http://www.arcenergytrust.com/news/latestnews.rssNews Releases For ARC Resourcesen-CA17/11/2008 4:37:51 PM21/11/2008 5:58:05 PMCopyright (c) 2008, ARC Resources Ltd.http://blogs.law.harvard.edu/tech/rssARC Resources RSS10http://www.arcenergytrust.com/en-ca/news/article.htm?newsreleaseref=news_1227496CALGARY, Nov. 17, 2008 (Canada NewsWire via COMTEX News Network) -- (AET.UN and ARX - TSX) ARC Energy Trust (the "Trust") announces that the cash distribution to be paid on December 15, 2008, in respect of the November 2008 production, for unitholders of record on November 30, 2008, will be $0.20 per trust unit. The ex-distribution date is November 26, 2008. <p>As at November 17, 2008 the Trust's trailing twelve-month cash distributions, including the November 17, 2008 payment, total $2.72 per trust unit. </p> <p>ARC Energy Trust is one of Canada's largest conventional oil and gas royalty trusts with an enterprise value of approximately $5.2 billion. The Trust expects full year 2008 oil and gas production to average approximately 64,000 to 65,000 barrels of oil equivalent per day from six core areas in western Canada. The Trust's 2008 capital expenditure program remains unchanged, including the ongoing development of its Montney assets. ARC Energy Trust units trade on the TSX under the symbol AET.UN and ARC Resources exchangeable shares trade under the symbol ARX. </p> <p>Note: Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion ratio for natural gas 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. </p> <p>ADVISORY - In the interests of providing ARC unitholders and potential investors with information regarding ARC, including management's assessment of ARC's future plans and operations, certain information contained in this document are forward-looking statements within the meaning of the "safe harbour" provisions of the United States Private Securities Litigation Reform Act of 1995 and the Ontario Securities Commission. Forward-looking statements in this document include, but are not limited to, ARC's internal projections, expectations or beliefs concerning future operating results, and various components thereof; the production and growth potential of its various assets, estimated total production and production growth for 2008 and beyond; the sources, deployment and allocation of expected capital in 2008; and the success of future development drilling prospects. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause ARC's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. </p> <pre> &lt;&lt; ARC RESOURCES LTD. John P. Dielwart, President and Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00001245E %CIK: 0001029509 </p> <p>SOURCE: ARC Energy Trust </p> <p>SOURCE: ARC Resources Ltd. </p> <pre>about ARC Energy Trust, please visit our website www.arcenergytrust.com or contact: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6417, Toll Free 1-888-272-4900, ARC Resources Ltd., Suite 2100, 440 - 2nd Avenue S.W., Calgary, AB, T2P 5E9 </pre> 17/11/2008 4:38:00 PMhttp://www.arcenergytrust.com/en-ca/news/permalink.htm?newsreleaseref=news_1227496http://www.arcenergytrust.com/en-ca/news/article.htm?newsreleaseref=news_1220614CALGARY, Oct. 31, 2008 (Canada NewsWire via COMTEX News Network) -- (AET.UN and ARX - TSX) ARC Resources Ltd. along with ARC Energy Trust announces the increase to the exchange ratio of the exchangeable shares of the corporation from 2.45490 to 2.49032. Such increase will be effective on November 17, 2008. <p>The following are the details on the calculation of the exchange ratio: </p> <pre> &lt;&lt; ------------------------------------------------------------------------- 10 day weighted average trading Effective Record ARC price date of date of Energy of AET.UN the Exchange ARC Energy Trust (prior to Increase increase ratio Trust Opening distrib- the end in in as of distrib- exchange ution of the exchange exchange effective ution ratio per unit month) ratio(xx) ratio date ------------------------------------------------------------------------- October November 31, 2008 2.45490 $0.24 $16.6359 0.03542 17, 2008 2.49032 ------------------------------------------------------------------------- (xx) The increase in the exchange ratio is calculated by dividing the ARC Energy Trust distribution per unit by the 10 day weighted average trading price of AET.UN and multiplying by the opening exchange ratio. &gt;&gt; </pre> <p>A holder of ARC Resources Ltd. exchangeable shares can exchange all or a portion of their holdings at any time by giving notice to their investment advisor or Computershare Investor Services at its principal transfer office in Suite 600, 530 - 8th Avenue SW, Calgary, Alberta, T2P 3S8, their telephone number is 1-800-564-6253 and their website is www.computershare.com. </p> <pre> &lt;&lt; ARC RESOURCES LTD. John P. Dielwart, President and Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00001245E %CIK: 0001029509 </p> <p>SOURCE: ARC Energy Trust </p> <p>SOURCE: ARC Resources Ltd. </p> <pre>about ARC Energy Trust, please visit our website www.arcenergytrust.com or contact: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6417, Toll Free 1-888-272-4900, ARC Resources Ltd., 2100, 440 - 2nd Avenue S.W., Calgary, AB, T2P 5E9 </pre> 31/10/2008 3:22:00 PMhttp://www.arcenergytrust.com/en-ca/news/permalink.htm?newsreleaseref=news_1220614http://www.arcenergytrust.com/en-ca/news/article.htm?newsreleaseref=news_1220329CALGARY, Oct. 30, 2008 (Canada NewsWire via COMTEX News Network) -- (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or "the Trust") announces results for the third quarter and nine months ended September 30, 2008. <pre> &lt;&lt; Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 ------------------------------------------------------------------------- FINANCIAL ($Cdn millions, except per unit and per boe amounts) Revenue before royalties 485.7 300.2 1,405.6 913.6 Per unit(1) 2.24 1.42 6.53 4.36 Per boe 82.06 53.41 78.84 53.73 Cash flow from operating activities(2) 251.4 179.6 734.8 531.2 Per unit(1) 1.16 0.85 3.41 2.54 Per boe 42.48 31.95 41.22 31.23 Net income 311.7 120.8 450.3 389.0 Per unit(3) 1.46 0.58 2.12 1.88 Distributions 171.3 125.0 442.8 372.2 Per unit(1) 0.80 0.60 2.08 1.80 Per cent of cash flow from operating activities(2) 68 70 60 70 Net debt outstanding(4) 773.2 699.8 773.2 699.8 OPERATING Production Crude oil (bbl/d) 28,509 28,437 28,372 28,682 Natural gas (mmcf/d) 192.0 173.3 197.0 177.6 Natural gas liquids (bbl/d) 3,822 3,795 3,862 4,013 Total (boe/d) 64,325 61,108 65,063 62,296 Average prices Crude oil ($/bbl) 114.20 73.40 107.20 66.45 Natural gas ($/mcf) 8.68 5.52 8.94 6.90 Natural gas liquids ($/bbl) 82.87 55.64 77.92 52.07 Oil equivalent ($/boe) 81.42 53.28 78.44 53.61 Operating netback ($/boe) Commodity and other revenue (before hedging)(5) 82.06 53.41 78.84 53.73 Transportation costs (0.80) (0.65) (0.77) (0.73) Royalties (15.00) (8.76) (14.18) (9.28) Operating costs (10.19) (9.93) (10.14) (9.51) Netback (before hedging) 56.07 34.07 53.75 34.21 ------------------------------------------------------------------------- TRUST UNITS (millions) Units outstanding, end of period(6) 217.4 208.8 217.4 208.8 Weighted average units(7) 216.6 210.9 215.2 209.4 ------------------------------------------------------------------------- TRUST UNIT TRADING STATISTICS ($Cdn, except volumes) based on intra-day trading High 33.30 22.60 33.95 23.86 Low 22.33 19.00 20.00 19.00 Close 23.10 21.17 23.10 21.17 Average daily volume (thousands) 841 503 790 588 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Per unit amounts (with the exception of per unit distributions) are based on weighted average trust units outstanding plus trust units issuable for exchangeable shares. Per unit distributions are based on the number of trust units outstanding at each distribution record date. (2) Cash flow from operating activities is a GAAP measure. Historically, management has disclosed Cash Flow, as a non-GAAP measure calculated using cash flow from operating activities less the change in non-cash working capital and the expenditures on site restoration and reclamation as they appear on the Consolidated Statements of Cash Flows. Cash Flow for the third quarter of 2008 would be $278.6 million ($1.29 per unit) and $763.5 million ($3.55 per unit) year-to-date. Distributions as a percentage of Cash Flow would be 61 per cent for the third quarter of 2008 (58 per cent year-to-date). Please refer to the non-GAAP measures section in the MD&amp;A for further details. (3) Net income per unit is based on net income after non-controlling interest divided by weighted average trust units outstanding (excluding trust units issuable for exchangeable shares). (4) Net debt excludes current unrealized amounts pertaining to risk management contracts and the current portion of future income taxes. (5) Includes other revenue. (6) Includes 1.1 million exchangeable shares exchangeable into 2.43068 trust units each for an aggregate 2.7 million trust units. (7) Includes trust units issuable for outstanding exchangeable shares at period end. HIGHLIGHTS AND ACCOMPLISHMENTS ------------------------------ - 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 CO(2) pilot project at Redwater with the goal of assessing commercial viability of large scale CO(2) sequestration and injection. The Trust will pursue the 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. The Trust will pursue the most cost effective means of financing its 2009 capital program through a combination of cash flow, existing credit facilities, DRIP proceeds, potential asset disposition proceeds 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&amp;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 