2. FORWARD LOOKING STATEMENTS
This presentation contains forward-looking information as to ARC’s internal projections, expectations or beliefs relating to
future events or future performance and includes information as to our future well inventory in our core areas, our exploration
and development drilling and other exploitation plans for 2012 and beyond, and related production expectations, the volume of
ARC's oil and gas reserves and the volume of ARC's gas resources in the NE BC Montney (as defined herein), the recognition
of additional reserves and the capital required to do so, the life of ARC's reserves, the volume and product mix of ARC's oil
and gas production, future results from operations and operating metrics. These statements represent management’s
expectations or beliefs concerning, among other things, future operating results and various components thereof or the
economic performance of ARC Resources. The projections, estimates and beliefs contained in such forward-looking
statements are based on management's assumptions relating to the production performance of ARC’s oil and gas assets, the
cost and competition for services, the continuation of ARC’s historical experience with expenses and production, changes in
the capital expenditure budgets, future commodity prices, continuing access to capital and the continuation of the current
regulatory and tax regime in Canada and necessarily involve known and unknown risks and uncertainties, such as changes in
oil and gas prices, infrastructure constraints in relation to the development of the Montney in British Columbia, risks associated
with the degree of certainty in resource assessments and including the business risks discussed in the annual MD&A and
related to management’s assumptions, which may cause actual performance and financial results in future periods to differ
materially from any projections of future performance or results expressed or implied by such forward-looking statements.
Accordingly, readers are cautioned that events or circumstances could cause actual results to differ materially from those
predicted. Other than the 2012 Guidance which is updated and discussed quarterly, ARC does not undertake to update any
forward looking information in this document whether as to new information, future events or otherwise except as required by
securities laws and regulations.
We have adopted the standard of 6 mcf:1 bbl when converting natural gas to barrels of oil equivalent ("boes"). Boes may be
misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf per barrel is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given
that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy
equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.
3. CORPORATE OVERVIEW
Production (Q2 2012) 93,997 boed
Liquids 36,125 boed
Natural gas 347 mmcfd
Crude Oil
Reserves (2P Gross) 572 mmboe NE BC/ NW AB
Liquids-rich Gas
17 year RLI (1) Dry Gas
NORTH AB
Current monthly dividend $0.10
Annualized total return 18% (2) REDWATER
10% (3)
Enterprise value ~$8 billion (4) PEMBINA
Shares outstanding ~307 MM (5) SE SASK/
MANITOBA
Daily average trading volume 1.5 million shares S AB/
SW SASK
Net debt (millions) $665 (0.8 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 September 30, 2012, including September 2012 dividend, and assuming DRIP participation.
(3) Annualized total return since September 30, 2007 (last 5 years).
(4) Market Capitalization as at September 30, 2012 and net debt as at June 30, 2012 adjusted for August 22 equity offering.
(5) As at June 30, 2012, after giving effect to August 22 equity offering and based on trailing 12 month funds from operations.
4. 2012 CAPITAL PROGRAM
FOCUSED ON OIL AND LIQUIDS
• $600 million capital program (~150 gross operated wells) with majority of spending
in oil and liquids-rich gas plays
NE BC - $155MM
~10 gross operated wells
NORTHERN AB - $165MM
~90% oil & liquid-rich gas
~30 gross operated wells
Parkland/Tower, Attachie
~100% oil & liquid-rich gas
Ante Creek, Swan Hills, Prestville
PEMBINA - $90MM
~40 gross operated wells
~90% oil
Cardium
SE SASK/MANITOBA - $100MM
~60 gross operated wells
100% oil
Goodlands, Midale
(1) The $600 million capital program includes ~$80 million of non-operated and corporate capital spending.
5. 2012 FOCUS ON OIL AND LIQUIDS
• Oil and liquids comprised 38% of second quarter 2012 production while contributing 79% of
second quarter revenue
• Drilled 77 gross operated wells in first half of 2012 (99% oil and liquids-rich)
• Grew crude oil and liquids production 19% to 36,125 boe/d in Q2 2012 (relative to Q2
2011) with significant growth at Ante Creek, Pembina and Goodlands
3% 3%
Q4 Revenue
20%
33%
6%
Q4 Production
Q2 Production Q2 Revenue
62% 3% 70%
Crude Oil
Condensate
NGL’s
Natural Gas
6. VALUE PROPOSITION
• We believe that top performing companies all have the following attributes:
– Great assets
– Operational excellence
– Capital discipline
– Management that delivers results
• At ARC our focus since inception has been on
“Risk Managed Value Creation”
• It is not a question of growth or income but of how best to create value for our owners
• Current dividend of $0.10 per month
8. INCOME AND GROWTH
ARC HAS DELIVERED BOTH
• ARC has a 16 year history of risk managed value creation
- Provided a 17.9% annual total return since inception
- Paid out $4.5 billion in total dividends - $28.28/share
- Grown absolute production from 9,500 boe/d to ~95,000 boe/d, – the Montney provides
the opportunity for substantial future growth
- Grown debt and dividend adjusted reserves & production by ~ 10% annually
Production History
100,000
15% CAGR*
75,000
Gas Liquids
Boe/d
50,000
Proved
25,000 Undeveloped
20%
0
2012Q2
1997
2001
2002
2006
2010
1996
1998
1999
2000
2003
2004
2005
2007
2008
2009
2011
* Compound annual growth rate
9. Corporate Strategy
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.
