

/d)

Months on Production

2013 Type Curve

2012 Type Curve

2009-2011 Type Curve

2008 Type Curve

DAWSON TYPE CURVE GROWTH

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

0 6 12 18 24 30 36

Gas

Rat

e (

Mcf

/d)

Months

Key Metrics




IP (12 mo) (MMcf/d) 4.8


IRR (% AT) 72% 44%



• Liquid yield assumptions – 3.1bbl/mmcf C5, 0.7bbl/mmcf C4, 0.4bbl/mmcf C3

DAWSON MONTNEY DEVELOPMENT ECONOMICS

DAWSON 2013 BUDGET – $52MM OPERATED

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 MONTNEY ASSET DETAILS

Net production (boe/d)- Q3 2012 3,450

Liquids (bbls/d) 30

Gas (mmcf/d) 20.5

Land (net Montney sections) 211



Liquids (mmbbls) 7

Gas (bcf) 628

Year # Hz Wells Drilled

2009 4 non-op

2010 4 operated

1 non-op

2011 5 operated

2012 Estimate 2 operated

1 non-op

2013 Budget 2 operated

WEST MONTNEY OPERATIONAL EXCELLENCE – DEVELOPMENT PLANNING

WEST MONTNEY SUNRISE PRODUCTION – OUTPERFORMING EXPECTATIONS

Montney A Sunrise A2-25 Hz

Montney B Sunrise B2-25 Hz

• Expect positive technical revisions in Sunrise based on 2-25 Hz well pad performance

Cum to date: 2 Bcf

EUR Forecast: 11 – 14 Bcf

GLJ 2011 (2P) EUR: 7 Bcf

Cum to date: 2 Bcf

EUR Forecast: 10 – 13 Bcf

GLJ 2011 (2P) EUR: 6 Bcf

0

1,000

2,000

3,000

4,000

5,000

6,000

0 6 12 18 24 30 36

Ga

s R

ate

mc

f/d

Months

SUNRISE MONTNEY 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)

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 ~93,000 boe/d to date

• Grown P+P reserves from 47 mmboe to 572 mmboe to date

• Progressive approach of applying new technologies to “unlock” value

• Proven track record of “Operational Excellence” in both cost management and safety

• Solid balance sheet with protective hedging program

• Experienced management team with track record of delivering results

WHY INVEST IN ARC RESOURCES

Forecast Forecast -

20,000

40,000

60,000

80,000

100,000

Pro

du

ctio

n (

Bo

e/d

)

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)

Total Non-Montney production

Fo

recast

PRODUCTION GROWTH

Appendix

2012 FINANCIAL AND

OPERATIONAL PERFORMANCE

Q3 2012 YTD Q3 2012

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

Production (boe/d)

Gas

Liquids

89,511

60%

40%

85,178

64%

36%

92,814

61%

39%

80,517

61%

39%

Revenue

Gas

Liquids

329.4

72.9

256.5

351.3

116.9

234.4

1,012.6

223.0

789.6

1,049.7

321.8

727.9

Funds from operations

Per share

164.9

0.55

213.5

0.74

511.4

1.74

617.6

2.15

Operating Income

Per share

26.6

0.09

68.0

0.24

104.1

0.35

217.4

0.76

Dividends

Per share

90.6

0.30

86.2

0.30

264.9

0.90

257.5

0.90

Capital expenditures 133.1 229.3 417.8 531.0

Net debt outstanding 691.0 870.1 691.0 870.1

Weighted average number of shares outstanding

(millions) 299.7 287.1 293.4 286.0

Netback (pre-hedging) 23.04 26.62 23.25 29.77

Debt raised from three different sources:

1. Bank Credit Facility - $1.9 billion plus $25 million overdraft facility, 12 banks under

facility

• $nil drawn under credit facility as at September 30, 2012

• The credit facility was extended to August 3, 2016

• Pre-approval for an additional $250 million (Accordion)

2. Long-term notes

• Private Placement market

• Currently have US$631MM and CDN$63MM drawn (Q3 2012)

3. Prudential Master Shelf

• Direct long-term relationship with major insurance company

• Currently have US$106.3 MM drawn out of capacity of US$225MM (Q3 2012)