CO(2) floods in Saskatchewan. The highlight of the quarter was the successful start-up of the Redwater EOR CO(2) 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. MANAGEMENT'S DISCUSSION AND ANALYSIS ------------------------------------ &gt;&gt; </pre> <p>This management's discussion and analysis ("MD&amp;A") is the Trust management's analysis of its financial performance and significant trends or external factors that may affect future performance. It is dated October 29, 2008 and should be read in conjunction with the unaudited Consolidated Financial Statements for the period ended September 30, 2008, the MD&amp;A and the unaudited Consolidated Financial Statements for the period ended June 30, 2008, the MD&amp;A and the unaudited Consolidated Financial Statements for the period ended March 31, 2008, and the audited Consolidated Financial Statements and MD&amp;A for the period ended December 31, 2007 as well as the Trust's 2007 Annual Information Form that is filed on SEDAR at www.sedar.com. </p> <p>The MD&amp;A contains forward-looking statements and readers are cautioned that the MD&amp;A should be read in conjunction with the Trust's disclosure under "Forward-Looking Statements" included at the end of this MD&amp;A. </p> <p>Executive Overview </p> <p>ARC Energy Trust ("ARC") is one of the top 20 producers of conventional oil and gas in western Canada. As at September 30, 2008, ARC held interests in excess of 18,000 wells with approximately 5,500 wells operated by ARC and the remainder operated primarily by other major oil and gas companies. ARC's production has averaged between 61,000 and 67,000 boe per day in each quarter for the last three years. The total capitalization of ARC, which trades on the Toronto Stock Exchange, as at September 30, 2008 was $5.8 billion as shown on Table 21. Subsequent to quarter end, the market has experienced a high degree of volatility and Trust has seen a decrease in total capitalization to approximately $4.4 billion on October 29, 2008. </p> <pre> &lt;&lt; ARC's objective as an energy company is to provide superior and sustainable long-term returns to unitholders. Key attributes to the business plan include: - Concentrated activities in three major areas: conventional oil and natural gas assets, resource plays and enhanced oil recovery initiatives. In addition to these major initiatives, ARC continually reviews acquisition and disposition opportunities to high grade its asset base and provide future growth opportunities. - Pay a portion of cash flow to unitholders annually. The Trust will distribute $0.24 per unit for the November 17, 2008 distribution; thereafter the distribution is set at $0.20 per unit beginning with the December 15, 2008 distribution. The remainder of the cash flow is used to fund reclamation costs and a portion of capital expenditures and land acquisitions. Since the Trust's inception in July 1996 to September 30, 2008, the Trust has distributed $3.1 billion or $23.11 per unit. - Annual replacement of production and reserves through drilling new wells and associated oil and natural gas development activities. The vast majority of the annual capital budget is being deployed on a balanced drilling program of low and moderate risk wells, well tie- ins and other related costs, and the acquisition of undeveloped land. The Trust continues to focus on major properties with significant upside, with the objective to replace production declines through internal development opportunities. Table 1 illustrates ARC's production and reserves per unit that have been achieved while making distributions since January 1, 2006, of $6.88 per unit or $1.5 billion. Table 1 --------------------------------------------------------------------- Per Trust Unit Q3 2008 YTD 2008 2007 2006 --------------------------------------------------------------------- Normalized production per unit(1) 0.30 0.31 0.30 0.31 Normalized reserves per unit(1)(2) - - 1.35 1.40 Distributions per unit $0.80 $2.08 $2.40 $2.40 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Normalized indicates that all years as presented have been adjusted to reflect a net debt to capitalization of 15 per cent. It is assumed that additional trust units were issued (or repurchased) at a period end price for the reserves per unit calculation and at an annual average price for the production per unit calculation in order to achieve a net debt balance of 15 per cent of total capitalization each year. The normalized amounts are presented to enable comparability of annual per unit values. (2) Reserves per unit are only calculated on an annual basis when the Trust has a full independent reserve evaluation prepared. - The periodic strategic acquisition of producing and undeveloped properties to enhance current production or provide the potential for future drilling locations and if successful, additional production and reserves. - Using prudent production practices to maximize the recovery of oil and natural gas from the reservoirs. - Controlling costs for both routine operating expenditures and costs incurred for capital projects. ARC expects that the aggregate amount of operating costs will increase over time as ARC adds approximately 300 wells per year to its operating base to replace the natural decline on existing producing wells. ARC's business plan and operating practices also include the following strategies and action plans that are being undertaken to increase ARC's competitiveness and future profitability: - Continual development of staff expertise and the hiring and retention of some of the industry's best and most qualified personnel. - Building relationships with suppliers, joint venture partners, government and other stakeholders and conducting business in a fair and equitable manner. - Promoting the use of proven and effective technologies to enhance the recoverable resources in place and reduce costs. - Being an industry leader in health, safety and environmental performance. - Actively supporting local initiatives and charities in the communities in which we live and work. The effectiveness of ARC's business plan can best be measured by historical results as shown in Table 2. Investors and unitholders will appreciate that commodity prices are a significant factor in determining profitability and market returns of the units, however the combination of appreciating commodity prices and the successful execution of ARC's business plan has resulted in the following returns to unitholders: Table 2 ------------------------------------------------------------------------- Total Returns(1) Trailing Trailing Trailing ($ per unit except for per cent) One Year Three Year Five Year ------------------------------------------------------------------------- Distributions per unit $ 2.68 $ 7.48 $ 11.27 Capital appreciation per unit $ 2.39 $ 0.74 $ 9.50 Total return per unit $ 5.07 $ 8.22 $ 20.77 Annualized total return per unit 21.2% 9.1% 23.3% ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Calculated as at September 30, 2008. 2008 Guidance Table 3 is a summary of the Trust's 2008 Revised Guidance and a review of 2008 actual results compared to guidance: Table 3 ------------------------------------------------------------------------- September 2008 Actual Guidance 2008 YTD ------------------------------------------------------------------------- Production (boe/d) 64,000-65,000 65,063 ------------------------------------------------------------------------- Expenses ($/boe): Operating costs 10.20 10.14 Transportation 0.80 0.77 G&amp;A expenses(1) 2.75 2.65 Interest 1.50 1.39 Capital expenditures ($ millions)(2) 530 379.1 Weighted average trust units and units issuable (millions) 216 217 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) G&amp;A guidance has been revised from the original estimate of $3.15 per boe. The components of the $2.75 per boe G&amp;A guidance for the full year are as follows: cash G&amp;A - $1.70 perboe; cash component of LTIP -$0.90 per boe; non-cash LTIP component - $0.15 per boe (2) 2008 Capital Expenditure Guidance has been revised downward to $530 million from the original estimate of $550 million. &gt;&gt; </pre> <p>The 2008 Guidance provides unitholders with information as to management's expectations for results of operations for 2008. Readers are cautioned that the 2008 Guidance may not be appropriate for other purposes. </p> <p>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. </p> <p>Actual results for the first nine months of 2008 were in line with 2008 guidance with some minor exceptions as follows: </p> <pre> &lt;&lt; - G&amp;A expenses of $2.65 per boe were lower than initial guidance of $3.15 per boe due to the decrease in the Trust's unit price at quarter-end that resulted in a lower non-cash LTIP expense. Full year G&amp;A cash expenses are still expected to be in line with guidance while total G&amp;A may fluctuate due to the variability of the Trust's unit price. The Trust has lowered the cash LTIP expense to $0.90 per boe from $1.00 per boe and the non-cash LTIP expense to $0.15 per boe from $0.44 per boe based on the reduction in the unit price. - Capital expenditures guidance included amounts that the Trust anticipated spending on crown land acquisitions throughout the year, however, it was difficult to know the success rate that the Trust would have in the silent bid process used for crown land sales. At this time, the Trust is revising its guidance to $530 million down from the original guidance of $550 million. &gt;&gt; </pre> <p>Non-GAAP Measures </p> <p>Historically, management used the non-GAAP measure Cash Flow or cash flow from