10. RISK MANAGED VALUE CREATION
Understand our Advantaged Position
Leverage our Advantaged Position
Make time to Think Strategically
Financial Operational
Flexibility Excellence
RISK
MANAGED
VALUE
CREATION
High Quality, Top Talent
Long Life and Strong
Assets Leadership
Culture
Be Dynamic and Flexible to Changing Conditions
11. STRATEGIC OVERVIEW
SUMMARY
• ARC’s strategy has delivered exceptional results to date
– We will continue to provide income and profitable growth to our investors
• Where do we go from here?
– Continued focus on meaningful oil and gas accumulations
– Our strategic initiatives will focus on:
• Operational excellence
• Developing the Montney – near term growth is forecast as an outcome
of the quality of our opportunities
• Realization of the value embedded in our assets through the
development of our large potential resources through advanced recovery
methods or application of new technologies
• Opportunistic acquisitions to add to our meaningful resource play
presence
• Maintaining balance sheet strength and financial flexibility
13. 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
15. SE SASKATCHEWAN/MANITOBA
ASSET DETAILS
Net production (boe/d) 11,500 Reserves (2P mmboe) 45.8
Production split 99% liquids Reserve split (2P) 99% liquids
Land (net sections) 248 Reserve Life Index (years) 11
Working Interest ~81%
2012 Plans /Accomplishments
• Increased total production in this area by 21% relative to Q2 2011 to 11,500 boe/d
• Significant production increase coming from Goodlands in Manitoba given active drilling program
in 2011 and 2012
• Drilled 19 light crude oil wells at Goodlands in the first half of 2012
19. PEMBINA
ASSET DETAILS
Net production (boe/d) – Q2 2012 11,500
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.
• 20 Hz Cardium wells drilled in first half of 2012
• Encouraging results on recent Buck Creek
horizontals
20. PEMBINA
OIL AND LIQUIDS GROWTH
ARC HAS GROWN LIQUIDS PRODUCTION IN THIS MATURE FIELD
Pembina - 23% Increase in Oil & Liquids Production since 2006
14,000
12,000
10,000
8,000
Boe/d
Q2 2012 - 8,500 boe/d
6,000 Q1 2006 - 6,900 boe/d oil and liquids
oil and liquids
4,000
Forecast
2,000 gas
oil & liquids
0
Q1 2006
Q2 2006
Q3 2006
Q4 2006
Q1 2007
Q2 2007
Q3 2007
Q4 2007
Q1 2008
Q2 2008
Q3 2008
Q4 2008
Q1 2009
Q2 2009
Q3 2009
Q4 2009
Q1 2010
Q2 2010
Q3 2010
Q4 2010
Q1 2011
Q2 2011
Q3 2011
Q4 2011
Q1 2012
Q2 2012
Q3 2012
Q4 2012
21. PEMBINA
CARDIUM AREA IP AVERAGE (3 MONTH RATE)
LOW CARDIUM DC&T COSTS AT ~$2.3 MM/WELL
600.0
Cardium Area IP Average (3 Month Rate)*
500.0
400.0
ARC Wells
IP3 boe/d
300.0 Other Wells
Industry Median
Well ~ 157 boe/d
ARC Median Well
200.0 ~ 154 boe/d
100.0
0.0
*Wells from TWNS 47-79 Ranges 5-10W5
*Applied minimum 750 production hours for IP3 cut-off
22. PEMBINA – HORIZONTAL WELLS
DEVELOPMENT ECONOMICS
Type Curve
IP (1mo) boe/d 237
IP (12mo) boe/d 94
EUR mboe 167
Type Curve
F&D ($/boe) 13.77
Economics - Type Curve at C$85/bbl
Capital Costs ($k) $4/GJ $3/GJ $2/GJ
Drilling & Completion 2,000
IRR (% AT) 55% 53% 50%
Equip & Tie-In 300
Total 2,300 Recycle Ratio 3.61 3.54 3.47
• All economics run at FLAT price forecasts.
• Condensate 4 bbls/MMcf, Propane 20 bbls/MMcf, Butane 15 bbls/MMcf, GOR 1400 scf/bbl.
