Transcript Document

MAY, 2010
ANNUAL GENERAL MEETING – May 18, 2010
ARC ENERGY TRUST
FORWARD LOOKING INFORMATION
This presentation contains forward-looking information as to the Trust’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 the 2010, the quantification of the
resources in the Montney formation in British Columbia, increased reserves at lower finding costs as a result of the
developments in the Montney formation in British Columbia and possible results of our CO2 flood at Redwater and
proposed CO2 sequestration project. 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
Energy Trust. 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, lack of legislation in Alberta
governing CO2 sequestration 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 2010 Guidance which is updated and discussed quarterly, the Trust
does not undertake to update any forward looking information in this document whether as to new information,
future events or other wise except as required by securities laws and regulations.
1
ARC ENERGY TRUST
• Launched July 1996
- 19% annual return since inception (to May 11)
- $25.38 per unit in total distributions (to May 11)
- Total distributions of $3.6 billion (to May 11)
• TSX listed – member of the S&P / TSX 60 index
- AET.UN – units; ARX – exchangeable shares
- Average trading volume 2010 – 1,160,000 units per day
• $5.9 billion enterprise value ($5.2 billion market cap)
- $678 million net debt at March 31
- 253 million total trust units outstanding at March 31, 2010
• Including 2.5 million units to be issued on the exchange of ARC exchangeable shares
2
2009 HIGHLIGHTS
• Annual production averaged 63,538 boe per day
• Cash flow from operating activities was $497.4 million ($2.11 per unit)
• Distributions were $299 million ($1.28 per unit)
• Total earnings were $223 million ($0.96 per unit)
• Payout ratio was 60 per cent of cash flow from operating activities
• Replaced 285 per cent of production and increased proved plus probable reserves
to 377 mmboe
• P+P FD costs were $5.45 per boe excluding future development capital (“FDC”)
and $10.54 including FDC
• P+P FD& costs were $6.44 per boe excluding FDC and $11.56 including FDC
3
Q1 2010 HIGHLIGHTS
• Q1 production averaged a record of 67,207 boe per day
• Cash flow from operating activities was $159 million($0.63 per unit) for the
three months
• Distributions were $75 million ($0.30 per unit)
• Total earnings were $139 million ($0.56 per unit)
• Payout ratio was 47 per cent of cash flow from operating activities
• Number of wells drilled was 49 gross wells (44 net wells) on operated
properties with a 100 per cent success rate
2
Q1 2010
OPERATING PERFORMANCE
($ millions except per unit and per boe numbers)
Q1 2010
Q1 2009
Change
Cash flow from operating activities
Per unit
159
0.63
124
0.54
+28%
+17%
Earnings
Per unit
139
0.56
22
0.10
+525%
+460%
Distributions
Per unit
% of Cash flow from operating
activities
75
0.30
82
0.36
-8.5%
-17%
47%
66%
-29%
Total capital expenditures
135
103
+30%
Net debt outstanding
678
782
-13%
Weighted average number of units
outstanding (millions)
252
229
+10%
2
BALANCED PRODUCTION
46/54 OIL/GAS SPLIT
Production History
Q1 2010
2010
2009
2008
2007
2006
IMPERIAL>>2005
2004
STAR>>2003
2002
STARTECH>>2001