operations to analyze operating performance, leverage and liquidity. We have now chosen to use the GAAP measure cash flow from operating activities instead of Cash Flow or cash flow from operations. There are two differences between the two measures and cash flow from operating activities: positive or negative changes in non-cash working capital and the deduction of expenditures on site restoration and reclamation as they appear on the Consolidated Statements of Cash Flows. Although management feels that Cash Flow, or cash flow from operations, is a valued measure of funds generated by the Trust during the reported quarter, we have changed our disclosure to only discuss the GAAP measure in the MD&amp;A in order to avoid any potential confusion by readers of our financial information and in our opinion, to more fully comply with the intent of certain regulatory requirements. </p> <p>Our historical measure of Cash Flow reflected revenues and costs for the three months reported in the quarter. This amount, however, comprised accruals for at least one month of revenue and approximately two months of costs. The oil and gas industry is designed such that revenues are typically collected on the 25th day of the month following the actual production month. Royalties are typically paid two months following the actual production month and operating costs are paid as the invoices are received. This can take several months; however, most invoices for operated properties are paid within approximately two months of the production month. In the event that commodity prices and or volumes have changed significantly from the last month of the previous reporting period over the last month of the current reporting period, a difference could occur between cash flow from operating activities and our historical non-GAAP measure of Cash Flow or cash flow from operations. Additionally, periods where the Trust spends a significant amount on site restoration and reclamation would result in a difference between cash flow from operating activities and Cash Flow or cash flow from operations. </p> <p>At the time of writing this MD&amp;A, substantially all revenues have been collected for the production period of September 2008. Management performs analysis on the amounts collected to ensure that the amounts accrued for September are accurate. Analysis is also performed regularly on royalties and operating costs to ensure that amounts have been accurately accrued. </p> <p>Management uses certain key performance indicators ("KPIs") and industry benchmarks such as distributions as a per cent of cash flow from operating activities, operating netbacks ("netbacks"), total capitalization, finding, development and acquisition costs, recycle ratio, reserve life index, reserves per unit and production per unit to analyze financial and operating performance. Management feels that these KPIs and benchmarks are key measures of profitability and overall sustainability for the Trust. These KPIs and benchmarks as presented do not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures for other entities. </p> <pre> &lt;&lt; 2008 Third Quarter Financial and Operational Results Financial Highlights Table 4 ------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30 September 30 ------------------------------------------------------------------------- (Cdn $ millions, except per unit % % and volume data) 2008 2007 Change 2008 2007 Change ------------------------------------------------------------------------- Cash flow from operating activities 251.4 179.6 40 734.8 531.2 38 Cash flow from operating activities per unit(1) 1.16 0.85 36 3.41 2.54 34 Net income 311.7 120.8 158 450.3 389.0 16 Net income per unit(2) 1.46 0.58 152 2.12 1.88 13 Distributions per unit(3) 0.80 0.60 33 2.08 1.80 16 Distributions as a per cent of cash flow from operating activities 68 70 (3) 60 70 (14) Average daily production (boe/d)(4) 64,325 61,108 5 65,063 62,296 4 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Per unit amounts are based on weighted average trust units outstanding plus trust units issuable for exchangeable shares at year-end. (2) Based on net income after non-controlling interest divided by weighted average trust units outstanding excluding trust units issuable for exchangeable shares. (3) Based on number of trust units outstanding at each cash distribution date. (4) Reported production amount is based on company interest before royalty burdens. Where applicable in this MD&amp;A natural gas has been converted to barrels of oil equivalent ("boe") based on 6 mcf: 1 bbl. The boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the well head. Use of the term boe in isolation may be misleading. &gt;&gt; </pre> <p>Net Income </p> <p>Net income in the third quarter of 2008 was $311.7 million ($1.46 per unit), an increase of $190.9 million from $120.8 million ($0.58 per unit) in 2007. While cash flow from operating activities increased $71.8 million in the third quarter of 2008 compared to the same period in 2007 (see Table 6 for details), there were several non-cash items that impacted the Trust's net income in the current quarter as follows: </p> <pre> &lt;&lt; - The Trust recorded a $187.5 million unrealized gain on risk management contracts, a $185.4 million increase compared to an unrealized gain of $2.1 million for the same period of 2007. The unrealized gain was attributed to the decline in commodity prices during the third quarter. - The Trust recorded a $15.5 million non-cash foreign exchange loss on its U.S. denominated debt as a result of the weakening of the Canadian dollar relative to the U.S. dollar during the quarter compared to a non-cash gain of $25.7 million in 2007. - The Trust recorded a non-cash G&amp;A recovery of $5.5 million in the third quarter compared to a non-cash expense of $3.7 million in 2007 on the Trust's Long-term incentive plan due to the decrease in the trust unit price in the quarter. - The Trust recorded a $48.4 million future income tax expense for the third quarter of 2008 compared to a $6.3 million recovery in 2007. The future income tax expense was attributed to the unrealized gain on risk management contracts in the quarter. &gt;&gt; </pre> <p>A measure of sustainability is the comparison of net income to distributions. Net income incorporates all costs including depletion expense and other non-cash expenses whereas cash flow from operating activities measures the cash generated in a given period before the cost of acquiring or replacing the associated reserves produced. Therefore, net income may be more representative of the profitability of the entity and thus a relevant measure against which to measure distributions to illustrate sustainability. As net income is sensitive to fluctuations in commodity prices and the impact of risk management contracts, currency fluctuations and other non-cash items, it is expected that there will be deviations between annual net income and distributions. Table 5 illustrates the annual shortfall of distributions to net income as a measure of long-term sustainability. </p> <pre> &lt;&lt; Table 5 ------------------------------------------------------------------------- Net income and Distributions ($ millions except per cent) Q3 2008 YTD 2008 2007 2006 ------------------------------------------------------------------------- Net income 311.7 450.3 495.3 460.1 Distributions 171.3 442.8 498.0 484.2 ------------------------------------------------------------------------- Excess (Shortfall) 140.4 7.5 (2.7) (24.1) Excess (Shortfall) as per cent of net income 45% 2% (1%) (5%) Distributions as a per cent of cash flow from operating activities 68% 60% 71% 66% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash Flow from Operating Activities Cash flow from operating activities increased by 40 per cent in the third quarter of 2008 to $251.4 million from $179.6 million in the third quarter of 2007. The increase in third quarter 2008 cash flow from operating activities is detailed in Table 6. Table 6 ------------------------------------------------------------------------- ($ per (% ($ millions) trust unit) variance) ------------------------------------------------------------------------- Q3 2007 Cash flow from Operating Activities 179.6 0.85 - ------------------------------------------------------------------------- Volume variance 15.8 0.07 9 Price variance 169.6 0.80 94 Cash losses on risk management contracts (42.3) (0.19) (24) Royalties (39.6) (0.19) (22) Expenses: Transportation (1.2) (0.01) (1) Operating(1) (6.6) (0.03) (4) Cash G&amp;A (0.6) - - Interest 0.8 - - Realized foreign exchange gain / loss (0.8) - - Weighted average trust units - (0.03) - Non-cash and other items(2) (23.3) (0.11) (13) ------------------------------------------------------------------------- Q3 2008 Cash flow from Operating Activities 251.4 1.16 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Excludes non-cash portion of LTIP expense recorded in operating costs. (2) Includes the changes in non-cash working capital and expenditures on site restoration and reclamation. Year-to-date cash flow from operating activities increased by 38 per cent in 2008 to $734.8 million from $531.2 million in the first nine months of 2007. The increase in 2008 cash flow from operating activities is detailed in Table 6a. Table 6a ------------------------------------------------------------------------- ($ per (% ($ millions) trust unit) variance) ------------------------------------------------------------------------- YTD 2007 Cash flow from Operating Activities 531.2 2.54 - ------------------------------------------------------------------------- Volume variance 44.1 0.21 8 Price variance 447.8 2.14 84 Cash losses on risk management contracts (123.8) (0.60) (23) Royalties (95.0) (0.45) (18) Expenses: Transportation (1.4) (0.01) - Operating(1) (18.8) (0.09) (4) Cash G&amp;A (8.1) (0.04) (2) Interest 2.8 0.01 1 Realized foreign exchange gain / loss (0.9) - - Weighted average trust units - (0.09) - Non-cash and other items(2) (43.1) (0.21) (8) ------------------------------------------------------------------------- YTD 2008 Cash flow from Operating Activities 734.8 3.41 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Excludes non-cash portion of LTIP expense recorded in operating costs. (2) Includes the changes in non-cash working capital and expenditures on site restoration and reclamation. 