• Assumes two month lag from capital spent to production date, and on-lease tie-in well.
24. ANTE CREEK
ASSET DETAILS
Net production (boe/d) – Q2 2012 10,500
Liquids (bbls/d) 5,200
Gas (mmcf/d) 33
Production split % (liquids/gas) ~50/50
Land (Montney net sections) 263
Working Interest ~99%
Reserves (2P mmboe) 47.2
Liquids (mmbbls) 20.2
Gas (bcf) 162
Reserve Life Index 18.2
2012 Plans/Accomplishments
• 30 mmcf/d gas plant commissioned in late February,
alleviating capacity constraints
• Growth in oil and liquids production in 2012
• Production to increase through 2013 as we “drill to fill”
new gas plant
25. ANTE CREEK
HZ WELLS ANTE CREEK - KAYBOB
ARC’S HZ ANTE CREEK WELLS HAVE OUTPERFORMED
1200
30 Day Average Daily IP Rate (boe/d)
1000 ARC Gas
ARC Liquids
Others Gas
800
Others Liquids
600
Boe/d
ARC Median Well
~ 377 boe/d
Industry Median Well
400
~ 231 boe/d
200
0
(1) All reported wells from 60-20W6 to 69-26W6.
(2) Taken within first month of production.
(3) ARC wells include only those originally licensed to ARC and do not include wells acquired by ARC.
(4) All wells have Oil IP3 > 0.
26. ANTE CREEK
GROWING OIL AND LIQUIDS
EXPANDED CAPACITY WILL FACILITATE GROWTH IN 2012/2013
Ante Creek > 60% Increase in Liquids Production during 2012
14,000
12,000
gas
oil & liquids
10,000
>60% growth in Q4 2012 liquids
production relative to Q4 2011
8,000
Boe/d
6,000
4,000
Forecast
2,000
0
Q1 2005
Q2 2005
Q3 2005
Q4 2005
Q1 2006
Q2 2006
Q4 2010
Q1 2011
Q2 2011
Q3 2011
Q4 2011
Q1 2012
Q2 2012
Q3 2012
Q4 2012
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
27. ANTE CREEK
DEVELOPMENT ECONOMICS
450
Type Curve
400
Production Rate (BOE/d)
350
IP (1mo) boe/d 385
300 IP (12mo) boe/d 235
250
200 EUR mboe 265
150
100
50 Type Curve
0
0 3 6 9 12 15 18 21 24 27 30 33 36
Months
F&D ($/boe) 15
Economics - Type Curve at C$85/bbl
Capital Costs ($K) $4/GJ $3/GJ $2/GJ
Drilling & Completions 3,600
IRR (% AT) 45% 35% 25%
Equip & Tie-In 400
Total 4,000 Recycle Ratio 2.2 2.0 1.8
• All economics run at FLAT price forecasts
29. NE B.C. MONTNEY
VAST RESOURCE BASE
We engaged GLJ to provide a resources evaluation of our properties at Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown and
Blueberry located in northeastern British Columbia and at Pouce Coupe located in northwestern Alberta (collectively, the "Evaluated Areas" or "NE BC
Montney"). The evaluation procedures employed by GLJ are in compliance with standards contained in the Canadian Oil and Gas Evaluation Handbook
("COGE Handbook") and the evaluation is based on GLJ's January 1, 2012 pricing
The estimates of Economic Contingent Resources (or ECR), DPIIP, TPIIP, UPIIP and Prospective Resources should not be confused with reserves and
readers should review the definitions and notes set forth at the end of this presentation. Actual natural gas resources may be greater than or less than
the estimates provided herein.
There is no certainty that it will be commercially viable to produce any of the resources that are categorized as discovered resources. There is no
certainty that any portion of ARC's resources that have been categorized as undiscovered resources will be discovered. Furthermore, if discovered, there
is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. Unless indicated otherwise in this presentation,
all references to ECR volumes are Best Estimate ECR volumes.
Continuous development through multi-year exploration and development programs and significant levels of future capital expenditures are required in
order for additional resources to be recovered in the future. The principal risks that would inhibit the recovery of additional reserves relate to the potential
for variations in the quality of the Montney formation where minimal well data currently exists, access to the capital which would be required to develop
the resources, low gas prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the
required services at the appropriate cost, and the effectiveness of fraccing technology and applications. The contingencies that prevent the ECR from
being classified as reserves are due to the early evaluation stage of these potential development opportunities. Additional drilling, completion, and test
results are required before these contingent resources are converted to reserves and a larger component of DPIIP is converted to ECR.
Projects have not been defined to develop the resources in the Evaluated Areas as at the evaluation date. Such projects, in the case of the Montney
resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints,
ARC's policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of ARC on gas
prices, the results of exploration and development activities of ARC and others in the area and possible infrastructure capacity constraints.
