ARC Resources - February 2013 Investor Presentation
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Transcript of 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)
~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)
~51 gross operated wells~12,600 boe/d(2)
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 $3/GJ AECO• Liquid yield assumptions – 11 bbl/mmcf C5+, 13 bbl/mmcf NGL
Key Metrics
DCET Capex per well ($MM) 5.2
Reserves per well (Bcf) 5.8
IP (1 mo) (MMcf/d) 5.0
IP (12 mo) (MMcf/d) 4.0
Economics ($85/bbl) $4/GJ $3/GJ
IRR (% AT) 79% 54%
Recycle Ratio 4.2 3.3
-
500
1,000
1,500
2,000
2,500
2010 2011 2012 2013
Sa
les
(b
oe
/d)
Tower Production
Gas (Forecast)
Liquids (Forecast)
Gas
Liquids
2012 Accomplishments:
• 2012 Operated Program average 30 day IP rate: 375 boe/d per well
• Production volumes limited due to liquid handling restrictions
• First of two 8 well development pads to be completed in 2013; spud in late October 2012
2013 Plans:
• 60 mmcf/d gas processing and liquids handling facility expected on-stream early 2014; site clearing and pile driving commenced
• Continue with pad drilling program in 2014 – expect ‘step’ production profile as all wells brought on at one time (8 wells per pad)
TOWER2012 ACCOMPLISHMENTS
(1) ARC purchased the Tower property in August 2010.
ARC purchased the Tower
property in 2010
• Pad drilling will substantially minimize surface land footprint
• Expect 8 to 16 wells per pad depending on reservoir characteristics
• Considerable cost savings related to pad development compared to single well leases, up to 20%
• Numerous operational and capital efficiencies due to pad development: reduced rig moves; single lease to survey, acquire and build; consolidated facilities, electricity to one site, single trunk line
• The cycle time from spud to on production is extended by 5 months for an 8 well pad. All wells are drilled and completed before production commences
TOWER OPERATIONAL EXCELLENCE - MINIMIZING FOOTPRINT
0 6 12 18 24 30 360
100
200
300
400
500
600
Months
Pro
du
ctio
n R
ate
(bo
e/d
)TOWERMONTNEY DEVELOPMENT ECONOMICS
Key Metrics
DCET Capex per well ($MM) 5.3
Reserves per well (Mboe) 400
IP (1 mo) (boe/d) 500
IP (12 mo) (boe/d) 260
Economics ($85/bbl) $4/GJ $3/GJ
IRR (% AT) 41% 37%
Recycle Ratio 3.3 3.1
• 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 – $249MM OPERATED
2014 base production, does not include 2014 CAPEX program
2013
-01
2013
-02
2013
-03
2013
-04
2013
-05
2013
-06
2013
-07
2013
-08
2013
-09
2013
-10
2013
-11
2013
-12
2014
-01
2014
-02
0
5,000
10,000
15,000
20,000
25,000
2013 Budget - Volumes (BOED)Operated
PO DEV OPT
Base Decline ~21%
• Drill 24 horizontal wells.• Construct the oil handling, gas processing and pipeline infrastructure with a planned start-up in early 2014• Significant capital being spent in 2013 with volumes coming on-stream in 2014.
DawsonWorld Class Asset
DAWSONASSET DETAILS
Net production (boe/d) –Q4 2012 28,800
Liquids (bbls/d) 800
Gas (mmcf/d) 168
Production split % (liquids/gas) ~97% gas
Land (Montney net sections) 130
Working Interest ~96%
Reserves (2P mmboe) 181
Liquids (mmbbls) 5.2
Gas (bcf) 1,052
Reserve Life Index 17
2013 Plans
• Inventory of completed gas wells to be tied-in during first half of 2013
• Drill 9 wells in 2013,maintain 2013 production flat at 165 mmcf/d
45 mmcfdCompressor Station
120 mmcfd Gas Plant
• 2008 type curve analysis was completed using initial production results and verified with a vertical well production multiplier
• 2009-2011 Type curve used P90 IP’s with decline analysis and assigned decline exponent rate
• 2012 Type curve realized the consistent flat production, coupled with a sharp decline exponent rate
• 2013 type curve uses historical pressure and production data from 60+ wells to estimate existing remaining reserves and forecast future wells
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 360
1,000
2,000
3,000
4,000
5,000
6,0002013 Type Curve
2012 Type Curve
2009-2011 Type Curve
2008 Type Curve
Months on Production
Gas R
ate
(Mcf
/d)
DAWSON TYPE CURVE GROWTH
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 360
1,000
2,000
3,000
4,000
5,000
6,000
7,000
Months
Gas R
ate
(Mcf
/d)
Key Metrics
DCET Capex per well ($MM) 5.2
Reserves per well (Bcf) 7.1
IP (1 mo) (MMcf/d) 5.0
IP (12 mo) (MMcf/d) 4.8
Economics ($85/bbl) $4/GJ $3/GJ
IRR (% AT) 72% 44%
Recycle Ratio 3.8 2.8
• 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 – $52MM OPERATED
2013-
01
2013-
02
2013-
03
2013-
04
2013-
05
2013-
06
2013-
07
2013-
08
2013-
09
2013-
10
2013-
11
2013-
12
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
2013 Budget - Volumes (BOED)Operated
PO DEV
• Dawson is a world-class asset that continues to exceed expectations.• Drill 9 horizontal Montney wells, on two pads, add compression to 1-34 compressor station
and optimize gas plant.