2008 Cash Flow from Operating Activities Sensitivity Table 7 illustrates sensitivities to pre-hedged operating income items with operational changes and changes to the business environment: Table 7 ------------------------------------------------------------------------- Impact on Annual Cash flow from operating activities(2) ------------------------------------------------------------------------- Business Environment Assumption Change $/Unit ------------------------------------------------------------------------- Oil price (US$WTI/bbl)(1) $ 107.10 $ 1.00 $ 0.04 Natural gas price (Cdn $AECO/mcf)(1) $ 8.40 $ 0.10 $ 0.03 Cdn$/US$ exchange rate $ 1.04 $ 0.01 $ 0.05 Interest rate on floating rate debt % 4.0 % 1.0 $ 0.03 Operational Liquids production volume (bbl/d) 31,500 % 1.0 $ 0.05 Natural gas production volumes (mmcf/d) 195.5 % 1.0 $ 0.02 Operating expenses per boe $ 10.20 % 1.0 $ 0.01 Cash G&amp;A expenses per boe $ 2.60 % 10.0 $ 0.03 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Analysis does not include the effect of hedging contracts. (2) Assumes constant working capital. Production Table 8 ------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30 September 30 ------------------------------------------------------------------------- % % Production 2008 2007 Change 2008 2007 Change ------------------------------------------------------------------------- Light &amp; medium crude oil (bbl/d) 27,211 27,207 - 27,073 27,353 (1) Heavy oil (bbl/d) 1,298 1,230 6 1,299 1,329 (2) Natural gas (mmcf/d) 192.0 173.3 11 197.0 177.6 11 NGL (bbl/d) 3,822 3,795 1 3,862 4,013 (4) ------------------------------------------------------------------------- Total production (boe/d)(1) 64,325 61,108 5 65,063 62,296 4 % Natural gas production 50 47 6 50 48 4 % Crude oil and liquids production 50 53 (6) 50 52 (4) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Reported production for a period may include minor adjustments from previous production periods. &gt;&gt; </pre> <p>Production volumes averaged 64,325 boe per day in the third quarter of 2008 up five per cent from the same period in 2007. The majority of the increase in volumes was from the Dawson area due to the start-up of a third party gas plant in the fourth quarter of 2007. The volumes were in line with management's expectations and incorporated minor downtime for planned turnarounds that were completed during the quarter. The Trust is maintaining its full year production guidance at 64,000 to 65,000 boe per day. </p> <pre> &lt;&lt; Table 9 summarizes the Trust's third quarter production by core area: Table 9 ------------------------------------------------------------------------- Three Months Ended September 30, 2008 ------------------------------------------------------------------------- Production Total Oil Gas NGL Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d) ------------------------------------------------------------------------- Central AB 7,428 1,380 29.0 1,218 Northern AB &amp; BC 21,705 5,112 90.2 1,553 Pembina &amp; Redwater 13,972 9,866 19.1 921 S.E. AB &amp; S.W. Sask. 9,629 977 51.9 8 S.E. Sask. &amp; MB 11,591 11,175 1.8 122 ------------------------------------------------------------------------- Total 64,325 28,510 192.0 3,822 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Three Months Ended September 30, 2007 ------------------------------------------------------------------------- Production Total Oil Gas NGL Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d) ------------------------------------------------------------------------- Central AB 7,694 1,522 29.6 1,234 Northern AB &amp; BC 19,106 5,776 71.2 1,475 Pembina &amp; Redwater 13,497 9,411 18.7 971 S.E. AB &amp; S.W. Sask. 9,679 1,008 52.0 10 S.E. Sask. &amp; MB 11,132 10,720 1.8 105 ------------------------------------------------------------------------- Total 61,108 28,437 173.3 3,795 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Provincial references: AB is Alberta, BC is British Columbia, Sask. is Saskatchewan, MB is Manitoba, S.E. is southeast and S.W. is southwest. Table 9a summarizes the Trust's production by core area for the first nine months of 2008: Table 9a ------------------------------------------------------------------------- Nine Months Ended September 30, 2008 ------------------------------------------------------------------------- Production Total Oil Gas NGL Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d) ------------------------------------------------------------------------- Central AB 7,549 1,405 29.5 1,228 Northern AB &amp; BC 22,550 5,473 93.1 1,553 Pembina &amp; Redwater 13,599 9,405 19.7 911 S.E. AB &amp; S.W. Sask. 9,826 991 52.9 12 S.E. Sask. &amp; MB 11,539 11,098 1.8 158 ------------------------------------------------------------------------- Total 65,063 28,372 197.0 3,862 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Nine Months Ended September 30, 2007 ------------------------------------------------------------------------- Production Total Oil Gas NGL Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d) ------------------------------------------------------------------------- Central AB 7,984 1,644 30.2 1,313 Northern AB &amp; BC 19,545 5,815 73.2 1,526 Pembina &amp; Redwater 13,579 9,378 18.9 1,051 S.E. AB &amp; S.W. Sask. 9,969 1,065 53.4 9 S.E. Sask. &amp; MB 11,218 10,780 1.9 114 ------------------------------------------------------------------------- Total 62,296 28,682 177.6 4,013 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Provincial references: AB is Alberta, BC is British Columbia, Sask. is Saskatchewan, MB is Manitoba, S.E. is southeast and S.W. is southwest. &gt;&gt; </pre> <p>Revenue </p> <p>Revenue increased to $485.7 million for the third quarter of 2008. The increase in revenue was attributable to both higher realized oil prices and increased production volumes. Prior to hedging activities, ARC's total realized commodity price was $82.06 per boe in the third quarter of 2008, a 54 per cent increase from the $53.41 per boe received prior to hedging in 2007. For the nine months ended September 30, 2008, the Trust realized $78.84 per boe, a 47 per cent increase over the realized price of $53.73 per boe received in the comparable period in 2007. Both of these amounts are prior to hedging losses. </p> <pre> &lt;&lt; A breakdown of revenue is as follows in Table 10: Table 10 ------------------------------------------------------------------------- Revenue Three Months Ended Nine Months Ended September 30 September 30 ------------------------------------------------------------------------- % % ($ millions) 2008 2007 Change 2008 2007 Change ------------------------------------------------------------------------- Oil revenue 299.5 192.0 56 833.3 520.3 60 Natural gas revenue 153.3 88.1 74 482.6 334.3 44 NGL revenue 29.1 19.4 50 82.4 57.0 45 ------------------------------------------------------------------------- Total commodity revenue 481.9 299.5 61 1,398.3 911.6 53 Other revenue 3.8 0.7 443 7.3 2.0 265 ------------------------------------------------------------------------- Total revenue 485.7 300.2 62 1,405.6 913.6 54 ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>The oil and natural gas prices realized by the Trust are based upon quality and transportation differentials from major North American commodity postings. The Trust's realized oil price was 94 per cent of the Edmonton posted oil prices, slightly higher than the comparable quarter of 2007 where ARC received 92 per cent. The Trust has not experienced any significant change in the quality composition of its oil production hence the increase in price relative to Edmonton posted prices is due to the strengthening of prices for sour and medium sour blend postings relative to Edmonton posted prices. Approximately 43 per cent of ARC's crude oil production is light sweet oil, 53 per cent is light and medium sour crude with the balance being heavy oil. The Trust's natural gas price of $8.68 per mcf was lower than the AECO monthly average in the quarter of $9.27 per mcf as a portion of the Trust's natural gas production is sold at the AECO daily spot price which averaged $7.75 per mcf during the third quarter. </p> <pre> &lt;&lt; Table 11 ------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30 September 30 ------------------------------------------------------------------------- % % 2008 2007 Change 2008 2007 Change ------------------------------------------------------------------------- Average Benchmark Prices AECO gas ($/mcf)(1) 9.27 5.61 65 8.58 6.81 26 WTI oil (US$/bbl)(2) 118.18 75.33 57 113.39 66.22 71 Cdn$/US$ foreign exchange rate 1.04 1.04 - 1.02 1.10 (7) Edmonton Posted oil (Cdn$/bbl) 121.77 79.78 53 114.99 72.99 58 ------------------------------------------------------------------------- ARC Realized Prices Prior to Hedging Oil ($/bbl) 114.20 73.40 56 107.20 66.45 61 Natural gas ($/mcf) 8.68 5.52 57 8.94 