SUNCOR>>2000
Liquids
ORION>>1999
1997
Gas
1998
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
MOBIL>>1996
BOE/D
• Production of 67,207 in Q1 2010
- 75 per cent operated
- 46/54 oil/gas split (98 per cent of oil is light or medium)
3
EXCELLENT 2009 FD&A RESULTS
• Proved + Probable reserves increased by 18% - 379 mmboe
• Replaced 347% of production at an all in P+P FD&A of $6.44/boe
• Drill bit P+P F&D of $5.45 was the lowest in a decade
FD&A
$25
$/boe
$20
$15
$10
$5
$0
2002
2003
2004
2005
2006
2007
2008
2009
4
EXCELLENT 2009 FD&A RESULTS
Source: National Bank Financial
4
EXCELLENT 2009 RECYCLE RATIO
Source: National Bank Financial
4
EXCELLENT PRODUCTION
REPLACEMENT RESULTS
• Second successive year of greater than 200% production replacement
from the drill bit
• ARC has successfully made the transition from a trust that relied on
acquisitions for growth to one that grows through the drill bit
Production Replacement
Development
Acquisitions
700%
600%
500%
400%
300%
200%
100%
0%
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
5
KEY RESERVE INFORMATION
• Reserves as of December 31, 2009* (mmboe)
- Proved Producing
- Total Proved
- Proved Plus Probable
- 14.5 year reserve life index
186
270
379
(104 mmboe liquids, 490 bcf gas)
(116 mmboe liquids, 917 bcf gas)
(153 mmboe liquids, 1,353 bcf gas)
Proved Plus Probable Reserves
mmboe
400
350
Gas
300
Liquids
250
Probable
29%
200
Proved
Producing
49%
150
100
2009
2008
2007
2006
2004
IMPERIAL>>2005
STAR>>2003
2002
STARTECH>>2001
ORION>>1999
SUNCOR>>2000
1998
1997
0
MOBIL>>1996
50
INTERNAL
DEVELOPMENT
- MONTNEY
Proved
Undeveloped
20%
Proved,
Developed
Non
Producing
2%
[*] Reserves are “Company Interest” (Gross + Royalties Receivable). Gross Proved Plus Probable reserves are 377 mmboe. Boe may be misleading, particularly if used in isolation. In
accordance with NI 51-101, a boe conversion ratio of 6 Mcf : 1 bbl has been used which is based on an energy equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
6
INCOME AND GROWTH
BOTH ARE POSSIBLE
• ARC has a 13 year history of risk managed value creation
- Provided a 19% annual return since inception
- Distributed $3.6 billion in total distributions - $25.38 / unit
- Grown absolute production from 9,500 boe/d to 67,000 boe/d, with discrete
transactions followed by stability – the Montney provides the opportunity for
internal growth
- Grown debt and distribution adjusted reserves & production by 9% annually
Production History
80,000
?
70,000
Gas
Liquids
50,000
Proved
Undeveloped
20%
40,000
30,000
20,000
10,000
2012
2010F
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
0
1996
BOE/D
60,000
7
CONVERSION TO A CORPORATION
• We currently expect to convert to a corporation on January 1, 2011
- Delaying conversion to the end of 2010 will preserve the maximum
amount of tax pools
• No change in strategy - focus on long-term, risk managed value creation
will not change
• Will remain a dividend paying entity as we believe the demand for income
oriented investments will continue to grow
• Continue to believe that returning cash to our owners instills discipline and
will lead to out-performance in the long-term
• We expect to maintain existing distribution philosophy
• Most likely factored into market price of ARC units.