See “Definitions of Oil and Gas Reserves and Resources” in this presentation.
30. MONTNEY LANDS
WORLD CLASS RESOURCE
PROGRESS/
• NE BC Montney lands are a major
PETRONAS growth engine.
Kahta/Lily
• Significant opportunity to grow
liquids production.
TALISMAN/ Attachie
SASOL • Total BC Montney Q2 production of
Farrell Creek 240 mmcf/d with Dawson
Tower
contributing approximately 167
Septimus
mmcf/d.
Parkland
• New, 60 mmcf/d gas plant with 130
SHELL Sunset Dawson
Groundbirch
bbls/mmcf of liquids handling
Sunrise capacity planned for Parkland/Tower
in late 2013.
Sundown
ENCANA/ • Ideally positioned with access to
MISTUBISHI west coast and other Alberta
Cutbank Ridge
ARC 100% markets.
ARC <100%
31. NE B.C. MONTNEY
RESOURCE POTENTIAL
• An Independent Resources Evaluation conducted by GLJ effective December 31, 2011
estimates the TPIIP to be 39.6 Tcf using a 3% porosity cut-off and 50.4 Tcf using no cut-off
(comparable to US shale gas resource-in-place estimates).
• DPIIP estimated to be 21.2 Tcf (54% of TPIIP) using a 3% porosity cut-off and 25.5 Tcf
(51% of TPIIP) using no cut-off.
3% Porosity 0% Porosity
Resource Categories (1) (2) Cut-Off (Tcf) Cut-Off (Tcf)
Total Petroleum Initially In Place (TPIIP) 39.6 50.4
Discovered Petroleum Initially In Place (DPIIP) 21.2 25.5
Undiscovered Petroleum Initially In Place (UPIIP) 18.4 24.9
• ARC estimates $54 million of capital would be required to drill and test sufficient wells to
convert all of the TPIIP into DPIIP
• ARC’s long-term development plans are based upon the estimated TPIIP
• The amount of natural gas and NGL’s which is ultimately recovered from ARC’s NE B.C.
Montney resource will be primarily a function of the future price of both commodities
(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.
32. NE B.C. MONTNEY
RESERVES AND RESOURCES
• GLJ’s Best Estimate of the ECR is 4.1 Tcf of gas and 101 Mmbbls
• Significant natural gas liquids (“NGL”) resource exists in the Montney in the Attachie,
Parkland, Septimus and Tower areas
• GLJ’s Best Estimate of the NGL ECR is 101 Mmbbls. In addition, GLJ’s Best Estimate of
Prospective NGL Resources is 98 Mmbbls
Low High
Reserves and Economic Contingent Resources (1)(5)(6) Estimate Best Estimate Estimate
Natural Gas (Tcf)
Reserves (2) 1.0 1.9 2.4 (3)
Economic Contingent Resources 2.5 4.1 5.7
Natural Gas Liquids (mmbbls) (4)
Reserves 11.3 21.1 26.6 (3)
Economic Contingent Resources 64.2 101.0 133.9
Low High
Prospective Resources (1)(6) Estimate Best Estimate Estimate
Natural gas (Tcf) 2.9 4.0 5.3
Natural gas liquids (mmbbls) (4) 69.0 98.0 131.2
(1) All DPIIP other than cumulative production, reserves, and ECR and all UPIIP other than Prospective Resources has been categorized as unrecoverable.
(2) 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.
(3) 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.
(4) The liquid yields are based on average yield over the producing life of the property.
(5) Cumulative production has been 0.2 Tcf on a raw basis.
(6) All volumes in table are company gross and sales volumes.
33. NE B.C. MONTNEY
RESERVES AND RESOURCES
• Very early stage in reserve booking cycle:
• 2P Reserves (1.9 Tcf) plus Cum Prod only 5.3% of TPIIP at 3%
cut-off (4.2% at 0% cut-off).
• Best Estimate ECR estimated to be 4.1 Tcf resulting in total
recovery including 2P reserves and Cum Prod to date of only
15.7% of TPIIP at 3% cut-off (12.3% at 0% cut-off).
• ARC estimates the 2P Reserves plus ECR (6.0 Tcf) can support a
peak production rate of 800 mmcf/d for 10 years.
• Estimated Prospective Resources of 4.0 Tcf (“Best Estimate”) results
in a total potential recovery factor of ~20% - 25% of the TPIIP.
Recovery factors at that level could support a peak production rate of
>1.3 Bcf/d for 10 years.
