Performance Review

2008 Third Quarter Performance Accomplishments / Financial Update

• During the third quarter, the Trust paid record distributions of $171.3 million ($0.80 per unit). The third quarter distribution increased 33 per cent relative to 2007 and included a $0.20 per unit top-up. The top-up distributions were declared and paid based on strong commodity prices during the quarter.
• Cash flow from operating activities for the quarter was $251.4 million ($1.16 per unit), a 40 per cent increase compared to $179.6 million ($0.85 per unit) in 2007. The increase is primarily a result of a 53 per cent increase in the Trust’s total realized commodity price for the quarter and a five per cent increase in production volumes. Using the more traditional non-GAAP measure of Cash Flow that excludes changes in non-cash working capital and site restoration spending for the quarter, Cash Flow was $278.6 ($1.29 per unit).
• Production for the quarter increased five per cent to 64,325 boe per day compared with the third quarter of 2007 with the growth in production at Dawson accounting for most of the increase in production. Third quarter volumes were marginally decremented for scheduled turnarounds and downtime. The Trust has maintained its full year production guidance of between 64,000 and 65,000 boe per day.
• As WTI oil prices were strong throughout much of the third quarter averaging US$118 per barrel, the Trust posted realized cash risk management hedging losses of $26.8 million on its oil volumes ($34.3 million on total contracts) negatively impacting cash flows in the quarter; however, the Trust was also able to participate in the market prices on approximately 70 per cent of its total third quarter production
• Total capital spending for the quarter, including undeveloped crown land purchases of $18.6 million and net undeveloped land property acquisitions of $13.1 million, was $149.5 million. This amount was funded 79 per cent by the Trust’s cash flow from operating activities and proceeds from the distribution re-investment program (“DRIP”). The Trust has revised the 2008 capital spending guidance down to $530 million from $550 million and intends to finance the fourth quarter capital program with cash flow and available borrowing capacity under existing credit facilities.
• During the third quarter, the Trust drilled 94 wells (83 net) with a 100 per cent success rate on operated properties. The majority of the wells drilled were in the Southeast Alberta area where the Trust drilled 47 gas wells as part of its shallow gas program. Year-to-date, the Trust has drilled 59 gross oil wells and 87 gross gas wells with a 100 per cent success rate.
• The Trust’s board of directors has approved a $585 million capital program in 2009, which will set the stage for considerable production growth in 2010. This program will maintain base production in the order of 64,000 boe per day while accelerating development of the Montney resource play in northeastern British Columbia. The Trust expects to drill 17 wells and construct an ARC operated 60 mmcf per day gas plant in the Dawson area which we expect will increase production to over 72,000 boe per day in 2010. The Trust will also proceed with additional spending on its CO2 pilot project at Redwater with the goal of assessing commercial viability of large scale CO2 sequestration and injection. The Trust will pursue the most cost effective means of financing its 2009 capital program including: a combination of cash flow, existing credit facilities, potential DRIP proceeds and assets dispositions and new borrowings or equity, if necessary. Management will review the 2009 capital program on a regular basis in the context of prevailing economic conditions and make adjustments as deemed necessary to the program, subject to quarterly review by the Trust's Board of Directors.
• The Trust has completed an assessment of the Alberta Government’s New Royalty Framework (”Framework”) and has estimated that the Trust’s average corporate royalty rate will increase from approximately 18 per cent in 2008 to between 20 and 28 percent in 2009 depending upon commodity prices. A table showing the expected sensitivity to commodity prices is included in the MD&A. Currently, 65 per cent of the Trust’s production is in Alberta. The 2009 capital budget proposes to invest 60 per cent of funds outside of Alberta as the Trust can deliver greater levels of return to unitholders in jurisdictions that are not subject to the new Framework.
• The Trust reviewed distribution levels in light of the outlook for commodity prices and the estimated increase in Alberta royalties pursuant to the new Framework in 2009. Following the $0.24 per unit October distribution to be paid November 17, 2008, the monthly distribution will be $0.20 per unit per month. Distribution levels are reviewed regularly and revisions are approved at the discretion of the Board of Directors.
• The recent global economic downturn, decline in commodity prices and resultant declines in global stock markets have had a significant impact on all businesses and individuals and ARC is no exception. The Trust has experienced a significant decline in its trust unit price similar to other oil and gas entities. Additionally, the decline in commodity prices during and subsequent to quarter end will have a direct impact on the Trust’s cash flows, payout ratios and levels of debt funding of capital programs in the future. Likewise, the financial and lending markets have been faced with reduced lending capacity which in turn will result in reduced access to capital and increased borrowing costs for businesses and individuals. The Trust has diligently maintained a conservative capital structure and low debt levels, attributes that are particularly important in light of the current economic situation. At September 30, the Trust’s net debt to annualized cash flow and net debt to total capitalization were 0.8 times and 13 per cent, respectively. While the current economic environment presents challenges, ARC’s business remains strong, our assets are top quality, our financial position is good and our future internal development prospects are the best we have ever had.