8
CONVERSION TO A CORPORATION
ARC Energy
Trust
Distributions
Unitholders
Conversion planned for
January 1, 2011 with a
December 2010 unitholders
meeting
ARC
Resources
Dividends
Shareholders
• Delaying conversion to the end of 2010 will preserve the maximum tax pools
• ARC has set a special unitholder meeting set for December 15, 2010
8
PROPERTY OVERVIEW
ARC’S UNCONVENTIONAL
OPPORTUNITIES
CO2 Enhanced Oil
Recovery
- Active projects at
Weyburn/Midale
- Pilot at Redwater
- Proposed pilot at
Pembina
Multi-Stage Horizontal
“Frac”
- Dawson
- Ante Creek
GOODLANDS
- Pembina
- Goodlands
9
2010 BUDGET – HALF OF WELLS
WILL BE HORIZONTAL
NE NE
BCBC/NW
/ NW AB
AB
Total Company
2
Vertical
14
109 102
NE BC/NW AB
REDWATER
Horizontal
2010 Budget Well Count
211 Operated Wells (196 Net)
91 Partner Operated (18 Net)
PEMBINA
16
16
CENTRAL AB
SE AB / SW SK
SE AB/SW SK
SE SK/MB
50
10
DAWSON
BRITISH COLUMBIA
DAWSON
RESERVES DETAILS
• Reserves
Dec. 31, 2009(1)
- Proved Developed Producing
131 Bcfe (21.8 mmboe)
- Total Proved
403 Bcfe (67.2 mmboe)
- Proved + Prob
610 Bcfe (101.8 mmboe)
- Produced to Date
70 Bcfe
• Working interest - Generally 100% surface to basement
• Reserve life index - 25 years (at current production levels)
• Production split - 99% natural gas
• Number of Wells - 19 producing horizontal wells,13 hz wells drilled and
completed and 15 horizontal wells drilled and waiting on completion
• ARC produces through 3 compression units at the 1-34 field site. All production is
processed through third party facilities in Alberta (30 mmcf/d @ Pouce 5-23) and
British Columbia (16 mmcf/d @ West Doe)
[1] See February 9, 2010 news release “ARC Energy Trust Announces 2009 Year End Reserves Information” which was filed with SEDAR and
can be found at www.sedar.com. The estimate of total proved reserves for the Dawson properties may not reflect the same confidence level as
estimates of all properties due to the effects of aggregation.
11
MONTNEY LANDS
MAJOR GROWTH ENGINE
Saturn/Monias –
19 net sections
5.0 Tcf
Sunrise/Sunset/Groundbirch
31.5 net sections
Sundown 18
net sections
3.4 Tcf
• Dawson and the West
Montney lands are a
significant growth engine for
ARC
• With greater than 8 Tcf of
gas classified as Discovered
Petroleum Initially in Place,
ARC’s current plans call for
the construction of three 60
mmcf/d gas plants over the
2010 – 2012 time period
• First phase on production
Q2 2010
[1] Discovered Petroleum Initially in Place [DPIIP], Is defined in the COGEH handbook as the quantity of hydrocarbons that are estimated to be in place within a known
accumulation. DPIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources. There is
no certainty that it will be economically viable or technically feasible to produce any portion of this DPIIP except for those identified as proved or probable reserves. At this time all
of the DPIIP not classified as reserves would be classified as Unrecoverable Resources.
12
DAWSON RESERVES
STILL MORE TO COME?
• What will the ultimate recovery factor
be for the Montney at Dawson?
- With 2.3 Tcf of gas classified as
DPIIP in the core of Dawson, the
current reserve estimate provides
a 30 per cent recovery factor
- There are an additional 1.1 Tcf of
gas classified as DPIIP on lands
with no reserves assigned for a
total DPIIP on ARC lands of 3.4
Tcf
P+P
Produced
Remaining
Resources
[1] Discovered Petroleum Initially in Place [DPIIP], Is defined in the COGEH handbook as the quantity of hydrocarbons that are estimated to be in place within a
known accumulation. DPIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and
contingent resources. There is no certainty that it will be economically viable or technically feasible to produce any portion of this DPIIP except for those identified
as proved or probable reserves. At this time all of the DPIIP not classified as reserves would be classified as Unrecoverable Resources.
13
WEST MONTNEY RESOURCE
5.0 TCF GAS
• 5.0 Tcf of gas classified as DPIIP
- 10 vertical wells drilled to June 30,
2009
- 4 horizontal wells drilled off of 3 of the
discovery wells
13-24
2009 Sunrise
Development
- Sunset 13-24 well indicates excellent
rock quality based on logs – NW
extension of Sunrise
• P+P Reserves of 190 Bcf at year-end
2009
• Participating in small, partner
operated development at Sunrise
- 10 mmcf/d net to ARC
[1] Discovered Petroleum Initially in Place [DPIIP], Is defined in the COGEH handbook as the quantity of hydrocarbons that are estimated to be in place within
a known accumulation. DPIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and
contingent resources. There is no certainty that it will be economically viable or technically feasible to produce any portion of this DPIIP except for those
identified as proved or probable reserves. At this time all of the DPIIP not classified as reserves would be classified as Unrecoverable Resources.