34. ARC RESOURCES
TOP MONTNEY DRILLER AND PRODUCER
• ARC Resources has been one of the top tier drillers and producers in the Montney since completion of its
first horizontal well in 2005
- Success of this well led to the recognition that considerably more gas could be accessed than
previously thought
• As an early play entrant, ARC added significant land and resource in the sweet spot of the fairway
through both acquisitions and land sales
• Other early entrants recognizing the prospectively of the Montney surrounding ARC lands include, Shell,
EnCana, Murphy, CNRL and Talisman
Montney Wells Rig Released since 2003 by Montney Gross Operated Raw Gas Production
Operator (Mmcf/d)
400 500
350 450
400
300
350
250 300
200 250
150 200
150
100
100
50 50
0 0
PRQ
ECA
MUR
CNQ
TLM
BIR
CR
ARX
TOU
AAV
RDS
ECA
ARX
PRQ
TT
COP
BTE
MUR
CNQ
TLM
CR
DVN
BP
SU
TOU
RDS
35. ARC RESOURCES MONTNEY GAS WELLS
EXCEEDING EXPECTATIONS
ARC’S MONTNEY GAS WELLS HAVE THE BEST INITIAL PRODUCTIVITY
37. PARKLAND/TOWER
EVALUATING POTENTIAL AND DEVELOPING
EXISTING LANDS
Parkland Tower
Net production (boe/d) 8,100 330
Tower
Liquids (bbls/d) 1,100 150
Gas (mmcf/d) 42 1.0
Land (net sections) 23 56
Working Interest ~84% ~90%
Reserves (2P mmboe) 49.7 4.5
Liquids (mmbbls) 8.4 1.4
Gas (bcf) 247.0 19.2
Parkland
Reserve Life Index 16 37
2012 Plans/Accomplishments
• Drilled and completed 3 wells in 2011, 2 wells now on production
• Drill 8 Hz wells by end of Q3 2012
• Complete, test and put on production all wells by year-end 2012
• Application submitted to construct two 60 mmcf/d gas plants with 130 bbls/mmcf liquids capacity
38. PARKLAND
CAN A SINGLE WELL DRAIN THE FULL
VERTICAL SECTION?
• At Parkland, the Upper Montney is considerably thicker than at Dawson. We believe the
lower-most sands are not contributing to production – a horizontal well has been drilled into
these lower sands to test this theory.
8-25-79-15W6
MA
Lower sand and 5
upper sand 1
month
Sands
Upper
production are
similar
Sands
No communication
Lower
between upper and
lower sands to date
39. PARKLAND
DEVELOPMENT ECONOMICS
6,000
Type Curve
5,000
IP (1mo) MMcf/d 5.0
4,000 IP (12mo) MMcf/d 2.6
Gas Rate mcf/d
3,000 EUR Bcf 4.8
2,000
1,000
Type Curve
0
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36
Months
F&D ($/boe) 5.5 Economics - Type Curve at C$85/bbl
Capital Costs ($k) $4/GJ $3/GJ $2/GJ
Drilling & Completion 4,200
IRR (% AT) 65% 40% 15%
Equip & Tie-In 500
Total 4,700 Recycle Ratio 3.6 2.8 1.8
• All economics run at FLAT price forecasts.
• Condensate 10 bbls/MMcf, Propane 6 bbls/MMcf, Butane 7 bbls/MMcf.
• Royalties noted (24%) based on approximate subsequent year royalty rate after.
$850 M credit is drawn down.
• Assumes one month lag from initial capital spent to production date.
41. ATTACHIE
NEW OPPORTUNITY UNDEFINED POTENTIAL
• Prospective land base of
117 sections
• ARC has drilled three Hz wells to
date:
• The 4-20 well tested at 10.7 mmcfd
and 350 bbls per day of free liquids
with 1,300 psia flowing pressure
• Tied in two wells to the 4-9 battery
and brought production on-stream
late in Q2
• Interpreted a 3D seismic program
over 300 square kilometers in the first
half of 2012
• Two wells planned for the second half
of 2012
43. DAWSON
ASSET DETAILS
Net production (boe/d) – Q2 2012 28,000
Liquids (bbls/d) 700
Gas (mmcf/d) 163
45 mmcf/d
Compressor Production split % (liquids/gas) ~97% gas
Station
120 mmcf/d Land (Montney net sections) 130
Gas Plant
Working Interest ~96%
Reserves (2P mmboe) 174
Liquids (mmbbls) 5.0
Gas (bcf) 1,012
Reserve Life Index 16.8
2012 Plans/Accomplishments
• Inventory of completed gas wells to be tied-in
throughout 2012
• Maintain 2012 production flat at 165 mmcf/d
44. MONTNEY HORIZONTAL WELLS
30 DAY HZ IP RATES GLACIER - TOWN
ARC’S DAWSON/PARKLAND WELLS HAVE EXCEEDED EXPECTATIONS
14,000
12,000
10,000
Production Rate (mcf/d)
ARC Others
8,000
ARC P50
5.2 Mmcf/d
6,000
Other Wells P50
3.3 Mmcf/d
4,000
2,000
0
1 101 201 301 401 501 601 701 801 901 1001
(1) Graph represents peak calendar day IP rates for the first month of production to July 2012.