• Term extended to April 14, 2015

ACCESS TO CAPITAL DEBT

• ARC’s long-term notes are structured so that they mature over a number of years; this

reduces refinancing risk

• ARC’s undrawn credit facility of $1.2 billion (after debt and equity proceeds) allows for

significant flexibility to repay debt

DEBT MATURITIES SPREAD OVER TIME

0

20

40

60

80

100

120

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

C$

Mill

ion

s

Long-term Principal Note Repayment Schedule

Summary of Hedge Positions as at November 7, 2012 (1)

Nov – Dec 2012 2013 2014 2015 - 2017

Crude Oil – WTI (2):

(US$/bbl) US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d

Ceiling $ 91.11 18,000 $ 104.01 14,992 - - - -

Floor $ 90.00 18,000 $ 95.01 14,992 - - - -

Sold Floor $ 63.44 16,000 $ 64.17 11,984 - - - -

Crude Oil Floors as % of 2012

Guidance (3) 55% 43% -

Natural Gas – Nymex (3): US$/mmbtu mmbtu/d US$/mmbtu mmbtu/d US$/mmbtu mmbtu/d US$/mmbtu mmbtu/d

Ceiling

$ 3.48

175,000 3.93 157,041 $ 4.83 90,000 $ 5.00 60,000

Floor

$ 3.48

175,000 3.39 157,041 $ 4.00 90,000 $ 4.00 60,000

Natural Gas Floors as % of 2012

Guidance (3) 50% 46% 26% 17%

Total Floors as % of 2012 Guidance (3) 51% 43% 16% 11%

HEDGE POSITIONS AS OF NOVEMBER 7, 2012

(1) The prices and volumes noted above represent averages for several contracts representing different periods and the average price for the portfolio of options listed above does not

have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes.

(2) For 2012 and 2013, all floor positions settle against the monthly average WTI price, providing protection against monthly volatility. Positions establishing the “Ceiling” have been sold

against either the monthly average or the annual average WTI price. In the case of settlements on annual positions, ARC will only have a negative settlement if prices average

above the strike price for an entire year, providing ARC with greater potential upside price participation for individual months.

(3) Based on 2012 guidance of 92,500 boe/d for 2012 hedge positions and based on 2013 guidance midpoint of 95,000 boe/d for 2013, 2014 and 2015-2017 hedge positions. Crude

oil floors as a % of production are based on guidance volumes for crude oil and condensate production for the respective period.

The discussion in this presentation in respect of reserves and resources is subject to a number of cautionary statements,

assumptions and risks as set forth below and elsewhere in this presentation. See also the definitions of oil and gas reserves

and resources found at the end of this presentation.

The reserves data set forth in this presentation is based upon an evaluation by GLJ Petroleum Consultants Ltd. ("GLJ") with

an effective date of December 31, 2011 using forecast prices and costs. The reserves evaluation was prepared in

accordance with National Instrument 51-101 ("NI 51-101"). Crude oil, natural gas and natural gas liquids benchmark

reference pricing, as at December 31, 2011, inflation and exchange rates used in the evaluation are based on GLJ's

January 1, 2012 pricing. Reserves included herein are stated on a company gross basis (working interest before deduction

of royalties without including any royalty interests) unless noted otherwise.

There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The

recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only

and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid

reserves may be greater than or less than the estimates provided herein.

See also ”NE B.C. Montney Vast Resource Base”, for further discussion regarding reserves and resources.

See “Definitions of Oil and Gas Reserves and Resources” in this presentation.

RESERVES AND RESOURCES

0

100

200

300

400

500

600

700

mm

bo

e

Gas

Liquids

INTERNAL DEVELOPMENT

MONTNEY

19% CAGR

• Reserves as of December 31, 2011* (mmboe)

- Proved Producing 209 (98 mmboe liquids, 655 bcf gas)

- Total Proved 360 (123 mmboe liquids, 1,419 bcf gas)

- Proved Plus Probable 572 (170 mmboe liquids, 2,413 bcf gas)

Crude

oil24%

Natural Gas70%

NGL's6%

2P Reserves

36%

25%

37%

Probable Proved

Producing

Proved

Undeveloped

Proved

Non-Producing 2%

KEY RESERVE INFORMATION 19% COMPOUND ANNUAL GROWTH

0%

100%

200%

300%

400%

500%

600%

700%

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

Acquisitions

Development

• Fourth consecutive year of greater than 200% reserve replacement through the drill bit

• Proved plus probable reserves increased 18% to 572 mmboe after divest of non-core assets with 14.6 mmboe of 2P reserves

385 PER CENT RESERVE REPLACEMENT IN 2011

Reserves and Economic Contingent Resources (3)(7)(8) Best Estimate

Natural Gas (Tcf)

Reserves (4) 1.9

Economic Contingent Resources 4.1

Natural Gas Liquids (mmbbls) (6)

Reserves 21.1

Economic Contingent Resources 101.0

Prospective Resources (3)(8) Best Estimate

Natural gas (Tcf) 4.0

Natural gas liquids (mmbbls) (6) 98.0

1) The resource categories do not include free liquids or associated solution gas in the Tower field.