6.90 30 NGL ($/bbl) 82.87 55.64 49 77.91 52.07 50 ------------------------------------------------------------------------- Total commodity revenue before hedging ($/boe) 81.42 53.28 53 78.44 53.61 46 Other revenue ($/boe) 0.64 0.13 392 0.40 0.12 233 ------------------------------------------------------------------------- Total revenue before hedging ($/boe) 82.06 53.41 54 78.84 53.73 47 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Represents the AECO monthly posting. (2) WTI represents West Texas Intermediate posting as denominated in US$. &gt;&gt; </pre> <p>Risk Management and Hedging Activities </p> <p>ARC continues to maintain an ongoing risk management program to reduce the volatility of revenues in order to increase the certainty of distributions, protect acquisition economics, and fund capital expenditures. The risk management program and Board approved parameters are discussed in the Trust's 2007 Annual Report filed on SEDAR and available on the Trust's website - www.arcenergytrust.com. </p> <p>Strong commodity prices throughout the third quarter had a significant positive impact on the Trust's revenue; however, these strong prices resulted in realized cash losses of $34.3 million on the Trust's oil and natural gas risk management contracts. Despite strong average commodity prices during the third quarter, prices decreased late in the quarter and futures prices as of September 30, 2008 were significantly lower than June 30, 2008. Consequently, the Trust recorded a $187.5 million unrealized non-cash mark-to-market gain on risk management contracts. </p> <p>Table 12 is a summary of the total gain (loss) on risk management contracts for the third quarter of 2008 as compared to the same period in 2007. </p> <pre> &lt;&lt; Table 12 ------------------------------------------------------------------------- Risk Management Contracts Crude Oil Natural Foreign ($ millions) &amp; Liquids Gas Currency(3) Power ------------------------------------------------------------------------- Realized cash (loss) gain on contracts(1) (26.9) (7.5) (0.2) - Unrealized (loss) gain on contracts(2) 139.6 39.6 5.6 1.9 ------------------------------------------------------------------------- Total gain (loss) on risk management contracts 112.7 32.1 5.4 1.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- -------------------------------------------------------------- Risk Management Contracts Q3 2008 Q3 2007 ($ millions) Interest Total Total -------------------------------------------------------------- Realized cash (loss) gain on contracts(1) 0.3 (34.3) 8.0 Unrealized (loss) gain on contracts(2) 0.8 187.5 2.1 -------------------------------------------------------------- Total gain (loss) on risk management contracts 1.1 153.2 10.1 -------------------------------------------------------------- -------------------------------------------------------------- (1) Realized cash gains and losses represent actual cash settlements or receipts under the respective contracts. (2) The unrealized (loss) gain on contracts represents the change in fair value of the contracts during the period. (3) Unrealized gain on foreign currency contracts includes a $6.2 million dollar gain on contracts related to repayments of the Trust's U.S. denominated long-term debt. See the Foreign Exchange Gains and Losses section of this MD&amp;A for further details on the debt related contracts. Table 12a ------------------------------------------------------------------------- Risk Management Contracts Crude Oil Natural Foreign ($ millions) &amp; Liquids Gas Currency(3) Power ------------------------------------------------------------------------- Realized cash (loss) gain on contracts(1) (78.0) (17.8) 0.1 - Unrealized (loss) gain on contracts(2) 3.3 13.2 6.5 1.9 ------------------------------------------------------------------------- Total gain (loss) on risk management contracts (74.7) (4.6) 6.6 1.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- -------------------------------------------------------------- Risk Management Contracts YTD 2008 YTD 2007 ($ millions) Interest Total Total -------------------------------------------------------------- Realized cash (loss) gain on contracts(1) (12.8) (108.5) 15.3 Unrealized (loss) gain on contracts(2) 1.1 26.0 (8.0) -------------------------------------------------------------- Total gain (loss) on risk management contracts (11.7) (82.5) 7.3 -------------------------------------------------------------- -------------------------------------------------------------- (1) Realized cash gains and losses represent actual cash settlements or receipts under the respective contracts. (2) The unrealized (loss) gain on contracts represents the change in fair value of the contracts during the period. (3) Unrealized gain on foreign currency contracts includes a $6.9 million dollar gain on contracts related to repayments of the Trust's U.S. denominated long-term debt. See the Foreign Exchange Gains and Losses section of this MD&amp;A for further details on the debt related contracts. &gt;&gt; </pre> <p>The volatility of oil and natural gas prices can lead to significant changes in the mark-to-market position of the Trust's oil and natural gas contracts. Unrealized losses at September 30, 2008 were calculated using forward strip prices as of that date to arrive at a closing mark-to-market loss position excluding contracts designated as effective accounting hedges, of $38.6 million compared to a loss position of $226 million at June 30, 2008 resulting from a weakening in commodity prices late in the third quarter. Commodity prices continued to decline after the quarter end, resulting in an increase in the value of the Trust's risk management contracts. </p> <p>For the remainder of 2008 the Trust has unlimited price participation on approximately 70 per cent of forecast production. The remaining 30 per cent of production volumes have price caps at average prices of US$90 per barrel on crude oil and Cdn$9.68 per GJ on natural gas along with downside price protection at average prices of US$68.13 per barrel on crude oil and Cdn$7.42 per GJ on natural gas. For 2009, the Trust has 5,000 barrels per day of production capped at US$90 per barrel. Subsequent to the quarter end the Trust has bought back a portion of this contract to regain the upside price potential on this production. Table 13 is an indicative summary of the Trust's positions for crude oil, natural gas and related foreign exchange for the next twelve months as at September 30, 2008: </p> <pre> &lt;&lt; Table 13 ------------------------------------------------------------------------- Hedge Positions Summary As at September 30, 2008(1)(2) ------------------------------------------------------------------------- Q4 2008 Q1 2009 ------------------------------------------------------------------------- Crude Oil US$/bbl bbl/day US$/bbl bbl/day ------------------------------------------------------------------------- Sold Call 90.00 10,000 90.00 5,000 Bought Put 68.13 10,000 55.00 5,000 Sold Put 51.07 7,000 40.00 5,000 ------------------------------------------------------------------------- Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day ------------------------------------------------------------------------- Sold Call 9.68 48,570 10.51 42,202 Bought Put 7.42 48,570 7.81 42,202 Sold Put 5.26 10,480 - - ------------------------------------------------------------------------- Foreign Exchange Cdn$/US$ $ million Cdn$/US$ $ million ------------------------------------------------------------------------- Bought Put 1.0750 3.00 - - Sold Put 1.0300 3.00 - - Swap 1.0150 12.00 - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Hedge Positions Summary As at September 30, 2008(1)(2) ------------------------------------------------------------------------- Q2 2009 Q3 2009 ------------------------------------------------------------------------- Crude Oil US$/bbl bbl/day US$/bbl bbl/day ------------------------------------------------------------------------- Sold Call 90.00 5,000 90.00 5,000 Bought Put 55.00 5,000 55.00 5,000 Sold Put 40.00 5,000 40.00 5,000 ------------------------------------------------------------------------- Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day ------------------------------------------------------------------------- Sold Call - - - - Bought Put - - - - Sold Put - - - - ------------------------------------------------------------------------- Foreign Exchange Cdn$/US$ $ million Cdn$/US$ $ million ------------------------------------------------------------------------- Bought Put - - - - Sold Put - - - - Swap - - - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) The prices and volumes noted above represent averages for several contracts and the average price for the portfolio of options listed above does not have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes. The natural gas price shown translates all NYMEX positions to an AECO equivalent price. In addition to positions shown here, ARC has entered into additional basis positions. (2) Please refer to note 9 in the Notes to the Consolidated Financial Statements for full details of the Trust's hedging positions as at September 30, 2008. Table 13 should be interpreted as follows using the fourth quarter 2008 crude oil hedges as an example. To accurately analyze the Trust's hedge position, contracts need to be modeled separately, as using average prices and volumes may be misleading. - If the market price is below $51.07, ARC will receive $68.13 less the difference between $51.07 and the market price on 7,000 barrels per day. For example if the market price is $51.06, ARC will receive $68.12 