(2) Region includes all horizontal wells from NE BC and NW AB Montney.
45. DAWSON
DEVELOPMENT ECONOMICS
Type Curve
IP (1mo) MMcf/d
5.0
6,000
IP (12mo) MMcf/d
5,000
4.2
Gas Rate (Mcf/d)
4,000
EUR (Bcf)
6.2
3,000
2,000
1,000 Type Curve
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Months
F&D ($/boe) 5.1
Economics - Type Curve at C$85/bbl
Capital $k $4/GJ $3/GJ $2/GJ
Drilling & Completion 4,600
Tie-In 500
IRR (% AT) 80% 40% 5%
Total 5,100 Recycle Ratio 3.2 2.3 1.1
• All economics run at FLAT price forecasts.
• Condensate 3.5 bbls/MMcf , Butane 0.6 bbls/MMcf and Propane 0.4 bbls/MMcf .
• Deep drill royalty credit ~1$MM applied to all cases.
49. SUNRISE/SUNSET
DEVELOPMENT ECONOMICS
7,000
Type Curve
6,000
IP (1mo) MMcf/d 6.0
5,000
Gas Rate mcf/d
IP (12mo) Mcf/d 2.8
4,000
EUR Bcf 7.0
3,000
2,000
1,000 Type Curve
0
2 4 6 8 10 12 14 16 18 20 22 24
Months
F&D ($/boe) 5.25
Economics - Type Curve at C$85/bbl
Capital Costs ($k) $4/GJ $3/GJ $2/GJ
Drilling & Completion 5,600
IRR (% AT) 50% 30% 10%
Equip & Tie-In 400
Total 6,000 Recycle Ratio 3.3 2.6 1.6
• All economics run at FLAT price forecasts.
• Assumes development is done with 8 wells per pad
• Condensate 1 bbls/MMcf, Propane 3 bbls/MMcf, Butane 1 bbls/MMcf.
• Royalties noted (24%) based on approximate subsequent year royalty rate after $1,250k credit is drawn down.
• Assumes one month lag from capital spent to production date, and on-lease tie-in well.
51. WHY INVEST IN ARC RESOURCES
• ARC is a top-tier oil and natural gas producer focused on “Risk Managed Value Creation”
• Extensive land position in top quality resource plays provides significant growth opportunity.
• Significant near-term oil and liquids growth opportunities
• Significant long-term natural gas growth opportunity in B.C. Montney
• Diverse inventory of high quality oil, liquids-rich gas and natural gas development
opportunities provides optionality through commodity price cycles
• History of proven performance
• Grown absolute production from 9,500 boe/d to 95,000 boe/d to date
• Grown P+P reserves from 47 mmboe to 572 mmboe to date
• Progressive approach of applying new technologies to “unlock” value
• Proven track record of “Operational Excellence” in both cost management and safety
• Solid balance sheet with protective hedging program
• Experienced management team with track record of delivering results
54. 2012 FINANCIAL AND
OPERATIONAL PERFORMANCE
Q2 2012 YTD 2012
(CDN$ millions, except per share and per boe amounts) 2012 2011 2012 2011
Production (boe/d) 93,997 82,367 94,484 78,147
Gas 62% 63% 62% 60%
Liquids 38% 37% 38% 40%
Revenue 317.2 374.3 683.2 698.4
Gas 64.3 115.1 150.1 204.9
Liquids 252.9 259.2 533.1 493.5
Funds from operations 165.8 210.1 346.5 404.2
Per share 0.57 0.73 1.19 1.42
Operating Income 30.5 76.4 77.4 149.2
Per share 0.10 0.27 0.27 0.52
Dividends 87.3 85.8 174.2 171.4
Per share 0.30 0.30 0.60 0.60
Capital expenditures 97.9 144.5 284.8 301.7
Net debt outstanding 996.0 744.8 996.0 744.8
Weighted average number of shares outstanding 290.8 286.0 290.2 285.4
(millions)
Netback (pre-hedging) 20.86 32.15 23.35 31.5
55. 2012 GUIDANCE
2012 Revised
2012 Guidance Guidance 2012 YTD Actual
Oil (bbls/d) 31,000 – 32,000 30,000 – 31,000 31,068
Condensate (bbls/d) 2,100 – 2,500 2,100 – 2,500 2,390
Gas (mmcf/d) 330 – 350 340 – 350 350
NGL’s (bbls/d) 2,100 – 2,600 2,100 – 2,600 2,673
Total (boe/d) 90,000 - 95,000 91,000 – 94,000 94,484
Operating costs 9.55 – 9.95 9.50 – 9.70 9.11
Transportation costs (1) 1.00 – 1.10 1.30 – 1.40 1.20
G&A expenses (2)
2.30 – 2.50 2.45 – 2.60 2.54
Interest (3) 1.10 – 1.20 1.20 – 1.30 1.24
Cash Taxes (4) 1.10 – 1.25 1.15 – 1.20 1.15
Capital expenditures (millions) (5)
600 600 285
Land expenditures and minor net property
acquisitions ($ millions) (6) - 25 - 50 23
Weighted average shares outstanding (millions) 293 293 290
(1) Transportation costs exceeded guidance slightly due to increased trucking activity in the first half of 2012. Going forward, transportation costs are expected to increase as ARC plans to ship a large proportion of its crude oil production on its own as
opposed to relying on third-party marketers, resulting is receiving a premium price for its products.
