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 139 0.56 22 0.10 +525% +460% Distributions % of Cash flow from operating activities 75 0.30 47% 82 0.36 66% -8.5% -17% -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 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 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 5

KEY RESERVE INFORMATION Reserves as of December 31, 2009* (mmboe) - Proved Producing 186 (104 mmboe liquids, 490 bcf gas) - Total Proved 270 (116 mmboe liquids, 917 bcf gas) - Proved Plus Probable 379 (153 mmboe liquids, 1,353 bcf gas) - 14.5 year reserve life index Proved Undeveloped 20% INTERNAL DEVELOPMENT - MONTNEY [*] 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 ? Proved Undeveloped 20% 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 Conversion planned for January 1, 2011 with a December 2010 unitholders meeting ARC Resources Unitholders Shareholders Distributions Dividends 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 - Pembina Goodlands GOODLANDS 9

2010 BUDGET – HALF OF WELLS WILL BE HORIZONTAL NE BC/NW AB NE BC/NW AB 2010 Budget Well Count 211 Operated Wells (196 Net) 91 Partner Operated (18 Net) REDWATER PEMBINA CENTRAL AB SE AB/SW SK SE SK/MB 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 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 Saturn/Monias – 19 net sections 3.4 Tcf 5.0 Tcf Sunrise/Sunset/Groundbirch 31.5 net sections Sundown 18 net sections [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 [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 - 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 2009 Sunrise Development 13-24 [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 Montney type curve from ARC Dawson area, others from Chesapeake investor presentation. 16

MONTNEY TYPE CURVE GEOLOGY MATTERS 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 18

DAWSON DEVELOPMENT ECONOMICS 2009 Hz Well (GLJ 07/09 Forecast) Avg. well depth 2000 m Avg. well cost $5.5mm Expected IP 5 mmcf/d Expected res. 5 Bcf Royalties 27% Op. costs 1.00 $/mcf AFTER TAX Rate of Return - % Gas $/mcf GLJ Jan/10 Price Deck $3.00 Flat $4.00 Flat $5.00 Flat 4 Bcf 72 6 23 45 5 Bcf 115 15 40 75 6 Bcf 169 25 60 113 Deep drill royalty credit ~1$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 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

ANTE CREEK PRODUCTION GROWTH 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, 1 ARC operated gas plant and 2 major water handling stations 25

PEMBINA ARC’S HOLDINGS Gross Operated Wells in the Pembina Cardium Berrymoor Lindale NPCU MIPA SPCU # Wells Penn West 2,359 41% ARC 1,415 25% Bonterra 649 12% Imperial 383 6% Enerplus 330 Triaxon (Penn West) 159 3% True 145 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 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 29

2010 CAPITAL PROGRAM 2008 2009(e) 2010(b) Development 232 174 380 Development – Facilities 13 75 55 Maintenance 21 12 23 Optimization 12 9 14 Land & Seismic 139 11 7 Unconventional Gas 22 20 8 Enhanced Oil Recovery (EOR) 51 28 40 Exploration 45 14 48 Other* 14 22 35 TOTAL $549 $365 $610 Operated Wells Drilled (gross) 232 147 211 ($ Millions) * 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 39 Production 2008 (Actual) 2009 (Estimate) 2010 (Budget) Oil (bbls/d) 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 Costs and Expenses ($/boe) Operating costs 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 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

E-mail: ir@arcresources.com T 403.503.8600 F 403.509.6417 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: ir@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