on 7,000 barrels per day. - If the market price is between $51.07 and $68.13, ARC will receive $68.13 on 10,000 barrels per day. - If the market price is between $68.13 and $90.00, ARC will receive the market price on 10,000 barrels per day. - If the market price exceeds $90.00, ARC will receive $90.00 on 10,000 barrels per day. Operating Netbacks The Trust's operating netback, after realized commodity and related foreign exchange hedging losses, increased 42 per cent to $50.28 per boe in the third quarter of 2008 compared to $35.52 per boe in the same period of 2007. The increase in netbacks in 2008 is primarily due to a 53 per cent increase in the Trust's weighted average sales price. The increase in revenue was partially offset by an increase in royalties and operating costs. The components of operating netbacks are shown in Tables 14 and 14a: Table 14 ------------------------------------------------------------------------- Light and Medium Heavy Natural Q3 2008 Q3 2007 Netbacks Crude Oil Oil Gas NGL Total Total ($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe) ------------------------------------------------------------------------- Weighted average sales price 114.92 98.97 8.68 82.87 81.42 53.28 Other revenue - - - - 0.64 0.13 ------------------------------------------------------------------------- Total revenue 114.92 98.97 8.68 82.87 82.06 53.41 Royalties (17.57) (10.53) (1.99) (23.83) (15.00) (8.76) Transportation (0.18) (1.10) (0.24) - (0.80) (0.65) Operating costs(1) (13.80) (11.26) (1.19) (9.78) (10.19) (9.93) ------------------------------------------------------------------------- Netback prior to hedging 83.37 76.08 5.26 49.26 56.07 34.07 Realized gain (loss) on risk management contracts (10.81) - (0.43) - (5.79) 1.45 ------------------------------------------------------------------------- Netback after hedging 72.56 76.08 4.83 49.26 50.28 35.52 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Operating expenses are composed of direct costs incurred to operate oil and gas wells. A number of assumptions have been made in allocating these costs between oil, heavy oil, natural gas and natural gas liquids production. Table 14a ------------------------------------------------------------------------- Light and Medium Heavy Natural YTD 2008 YTD 2007 Netbacks Crude Oil Oil Gas NGL Total Total ($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe) ------------------------------------------------------------------------- Weighted average sales price 108.09 88.49 8.94 77.92 78.44 53.61 Other revenue - - - - 0.40 0.12 ------------------------------------------------------------------------- Total revenue 108.09 88.49 8.94 77.92 78.84 53.73 Royalties (16.69) (9.49) (1.89) (22.15) (14.18) (9.28) Transportation (0.13) (1.16) (0.23) - (0.77) (0.73) Operating costs(1) (14.00) (10.94) (1.21) (7.18) (10.14) (9.51) ------------------------------------------------------------------------- Netback prior to hedging 77.27 66.90 5.61 48.59 53.75 34.21 Realized gain (loss) on risk management contracts(2) (10.49) - (0.33) - (6.08) 0.93 ------------------------------------------------------------------------- Netback after hedging 66.78 66.90 5.28 48.59 47.67 35.14 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Operating expenses are composed of direct costs incurred to operate oil and gas wells. A number of assumptions have been made in allocating these costs between oil, heavy oil, natural gas and natural gas liquids production. (2) Realized loss on risk management contracts excludes the settlement amount for the treasury interest rate lock contracts that were unwound during the first quarter of 2008. &gt;&gt; </pre> <p>Royalties as a percentage of pre-hedged commodity revenue net of transportation costs were 18.5 per cent ($15.00 per boe) and 16.6 per cent ($8.76 per boe), respectively, for the third quarters of 2008 and 2007. The increase in the royalty rate from 16.6 per cent to 18.5 per cent was partially due to a higher proportion of gas revenue as natural gas royalty rates are generally higher, on average than royalty rates on crude oil production. In 2007, the Trust's royalty rates were lower than normal levels due to Gas Cost Allowance credits and royalty credits received on a portion of the Trust's BC gas production. The higher rate is also attributed to changes to the Trust's production profile as new production has come on to offset production declines at existing properties. </p> <p>Operating costs increased to $10.19 per boe in the third quarter of 2008 compared to $9.93 per boe in the third quarter of 2007. Costs for the third quarter were in-line with expectations as turnarounds and maintenance activities continued throughout the summer months. For 2008, the Trust has maintained guidance at $10.20 per boe based on production of between 64,000 and 65,000 barrels per day. Total operating costs are projected to be approximately $235 million for the full year of 2008. </p> <p>Alberta Government New Royalty Framework </p> <p>On April 10, 2008, the Alberta Government announced revisions to the New Royalty Framework ("Framework" or "NRF") that will take effect on January 1, 2009 pending final legislation which is expected in November 2008. </p> <pre> &lt;&lt; The revisions to the Framework include the following: - Increased royalty rates on conventional and non-conventional oil and natural gas production in Alberta whereby royalty rates may increase to maximum rates of 50 per cent; - Sliding scale royalty calculations based on a broader range of commodity prices whereby conventional oil and natural gas royalty rates may increase up to maximum prices of approximately Cdn$120 per barrel and Cdn$16 per GJ, respectively; - The elimination of royalty incentive and royalty holiday programs with the exception of specific programs relating to deep oil and natural gas drilling programs, innovative technology and enhanced recovery programs; &gt;&gt; </pre> <p>Approximately 65 per cent of the Trust's production is in Alberta; consequently, the Framework will have a significant adverse impact on the Trust's Alberta and corporate royalty rates. The Trust has completed an assessment of the Framework and has estimated that the Trust's average corporate royalty rate will increase from approximately 18 per cent of revenue in 2008 to between 20 and 28 per cent of revenue in 2009 depending upon commodity prices as illustrated in Table 14b. </p> <pre> &lt;&lt; Table 14b ------------------------------------------------------------------------- Royalty Rates - New Royalty Framework ------------------------------------------------------------------------- ------------------------------------------------------------------------- Edmonton posted oil (Cdn$/bbl)(1) $60 $80 $100 $120 AECO natural gas (Cdn$/GJ)(1) $6 $8 $10 $12 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Current Alberta royalty rate(2) 17.5% 17.5% 17.5% 17.5% ------------------------------------------------------------------------- NRF Alberta royalty rate(3) 20.0% 25.0% 29.0% 33.0% ------------------------------------------------------------------------- % Increase - Alberta royalty rate 14% 43% 66% 89% ------------------------------------------------------------------------- Current Corporate royalty rate(2) 18.0% 18.0% 18.0% 18.0% ------------------------------------------------------------------------- NRF Corporate royalty rate(3) 20.0% 23.0% 26.0% 28.0% ------------------------------------------------------------------------- % Increase - Corporate royalty rate 11% 28% 44% 56% ------------------------------------------------------------------------- Incremental Annual Corporate royalties ($ Millions) $15.0 $60.0 $125.0 $200.0 ------------------------------------------------------------------------- Decrease in annual cash flow per unit $0.07 $0.27 $0.58 $0.91 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Canadian dollar denominated prices before quality differentials. (2) Current Alberta and Corporate royalty rates are consistent across all price scenarios as price ceilings have been exceeded under the current royalty regime whereby royalty rates change only marginally across the price scenarios presented. (3) Estimated royalty rates based on draft guidelines that are subject to interpretation. Changes to draft royalty guidelines may result in changes to the estimated royalty rates. Royalty rate includes Crown, Freehold and Gross Override royalties for all jurisdictions in which the Trust operates. Table 14c illustrates provincial royalty rates following implementation of the Framework whereby royalty rates in Alberta will be significantly higher than royalty rates in the Trust's other operating jurisdictions. Production in each province currently approximates 65 per cent in Alberta, 22 per cent in Saskatchewan, 11 per cent in British Columbia and one per cent in Manitoba. The Trust may redirect future capital spending from Alberta if rates of return erode relative to other provinces following implementation of the Framework in January 2009. Table 14c ------------------------------------------------------------------------- Provincial Royalty Rates - New Royalty Framework ------------------------------------------------------------------------- ------------------------------------------------------------------------- Edmonton posted oil (Cdn$/bbl)(1) $60 $80 $100 $120 AECO natural gas (Cdn$/GJ)(1) $6 $8 $10 $12 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Current Alberta royalty rate(2) 17.5% 17.5% 17.5% 17.5% ------------------------------------------------------------------------- NRF Alberta royalty rate(2) 20.0% 25.0% 29.0% 