(2) The 2012 annual guidance for general and administrative cost per boe is based on a range of $1.75 - $1.85 prior to the recognition of any expense associated with ARC’s long-term incentive plan and $0.70- $0.75 per boe associated with ARC’s long-term
incentive plan. Actual per boe costs for each of these components for the six months ended June 30, 2012 were $1.76 per boe and $0.78 per boe, respectively.
(3) Includes impact of US$360 million and CDN$40 million of long-term notes to be issued by August 31, 2012.
(4) The 2012 corporate tax estimate will vary depending on the level of commodity prices and represents only the current income tax expense.
(5) Excludes amounts related to unbudgeted net acquisitions of land and small producing properties which totaled approximately $23 million in the first half of 2012.
(6) Land expenditures and minor net property acquisitions are not included in the $600 million capital program .
56. ACCESS TO CAPITAL
DEBT
Debt raised from three different sources:
1. Bank Credit Facility - $1 billion plus $25 million overdraft facility, 12 banks under facility
• $484 million drawn under credit facility as at June 30, 2012 was repaid in full in
August 2012 with proceeds from long-term note issuance and equity proceeds
• The credit facility was extended to August 3, 2015
• Pre-approval for an additional $250 million (Accordion)
2. Long-term notes
• Private Placement market
• Currently have US$271 MM and CDN$23 MM drawn (Q2 2012)
• New Issue of US$360 MM and CDN$40MM of notes closed Aug 23, 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$225 MM (Q2 2012)
• Term extended to April 14, 2015
57. DEBT MATURITIES
SPREAD OVER TIME
• ARC’s long-term notes are structured so that they mature over a number of years; this
reduces refinancing risk
• ARC’s unused credit capacity of $1 billion (after debt and equity proceeds) allows for
significant flexibility to repay debt
Long-term Principal Note Repayment Schedule
120
100
80
C$ Millions
60
40
20
0
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
58. HEDGE POSITIONS
AS OF JULY 31, 2012
Summary of Hedge Positions as at July 31, 2012 (1)(2)
Jul – Oct 2012 Nov – Dec 2012 Jul – Dec 2012 2013 2014 - 2017
Crude Oil – WTI:
(US$/bbl) US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d
Sold Call $ 91.11 18,000 $ 91.11 18,000 $ 91.11 18,000 $ 105.01 11,984 - -
Bought Put $ 90.00 18,000 $ 90.00 18,000 $ 90.00 18,000 $ 95.01 11,984 - -
Sold Put $ 63.44 16,000 $ 63.44 16,000 $ 63.44 16,000 $ 64.17 11,984 - -
Crude Oil Floors as % of 2012
Guidance (3) 56% 56% 56% 37% -
Natural Gas - Nymex:
(US$/mmbtu) $/mmbtu mmbtu/d $/mmbtu mmbtu/d $/mmbtu mmbtu/d $/mmbtu mmbtu/d $/mmbtu mmbtu/d
Sold Call $ 3.86 130,000 $ 5.00 30,000
Bought Put $ 3.34 130,000 $ 4.00 30,000
Sold Swap $ 3.77 220,000 $ 3.48 175,000 3.71 205,082
Natural Gas Floors as % of
2012 Guidance (3) 63% 50% 59% 37% 9%
Total Floors as % of 2012
Guidance (3) 55% 48% 53% 35% 5%
(1) The prices and volumes noted above represent averages for several contracts 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 crude oil, all put positions settle against the monthly average WTI price, providing protection against monthly volatility. Calls have been sold against either the monthly average or the
annual average WTI price. For annual sold calls, volumes are based on full year and 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) The above calculated floors (bought puts) are determined using the high end of 2012 guidance volumes.