14
TYPE CURVE COMPARISON
MONTNEY IS AMONG THE BEST
12,000
Haynesville
Barnett
Marcellus
Montney
10,000
mcf
8,000
6,000
4,000
2,000
0
1
3
5
7
9
11
13
15
17
19
21
23
25
27
29
31
33
35
Montney type curve from ARC Dawson area, others from Chesapeake investor
presentation.
37
16
MONTNEY TYPE CURVE
GEOLOGY MATTERS
5,000
4,500
Dawson
Sunrise/Groundbirch
Production (mcf/d)
4,000
Swan/Tupper
3,500
all wells
3,000
Northwest
2,500
Alberta
2,000
1,500
1,000
500
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 36
Months
16
DRIVING COSTS DOWN
• Decreased drilling cost per meter
from average ~$753/m to ~$398/m
– Increased ownership of well
construction design
• BHA selection
• ROP control
• Procurement
• Best wellbore for best price
• Decreased horizontal well
completion costs by an average of
30% per interval
– ~40% due to increased operational
efficiencies (pad operations, time,
simplified stimulation design, etc.)
– Remaining decrease due to market
conditions
Drilling Costs Per Meter ($/m)
$1,200
$1,025
$907
$1,000
$753
$800
$600
$398
$400
$200
$0
2006
2007
2008
2009
Completion Cost Per Interval (1000$/interval)
$900
$816
$800
$700
$600
$500
$400
$300
$200
$100
$0
2006
2007
2008
2009
18
DAWSON
DEVELOPMENT ECONOMICS
2009 Hz Well (GLJ 07/09 Forecast)
•
•
•
•
Avg. well depth
Avg. well cost
Expected IP
Expected res.
2000 m
$5.5mm
5 mmcf/d
5 Bcf
•
•
Royalties
Op. costs
27%
1.00 $/mcf
AFTER TAX Rate of Return - %
Gas
$/mcf
4 Bcf
GLJ Jan/10
Price Deck
72
$3.00
Flat
6
$4.00
Flat
23
$5.00
Flat
6
45
4
5
Production
profile (mmcf/d)
3
5 Bcf
115
15
40
75
2
1
6 Bcf
169
25
60
113
0
•Deep drill royalty credit ~1$MM applied to all cases
•Royalties noted (26%) based on approximate subsequent year royalty rate after credit is drawn down
•Assumes one month lag from capital spend to production date
19
2010 MONTNEY
DEVELOPMENT PLANS
• Main Dawson field
– Drill 32 horizontal wells
– Commission 60 mmcf/d gas plant
in early Q2 2010
– Begin construction of 60 mmcf/d
Phase 2 plant – on stream Q1
2011
• Montney West Lands
– Drill 5 horizontal delineation wells
and 3 vertical exploratory wells
– Preliminary work on 60 mmcf/d
gas plant for 2012
– Participate in partner operated 20
mmcf/d development at Sunrise –
10 mmcf/d net to ARC
20
2010 DAWSON GAS PLANT
• Dawson 5-35 Gas Plant
- 60 mmcf/d gas plant under construction – mechanical completed
- Start-up procedures initiated, expect sales gas in the month of May
- Second plan will be a “mirror image” of the first – target completion in Q1,
2011
21
DAWSON PRODUCTION FORECAST
• Staged growth phase
- 60 mmcf/d gas plant to be commissioned in April 2010
- Second 60 mmcf/d gas plant to be on stream Q1 2011
Forecast
180
Phase 2 Plant ~160 mmcf/d
160
Production (mmcf/d)
140
120
100
Phase 1 Plant ~105 mmcf/d
2009+
2008
80
BASE (2002-2007)
Actual
Forecast
60
40
20
0
Date
21
ANTE CREEK
ANTE CREEK
ASSET DETAILS
• Current production
7,000 boe/d
• Reserves*
33 mmboe
• Working interest
≈98%
• Reserve life index
13 years
• Production split
46% oil & NGLs / 54% natural gas
• Average vertical rate
36 boe/d
Average horizontal rate
169 boe/d
• ARC has ownership in two major facilities in the region. 95% of the oil
and 45% of the gas is first processed through the 100% ARC owned
north facility and then flows to a 3rd party gas plant; the remaining
production is processed at the 100% ARC owned southern 10-36 plant
[*] See Dec. 14, 2009 news release “ARC Energy Trust Announces Strategic Acquisition and Concurrent Financing” which was filed with SEDAR and can
be found at www.sedar.com . This reserve number is an estimate based on adding the acquired reserves (at Sept. 30, 2009 and the year-end 2008
reserves for the existing property.