Base Decline ~28%
WEST MONTNEY Long-term Growth Opportunity
WEST MONTNEYASSET DETAILS
Net production (boe/d)- Q4 2012 3,760
Liquids (bbls/d) 90
Gas (mmcf/d) 22.0
Land (net Montney sections) 214
Working Interest ~90%
Reserves (2P mmboe) 131
Liquids (mmbbls) 11
Gas (bcf)
Reserve Life Index
723
88
Attachie
Tower
ParklandSeptimus
Sunset
Sunrise
Sundown
Dawson
Blueberry
WEST MONTNEYOPERATIONAL EXCELLENCE – DEVELOPMENT PLANNING
WEST MONTNEY SUNRISE PRODUCTION – OUTPERFORMING EXPECTATIONS
Montney A Sunrise A2-25 Hz
Montney B Sunrise B2-25 Hz
• Realized positive technical revisions in Sunrise based on 2-25 Hz well pad performance. Estimated Ultimate Recovery (EUR) is Cumulative Production + 2P Reserves.
MTYA (Raw)Cum to Dec.31, 2012: 2.2 BcfARC EUR Forecast: 11 – 14 BcfGLJ 2011 EUR: 7 BcfGLJ 2012 EUR: 10 Bcf
MTYB (Raw)Cum to Dec. 31, 2012: 2.3 BcfARC EUR Forecast: 10 – 13 BcfGLJ 2011 (2P) EUR: 6 BcfGLJ 2012 (2P) EUR: 10 Bcf
0 6 12 18 24 30 360
1,000
2,000
3,000
4,000
5,000
6,000
Months
Gas
Rat
e m
cf/d
SUNRISEMONTNEY SUNRISE DEVELOPMENT ECONOMICS
Key Metrics
DCET Capex per well ($MM) 5.5
Reserves per well (Bcf) 9.7
IP (1 mo) (MMcf/d) 5.2
IP (12 mo) (MMcf/d) 4.5
Economics ($85/bbl) $4/GJ $3/GJ
IRR (% AT) 51% 32%
Recycle Ratio 4.5 3.2
• 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
Working Interest ~79%
Reserves (2P mmboe) Cardium 49.4
Reserve Life Index 15
2013 Plans• ARC is the second largest operator in the Pembina area• Continued focus on long term value through prudent reservoir and waterflood management• 11-31 Berrymoor plant expansion expected on stream May 2013• Drill 52 Hz wells and two vertical injectors throughout the Pembina area (operated)
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 $2.4 MM per well (1)
• ARC’s Cardium well performance is comparable to industry peer average
(1) Source information from Well Completions & Frac Database – Canadian Discovery Ltd. and Introspec Energy Group Inc., wells rig released Jan 2011 to Nov 2012.(2) IP3 data from Accumap - includes wells with greater than 750hrs, wells within TWP 47-49 RNG 5-10W5, on production after January 1, 2008.
PEMBINA OIL – OPERATIONAL EXCELLENCE INDUSTRY LEADING CAPITAL EFFICIENCY
-
50
100
150
200
250
300
350
400
450
IP3
(boe
/d)
Cardium Area IP Average (3 Month Rate)
ARC Others
ARC Average Oil IP~ 137 bbls/d
0 6 12 18 24 30 360
2
4
6
8
10
12
Months On Production
Rat
e (b
oep
d)
Key Metrics
DCET Capex per well ($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
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 $9 MM (gross) on drilling
water injection wells, converting wells producers to injectors and injection stimulations.
Base Decline ~23%
SE SASKATCHEWAN OILSolid Long-life Assets
Net production (boe/d) – Q4 2012
12,200
Production split 99% liquids
Land (net sections) 241
Working Interest ~81%
Reserves (2P mmboe) 48.1
Reserves Life Index 11
SE SASKATCHEWAN / MANITOBA OILASSET DETAILS
2013 Plans:
• Continue to drill horizontally in a number of properties that were previously only vertically exploited.
• Drilling 51 gross operated wells in 2013 with significant focus at Goodlands in Manitoba.
• Continued focus on long term value through prudent reservoir and waterflood management
Key Metrics
DCET Capex per well ($MM) 1.4
Reserves per well (Mboe) 54
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