33.0% ------------------------------------------------------------------------- Saskatchewan royalty rate(2) 20.7% 20.7% 20.7% 20.7% ------------------------------------------------------------------------- British Columbia royalty rate(2) 23.5% 23.5% 23.5% 23.5% ------------------------------------------------------------------------- Manitoba royalty rate(2) 17.4% 17.4% 17.4% 17.4% ------------------------------------------------------------------------- (1) Canadian dollar denominated prices before quality differentials. (2) Royalty rate includes Crown, Freehold and Gross Override royalties for all jurisdictions in which the Trust operates. &gt;&gt; </pre> <p>As royalties under the new Framework are sensitive to both commodity prices and production levels, the estimated NRF Alberta and corporate royalty rates will fluctuate with commodity prices, well production rates, production decline of existing wells, and performance and location of new wells drilled. The estimated Alberta and corporate royalty rates are based on draft guidelines that may change pending the outcome of final legislation. </p> <p>The Trust will upgrade its production accounting system in the fourth quarter to accommodate royalty calculations and reporting requirements under the Framework effective January 1, 2009. </p> <p>General and Administrative Expenses and Trust Unit Incentive Compensation </p> <p>Cash G&amp;A expenses net of overhead recoveries on operated properties, excluding cash costs of the Whole Trust Unit Incentive Plan ("Whole Unit Plan"), increased seven per cent to $9 million in the third quarter of 2008 from $8.4 million in the same period of 2007. Increases in G&amp;A expenses for 2008 were due to increased staff levels and higher compensation costs. </p> <p>The Trust recorded a non-cash G&amp;A recovery of $5.5 million (a recovery of $0.93 per boe) during the third quarter, representing a reduction in the value of the Whole Unit Plan due to the decrease in the Trust's unit price from $33.95 per unit at June 30, 2008 to $23.10 at September 30, 2008. There were no cash payments under the plan in the third quarter. Subsequent to quarter end, the Trust made a cash payment under the plan of $9.3 million of which $7.0 million was recorded in G&amp;A. The amount paid subsequent to quarter end was fully accrued as non-cash expense in the third quarter and the cash payment will be reflected as cash G&amp;A and a decrement to cash flow from operating activities in the fourth quarter. </p> <p>Table 15 is a breakdown of G&amp;A and trust unit incentive compensation expense: </p> <pre> &lt;&lt; Table 15 ------------------------------------------------------------------------- G&amp;A and Trust Unit Incentive Compensation Three Months Ended Nine Months Ended Expense September 30 September 30 ------------------------------------------------------------------------- ($ millions % % except per boe) 2008 2007 Change 2008 2007 Change ------------------------------------------------------------------------- G&amp;A expenses 13.3 12.0 11 40.3 38.1 6 Operating recoveries (4.3) (3.6) 19 (12.2) (12.0) 2 ------------------------------------------------------------------------- Cash G&amp;A before Whole Unit Plan 9.0 8.4 7 28.1 26.1 8 Whole Unit Plan - cash - - - 14.4 8.3 74 - accrued (5.5) 3.7 (249) 4.7 (0.3) 1667 ------------------------------------------------------------------------- Total G&amp;A and trust unit incentive compensation expense 3.5 12.1 (71) 47.2 34.1 38 ------------------------------------------------------------------------- Total G&amp;A and trust unit incentive compensation expense per boe 0.59 2.16 (73) 2.65 2.00 33 ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>The components of the initial $3.15 per boe G&amp;A guidance for the full year were as follows: cash G&amp;A - $1.71/boe; cash component of LTIP - $1.00 per boe; non-cash LTIP component - $0.44 per boe. The $1.00 per boe cash and $0.44 per boe non-cash Whole Unit Plan amounts have been revised downward to $0.90 per boe cash and $0.15 per boe non-cash to account for the decline in the trust unit price which impacts the fourth quarter cash payout and non-cash expense amounts under the Whole Unit Plan. The cash G&amp;A guidance remains unchanged at $1.70 per boe for the remainder of 2008. The revised full year guidance for G&amp;A is now $2.75 per boe. </p> <p>Whole Unit Plan </p> <p>The Whole Unit Plan results in each employee, officer and director (the "plan participants") receiving cash compensation in relation to the value of a specified number of underlying trust units. The Whole Unit Plan consists of Restricted Trust Units ("RTUs") for which the number of units is fixed and will vest over a period of three years and Performance Trust Units ("PTUs") for which the number of units is variable and will vest at the end of three years. </p> <p>Upon vesting, the plan participant is entitled to receive a cash payment based on the fair value of the underlying trust units plus accrued distributions. The cash compensation issued upon vesting of the PTUs is dependent upon the performance of the Trust compared to its peers and indicated by the performance multiplier. The performance multiplier is based on the percentile rank of the Trust's total unitholder return compared to its peers. Total return is calculated as the sum of the change in the market price of the trust units in the period plus the amount of distributions in the period. The performance multiplier ranges from zero, if ARC's performance ranks in the bottom quartile, to two for top quartile performance. </p> <p>Table 16 shows the changes to the Whole Unit Plan during the first nine months of 2008 along with the estimated value of the plan at September 30, 2008: </p> <pre> &lt;&lt; Table 16 ------------------------------------------------------------------------- Whole Unit Plan (units in thousands and Number of Number of Total $ millions except per unit) RTUs PTUs RTUs and PTUs ------------------------------------------------------------------------- Balance, beginning of period 746 903 1,649 Granted in the period 414 353 767 Vested in the period (193) (183) (376) Forfeited in the period (41) (42) (83) ------------------------------------------------------------------------- Balance, end of period(1) 926 1,031 1,957 ------------------------------------------------------------------------- Estimated distributions to vesting date(2) 277 431 708 Estimated units upon vesting after distributions 1,203 1,462 2,665 Performance multiplier(3) - 1.5 - ------------------------------------------------------------------------- Estimated total units upon vesting 1,203 2,145 3,348 ------------------------------------------------------------------------- Trust unit price at September 30, 2008 $23.10 $23.10 $23.10 Estimated total value upon vesting ($ millions) 27.8 49.5 77.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Based on underlying units before performance multiplier and accrued distributions. (2) Represents estimated additional units to be issued equivalent to estimated distributions accruing to vesting date. (3) The performance multiplier only applies to PTUs and was estimated to be 1.5 at September 30, 2008 based on an average calculation of all outstanding grants. The performance multiplier is assessed each period end based on actual results of the Trust relative to its peers. &gt;&gt; </pre> <p>The value associated with the RTUs and PTUs is expensed in the statement of income over the vesting period with the expense amount being determined by the trust unit price, the number of PTUs to be issued on vesting, and distributions. In periods where substantial trust unit price fluctuation occurs, the Trust's G&amp;A expense is subject to significant volatility. </p> <p>Table 17 is a summary of the range of future expected payments under the Whole Unit Plan based on variability of the performance multiplier and units outstanding as at September 30, 2008: </p> <pre> &lt;&lt; Table 17 ------------------------------------------------------------------------- Value of Whole Unit Plan as at September 30, 2008 Performance multiplier ------------------------------------------------------------------------- (units thousands and $ millions except per unit) - 1.0 2.0 ------------------------------------------------------------------------- Estimated units to vest RTUs 1,203 1,203 1,203 PTUs - 1,462 2,923 ------------------------------------------------------------------------- Total units(1) 1,203 2,665 4,126 ------------------------------------------------------------------------- Trust unit price(2) $23.10 $23.10 $23.10 Trust unit distributions per month(2) $0.24 $0.24 $0.24 ------------------------------------------------------------------------- Value of Whole Unit Plan upon vesting 27.8 61.6 95.3 ------------------------------------------------------------------------- Officers 2.9 18.8 34.8 Directors 1.9 1.9 1.9 Staff 23.0 40.9 58.6 ------------------------------------------------------------------------- Total payments under Whole Unit Plan(3) 27.8 61.6 95.3 ------------------------------------------------------------------------- 2008 4.3 6.5 8.6 2009 10.7 19.1 27.6 2010 8.3 19.8 31.2 2011 4.5 16.2 27.