Montney Resource Play Development
At Dawson, ARC drilled and completed two delineation wells on the outer edges of the field as well as drilling four deviated infill wells from the 6-25-79-15W6 surface location in the third quarter. With seven wells drilled into section 25, ARC expects to use new completion techniques, microseismic fracture mapping and pressure data acquisition in order to contribute to the understanding of the infill drilling density required to optimally exploit this field. Production from the field averaged approximately 40 mmcf per day, as planned and unplanned maintenance limited the ability of the processing facilities to run at the maximum contracted capacity.

At West Dawson, ARC drilled two horizontal delineation wells at 2-7-79-15W6 with one well targeting the lower Montney and the second targeting the upper Montney horizons. This is the first horizontal well to target the lower Montney within the main Dawson Pool.

Approval has been received from the National Energy Board to construct a 10 mmcf per day gas line from the Dawson field to Fourth Creek in Alberta. ARC expects to have the new line completed by late fourth quarter 2008 with start-up dependent on installation of a new compressor at the Spectra 5-22 location.

ARC has decided to accelerate the construction plans for additional processing capacity for the Dawson field. Engineering and procurement of long lead time items for a 60 mmcf per day gas plant has been initiated. ARC now expects to have this gas plant on-line early in 2010.

ARC engaged GLJ Petroleum Consultants to update the Dawson Montney property reserves evaluation utilizing production and drilling data to the end of the third quarter. As of October 1, 2008 GLJ estimates that there are 416 Bcf [71 mmboe] of Proved plus Probable reserves at Dawson. This is an addition of 171 Bcf [29 mmboe] of Proved reserves and 254 Bcf [43 mmboe] of Proved plus Probable reserves for the Dawson property (based on 6:1 gas/oil boe conversion). Additional information on the revised reserves evaluation for Dawson can be found in the “ARC Energy Trust announces significant increase in Montney Reserves and Land Valuations” news release dated October 30, 2008 and filed on SEDAR at www.sedar.com.

The Trust continues to expand its Montney land base through purchases of land at crown land sales and acquisitions from other companies. The Trust also continues to convert undeveloped lands to developed lands through the drilling of wells. As at the end of the third quarter, the Trust held 148 gross undeveloped sections (123 net) of lands in the Dawson and the Montney West Exploratory Lands. This is up from 96 gross undeveloped sections (87 net) at December 31, 2007.

The Trust began the delineation process of the Sunrise discovery with the drilling of two successful vertical delineation wells, participation in a partner operated horizontal delineation well and the drilling of two horizontal wells. The two horizontal wells were drilled from the 9-13 discovery well into the upper Montney formations. Testing of the ARC operated wells will take place in the fourth quarter, but based on log analysis and the successful testing of a partner operated horizontal well at Sunrise [50 per cent ARC working interest], ARC has allocated funds from its 2009 budget for development of this field.

Elsewhere, ARC had a successful start to the exploratory drilling program on the new Montney lands with the drilling of the Saturn 13-11-81-20W6 vertical well and a subsequent follow-up horizontal well. Drilling of a second vertical well at Saturn, the first wells at Sunset and Monias and two wells at Sundown are expected to take place in the fourth quarter.

Enhanced Oil Recovery Initiatives
The Trust spent $10.1 million during the third quarter of 2008 on enhanced oil recovery (“EOR”) initiatives, including development capital for the Weyburn and Midale CO2 floods in Saskatchewan. The highlight of the quarter was the successful start-up of the Redwater EOR CO2 pilot. Injection commenced on July 29 and has been proceeding smoothly. The Trust expects that it will take 12 to 18 months before it will be known if the pilot has been successful in increasing oil production and has shown potential for a commercial scale EOR scheme.

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