2) All volumes in table are company gross and raw gas volumes.

3) All DPIIP other than cumulative production, reserves, and ECR and all UPIIP other than Prospective Resources has been categorized as unrecoverable.

4) For reserves, the volume under the heading Low Estimate are proved reserves, the volume under the heading Best Estimate are 2P reserves and the number under the heading High Estimate are 2P plus possible reserves.

5) This volume is an arithmetic sum of multiple estimates of reserves, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of

individual classes of reserves and appreciate the differing probabilities associated with each class.

6) The liquid yields are based on average yield over the producing life of the property.

7) Cumulative production has been 0.2 Tcf on a raw basis.

8) All volumes in table are company gross and sales volumes.

• Independent Resources Evaluation conducted by GLJ effective December 31, 2011

• The amount of natural gas and NGLs which is ultimately recovered from ARC’s NEBC Montney

resource will be primarily a function of the future price of both commodities

Resource Categories (1) (2)

3% Porosity Cut-

Off (Tcf)

0% Porosity

Cut-Off (Tcf)

Total Petroleum Initially In Place (TPIIP) 39.6 50.4

Discovered Petroleum Initially In Place (DPIIP) 21.2 25.5

Undiscovered Petroleum Initially In Place (UPIIP) 18.4 24.9

MONTNEY GROWTH ASSETS RESERVES AND RESOURCES

(1) Graph represents peak calendar day IP rates for the first month of production to July 2012.

(2) Region includes all horizontal wells from NE BC and NW AB Montney.

MONTNEY HORIZONTAL WELLS 30 DAY HZ IP RATES GLACIER - TOWN

ARC’S DAWSON/PARKLAND WELLS HAVE EXCEEDED EXPECTATIONS

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

1 101 201 301 401 501 601 701 801 901 1001

Pro

du

cti

on

Ra

te (

mc

f/d

)

ARC Others

Other Wells P50

3.3 Mmcf/d

ARC P50

5.2 Mmcf/d

SE SASKATCHEWAN OIL Solid Long-life

Assets


Production split 99% liquids

Land (net sections) 232



T1

T2

T3

T4

T5

T6

T7

T8

T9

T10

T11

T12

T13

T14

T1

T2

T3

T4

T5

T6

T7

T8

T9

T10

T11

T12

T13

T14

R22W1R23R24R25R26R27R28R29R30R31R32R33R34R1W2R2R3R4R5R6R7R8R9R10R11R12R13R14R15R16R17R18R19R20R21R22R23R24R25R26R27R28

File: IR Annual Presentation SESKMB. Datum: NAD27 Projection: Stereographic Center: N49.54139 W103.04696 Created in AccuMap™, a product of IHS

North

Landscape

Elmore

Radville

Lougheed Midale

Oungre

Bromhead

Parkman

Browning

Weir Hill

Glen Ewen

Year # Hz Wells

Drilled

2009 11

2010 17

2011 21

2012 Estimate 35

2013 Budget 29

SE SASKATCHEWAN OIL ASSET DETAILS

• Increased total production in area

by 11% to 9,300 boe/d, relative to

Q3 2011

• Drilled 29 wells to the end of Q3 and

plan to drill 35 wells to year-end

• Continued to drill horizontally in a

number of properties that were

previously only vertically exploited

• Facility upgrades continue to be a

priority to support development

volumes

• Continued work on waterfloods in

Lougheed, Oungre, Skinner Lake

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2008 2009 2010 2011 2012 2013

Sale

s (

bo

e/d

)

SE SK Production


SE SASKATCHEWAN OIL 2012 ACCOMPLISHMENTS

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 GAS


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 as follows:

Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual

remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent

probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the

actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be

at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best

estimate.

High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the

actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10

percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

DEFINITIONS OF OIL AND GAS


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: [email protected] 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

http://www.sedar.com/