59. RESERVES AND RESOURCES
The discussion in this presentation in respect of reserves and resources is subject to a number of cautionary statements,
assumptions and risks as set forth below and elsewhere in this presentation. See also the definitions of oil and gas reserves
and resources found at the end of this presentation.
The reserves data set forth in this presentation is based upon an evaluation by GLJ Petroleum Consultants Ltd. ("GLJ") with
an effective date of December 31, 2011 using forecast prices and costs. The reserves evaluation was prepared in
accordance with National Instrument 51-101 ("NI 51-101"). Crude oil, natural gas and natural gas liquids benchmark
reference pricing, as at December 31, 2011, inflation and exchange rates used in the evaluation are based on GLJ's
January 1, 2012 pricing. Reserves included herein are stated on a company gross basis (working interest before deduction
of royalties without including any royalty interests) unless noted otherwise.
There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The
recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only
and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid
reserves may be greater than or less than the estimates provided herein.
See also ”NE B.C. Montney Vast Resource Base”, for further discussion regarding reserves and resources.
See “Definitions of Oil and Gas Reserves and Resources” in this presentation.
60. KEY RESERVE INFORMATION
19% COMPOUND ANNUAL GROWTH
• Reserves as of December 31, 2011* (mmboe)
- Proved Producing 209 (98 mmboe liquids, 655 bcf gas)
- Total Proved 360 (123 mmboe liquids, 1,419 bcf gas)
- Proved Plus Probable 572 (170 mmboe liquids, 2,413 bcf gas)
700
19% CAGR
600 Probable Proved
Producing
Gas 37%
36%
500 Liquids
Proved
mmboe
400 Undeveloped
Proved Non-
25%
Producing
300 2%
NGL's
200 6%
Crude
oil
100 24%
0
Natural
Gas
70%
INTERNAL DEVELOPMENT
MONTNEY
61. 385 PER CENT
RESERVE REPLACEMENT IN 2011
• Fourth consecutive year of greater than 200% reserve replacement through the drill bit
• Proved plus probable reserves increased 18% to 572 mmboe after divest of non-core assets
with 14.6 mmboe of 2P reserves
700%
Acquisitions
600% Development
500%
400%
300%
200%
100%
0%
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
62. DEFINITIONS OF OIL AND GAS
RESERVES AND RESOURCES
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known
accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established
technology; and specified economic conditions, which are generally accepted as being reasonable. reserves are classified according to the
degree of certainty associated with the estimates as follows:
Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual
remaining quantities recovered will exceed the estimated proved reserves.
Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the
actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the
actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
Resources encompasses all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations,
including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. “Total resources” is equivalent
to “Total Petroleum Initially-In-Place”. Resources are classified in the following categories:
Total Petroleum Initially-In-Place (“TPIIP”) is that quantity of petroleum that is estimated to exist originally in naturally occurring
accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations,
prior to production, plus those estimated quantities in accumulations yet to be discovered.
Discovered Petroleum Initially-In-Place (“DPIIP”) is that quantity of petroleum that is estimated, as of a given date, to be contained in
known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production,
reserves, and contingent resources; the remainder is unrecoverable.
Forecast
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known
accumulations using established technology or technology under development but which are not currently considered to be
commercially recoverable due to one or more contingencies.
63. DEFINITIONS OF OIL AND GAS
RESERVES AND RESOURCES
Economic Contingent Resources are those contingent resources which are currently economically recoverable.
Undiscovered Petroleum Initially-In-Place (“UPIIP”) is that quantity of petroleum that is estimated, on a given date, to be contained
in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as
“prospective resources” and the remainder as “unrecoverable.”
Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from
undiscovered accumulations by application of future development projects.
Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future
development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or
technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented
by subsurface interaction of fluids and reservoir rocks.
Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and
resources as follows:
Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual
remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent
probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the
actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be
at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best
estimate.
High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the
Forecast
actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10
percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
64. 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 November 2, 2011 news release titled “ARC
Resources Ltd. Announces A $760 Million Capital Budget For 2012, Which includes a Twelve Per
Cent Production Growth Target”, the January 26, 2012 release titled “ARC Resources Ltd.
Announces 18 per cent increase in year-end Reserves and results of updated Independent
Resources Evaluation for Northeast British Columbia Montney Assets”; and the February 8, 2012
release titled “ARC Resources Ltd. reports Fourth Quarter 2011 Results” which may be found on
SEDAR at www.sedar.com and are incorporated by reference and outline a number of 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: For further information about ARC’s properties please
Investor Relations view our virtual field tour (in our operations section) at
E-mail: ir@arcresources.com www.arcresources.com
T 403.503.8600 F 403.509.6417
Toll Free 1.888.272.4900
ARC Resources Ltd.
1200, 308 – 4 Avenue S.W.
Calgary, AB T2P 0H7