22
2010 01
2009 09
2009 05
2009 01
2008 09
2008 05
2008 01
2007 09
2007 05
2007 01
2006 09
2006 05
2006 01
2005 09
2005 05
2005 01
2004 09
2004 05
2004 01
2003 09
2003 05
2003 01
2002 09
2002 05
7,000
2002 01
8,000
2001 09
2001 05
2001 01
Boe/d
ANTE CREEK
PRODUCTION GROWTH
NGL BOE/Day
Gas BOE/Day
Oil BOE/Day
6,000
5,000
4,000
3,000
2,000
1,000
-
23
ANTE CREEK
FUTURE OPPORTUNITIES
• December acquisition increased
production to 7,000 boe/day and land
holdings by 70 per cent at Ante Creek
• Horizontal multi stage completions have
been very successful – 30 day
production rates have averaged 500
boe/d – as opposed to 100 boe/d for a
vertical well
• 2010 budget of $70 mm – drill 14
horizontal wells and expand facilities
• Significant growth in production and
reserves
24
PEMBINA
ALBERTA
PEMBINA
ARC OPERATIONS
•
Current production
6,374 boe/d operated (6,456 boe/d including
non-operated) from the Cardium
•
Reserves
40.8 mmboe (operated)
•
Working interest
66.1% (operated)
•
Reserve life index
17.8 years (based on GLJ 2P production est.)
•
Production split
83% oil & NGLs / 17% gas
•
Average well rate
9.9 boe/d
•
Average water cut
93%
•
Current operated Pembina production is focused in Berrymoor, Lindale, MIPA and
the North Pembina Cardium Unit #1, which is centered on the town of Drayton
Valley
•
Pembina production is processed through 7 ARC operated oil facilities,
ARC operated gas plant and 2 major water handling stations
1
25
PEMBINA
ARC’S HOLDINGS
Gross Operated Wells in the
Pembina Cardium
# Wells
Berrymoor
NPCU
Lindale
MIPA
SPCU
Penn West
2,359
41%
ARC
1,415
25%
Bonterra
649
12%
Imperial
383
6%
Enerplus
330
6%
Triaxon (Penn
West)
159
3%
True
145
3%
•
ARC is the second largest operator in the
Pembina area
•
Pembina has been a core holding of ARC
since inception – July 1996
•
Currently own an interest in 290 sections –
125 net in the main Cardium trend. Most
are in the Pembina area
26
PEMBINA
HORIZONTAL DRILLING PLANS
• Drilled and completed five horizontal wells in Pembina in the first half of the
year – 1 well in NPCU, 3 wells in Powerhouse and 1 well in the Lindale
Cardium unit. Three of the wells were targeted in an area of the reservoir
that could not be accessed with conventional drilling
• Initial production results are encouraging – average IP rates
are 150 – 200 boe/d
• Geology of the Pembina field is quite variable – need to test the application
in several different geologic environments before we can estimate where
horizontal completion technology can be effectively applied
2010 Budget
• $54 mm – 16 vertical and 16 horizontal wells
28
PEMBINA – 30 DAY INITIAL
PRODUCTION RATES
900
800
Calendar Rate Peek Rate*(bbl/day)
700
600
500
400
300
200
100
0
1
3
5
7
9
11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63
Rank
* Some wells have been shifted by three months to obtain peak rate
27
HORIZONTAL WELLS “TYPE CURVES”
• Given the vertical and horizontal variability in the reservoir, it is not
surprising that there is great variability for production curves
300.0
250.0
Cal Oil Rate (bbl/d)
200.0
150.0
100.0
50.0
0.0
0
5
10
15
Month
20
25
30
29
2010 CAPITAL PROGRAM
($ Millions)
Development
Development – Facilities
Maintenance
Optimization
Land & Seismic
Unconventional Gas
Enhanced Oil Recovery (EOR)
Exploration
Other*
TOTAL
Operated Wells Drilled (gross)
*
2008
2009(e)
2010(b)
232
13
21
12
139
22
51
45
14
174
75
12
9
11
20
28
14
22
380
55
23
14
7
8
40
48
35
$549
$365
$610
232
147
211
Increase in Other for 2009 and 2010 is for leasehold improvements for new office space
2009(e) - Current estimate for 2009
2010(b) - Current budget for 2010
Additional details can be found in our November 5, 2009 news release titled “ARC Energy Trust Announces a $575 Million Capital Budget for 2010”
38
2010 GUIDANCE
Production
2008 (Actual)
2009 (Estimate)
2010 (Budget)
28,513
27,500
27,600 –28,500
NGLs (bbls/d)
3,861
3,500
3,400 – 3,500
Gas (mmcf/d)
196.5
195
237 – 243
Total (boe/d)
65,126
63,500
70,500 – 72,500
2008 (Actual)
2009 (Estimate)
2010 (Budget)
10.13
10.50
10.30
Transportation costs
0.80
0.90
1.00
G&A expenses
2.48
2.10
2.85
Interest
1.39
1.30
1.40
Weighted average units outstanding
including units held for exchangeable
shares (millions)
216
238
251
Oil (bbls/d)
Costs and Expenses ($/boe)
Operating costs
The 2010 Guidance provides unitholders with information on Management’s expectations for results of operations, excluding any acquisitions for
2010. Readers are cautioned that the 2010 Guidance may not be appropriate for other purposes.
39
WHERE TO FROM HERE?
• Our structure will change, BUT
• Our vision will not:
– Leading oil and gas entity as measured by:
• Quality of assets
• Leadership
• Long-term return to investors
• Risk managed value creation
• We have purposely targeted assets that we believe are ideal for a trust
– Long-life, opportunity rich
• We believe demand for income oriented investments will continue to
grow
30
SUMMARY
• Since inception, our mantra has been “risk managed value creation”
– One way of managing risk, is to stage growth
• We have grown opportunistically, with growth followed by stability
• We expect to continue to provide both growth and income to our
investors
• Near-term growth in production and reserves is expected from defined
projects:
– Three, 60 mmcf/d gas plants planned
• Q2 2010, Q1 2011 and Q1 2012
• Represents 30,000 boe/d of new production on a 63,500 boe/d base
– Application of horizontal drilling and multi-stage fracturing to in the Cardium
(Pembina and Garrington) and the Montney (Ante Creek)
31
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 5, 2009 news release titled “ARC Energy Trust Announces A $575 Million Capital
Budget for 2010”, the December 14, 2009 release titled “ARC Energy Trust Announces Strategic Acquisition
and Concurrent Bought Deal Financing”; and the February 9, 2010 release titled “ARC Energy Trust
Releases 2009 Year-end Reserves Information” 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 Energy Trust please visit our website
www.arcresources.com
Or contact:
Investor Relations
E-mail: [email protected]
T 403.503.8600 F 403.509.6417
Toll Free 1.888.272.4900
ARC Resources Ltd.
1200, 308 – 4 Avenue S.W.
Calgary, AB T2P 0H7