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes additional estimated units to be issued for accrued distributions to vesting date. (2) Values will fluctuate over the vesting period based on the volatility of the underlying trust unit price and distribution levels. Assumes future trust unit price of $23.10 per trust unit and distributions based on current levels at September 30. (3) Upon vesting, a cash payment is made equivalent to the value of the underlying trust units. The payment is made on vesting dates in March and April for the spring grants, and September and October for the fall grants of each year and at that time is reflected as a reduction of cash flow from operating activities. &gt;&gt; </pre> <p>Due to the variability in the future payments under the plan, the Trust estimates that between $27.8 million and $95.3 million will be paid out from 2008 through 2011 based on the current trust unit price, distribution levels and the Trust's market performance relative to its peers. </p> <p>Provision for Non-recoverable Accounts Receivable </p> <p>On July 22, 2008, SemCanada Crude filed for protection under the Companies' Creditors Arrangement Act ("CCAA"). At that time, the Trust had a receivable of $30.6 million owing from the counterparty for crude oil production that SemCanada marketed on behalf of the Trust. To date, the Trust has recorded a provision for non-recoverable accounts receivable of $18 million ($13.5 million net of tax) for the estimated non-recoverable portion of the $30.6 million balance as Management believes that some portion of the $30.6 million owed by SemCanada is recoverable. The Trust has no additional exposure to SemCanada Crude as all production was allocated to other marketing counterparties effective July 23, 2008. </p> <p>Interest Expense </p> <p>Interest expense decreased to $7.8 million in the third quarter of 2008 from $8.6 million in the third quarter of 2007 due to a decrease in short-term interest rates. As at September 30, 2008, the Trust had $695.7 million of debt outstanding, of which $231 million was fixed at a weighted average rate of 4.8 per cent and $464.7 million was floating at current market rates plus a credit spread of 60 basis points. The Canadian market interest rates have declined to approximately 4.2 per cent in the third quarter of 2008 as compared to approximately 4.9 per cent in the same period of 2007. U.S. London Inter-Bank Offer Rate ("LIBOR") interest rates have declined to approximately 3.1 per cent in the third quarter of 2008 as compared to approximately six per cent in the same period of 2007. Although Canadian interest rates and US LIBOR rates have decreased on average since the third quarter of 2007, they have been volatile towards the end of the September and into the month of October due to the credit crisis and the uncertainty surrounding some banks' sources of funds. In light of this volatility, the Trust has maintained annual guidance for interest expense at $1.50 per boe. </p> <p>Foreign Exchange Gains and Losses </p> <p>In the third quarter of 2008, the Trust recorded a loss of $16.3 million on foreign exchange transactions compared to a gain of $25.7 million in the same period of 2007. These amounts include both realized and unrealized foreign exchange gains and losses. </p> <p>Realized foreign exchange gains or losses arise from U.S. denominated transactions such as interest payments, debt repayments and hedging settlements. </p> <p>Unrealized foreign exchange gains and losses are due to revaluation of U.S. denominated debt balances into Canadian dollars based on period end foreign exchange rates. The unrealized gain/loss impacts net income but does not impact cash flow from operating activities as it is a non-cash amount. During the third quarter, the Canadian dollar weakened to 1.06 CAD$/US$ from 1.01 CAD$/US$ at June 30, 2008, resulting in an unrealized loss of $15.5 million on U.S. dollar denominated debt of US$374 million. </p> <p>ARC entered into forward contracts to lock in exchange rates for principal repayments on US$127.2 million of the US$218 million fixed term debt outstanding. The forward contracts had a mark-to-market gain position at September 30, 2008 of $9.5 million. The unrealized gain on these contracts has been included in the unrealized risk management contracts on the Consolidated Statement of Income and Deficit. </p> <p>Taxes </p> <p>In the third quarter of 2008 the Trust recorded a future income tax expense of $48.4 million versus an income tax recovery of $6.3 million in the third quarter of 2007. The third quarter expense of $48.4 million is primarily due to the $187.5 million unrealized mark-to-market gain on risk management contracts. The Trust has recorded a current future income tax asset of $13.9 million as at September 30, 2008 relating to the current portion of mark-to-market losses on risk management contracts. The net future tax liability on the balance sheet reflects the estimated tax liability associated with the Trust's income tax pools being less than the net book value of the Trust's assets. Each quarter as the Trust makes distributions it effectively passes the taxable income in the current period on to its unitholders. </p> <p>On February 26, 2008, the Federal Government announced as part of the Federal budget that the provincial component of the tax on the Trust is to be calculated based on the general provincial rate in each province in which the Trust has a permanent establishment. This is the same way a corporation would calculate its provincial tax rate, and is different than the original calculation of the tax on the Trust, which had a deemed provincial rate of 13 per cent rather than Alberta's provincial rate of 10 per cent. At the time of writing this MD&amp;A, the Federal budget had been substantively enacted; however, the specific rules for determining the provincial rates for trusts had not been substantively enacted as at September 30, 2008. As a result, a reduction in the tax rate used for the Trust's future income tax calculation has not been reflected in the third quarter of 2008. </p> <p>On July 14, 2008, the Department of Finance released proposed amendments (the "Conversion Rules") to the Income Tax Act (Canada) to facilitate the conversion of existing income trusts into corporations. In general, the proposed amendments will permit a conversion to be tax deferred for both the unitholders and the income trust. However, the Conversion Rules provide alternative approaches to completing a tax deferred conversion. The Department of Finance requested comments on the Conversion Rules by September 15, 2008 and it is anticipated that there will be further amendments to the Conversion Rules. Management and the Board of Directors continue to review the impact of the trust tax on our business strategy and while there has not been a decision as to ARC's future direction, at this time we are of the opinion that the conversion from a trust into a corporation may be the most logical and tax efficient alternative for ARC unitholders. We expect future technical interpretations and details will further clarify the legislation. At the present time, ARC believes that if structural or other similar changes are not made, the relative after-tax distribution amount in 2011 to taxable Canadian investors will remain approximately the same at the same distribution levels, however, will decline for both tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and foreign investors. </p> <p>Depletion, Depreciation and Accretion of Asset Retirement Obligation </p> <p>The depletion, depreciation and accretion ("DD&amp;A") rate decreased slightly to $15.79 per boe in the third quarter of 2008 from $16.11 per boe in the third quarter of 2007. Total depletion of oil and gas assets increased by $3.4 million due to an increase in the Trust's production volumes for the quarter. The lower depletion rate in the third quarter and first nine months of 2008 relative to 2007 is due to a slight increase in the Trust's proven reserve base and a reduction in future development capital associated with the Trust's proven reserve base in 2008. </p> <pre> &lt;&lt; A breakdown of the DD&amp;A rate is detailed in Table 18: Table 18 ------------------------------------------------------------------------- DD&amp;A Rate Three Months Ended Nine Months Ended September 30 September 30 ------------------------------------------------------------------------- ($ millions except % % per boe amounts) 2008 2007 Change 2008 2007 Change ------------------------------------------------------------------------- Depletion of oil &amp; gas assets(1) 91.1 87.7 4 276.5 267.8 3 Accretion of asset retirement obligation(2) 2.3 2.9 (21) 6.9 8.7 (21) ------------------------------------------------------------------------- Total DD&amp;A expense 93.4 90.6 3 283.4 276.5 2 DD&amp;A rate per boe 15.79 16.11 (2) 15.90 16.26 (2) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes depletion of the capitalized portion of the asset retirement obligation that was capitalized to the Property Plant &amp; Equipment ("PP&amp;E") balance and is being depleted over the life of the reserves. (2) Represents the accretion expense on the asset retirement obligation during the year. &gt;&gt; </pre> <p>Capital Expenditures and Net Acquisitions </p> <p>During the third quarter of 2008, the Trust spent $136.4 million on capital expenditures, including $18.6 million for purchases of undeveloped land at land sales. In addition, $13.1 million was spent on net acquisitions of both producing properties and undeveloped land. Year-to-date, the Trust has spent $379.1 million on capital expenditures, including $105.3 million on undeveloped land. As well, the Trust has spent $23.4 million on minor producing property and undeveloped land property acquisitions in the first nine months of 2008. </p> <p>The following summarizes the Trust's year-to-date spending as it relates to our strategic focus areas: </p> <p>Resource Plays </p> <p>The Trust's resource play spending consists of costs incurred for projects in the Montney gas play, the Bakken oil play and the Trust's natural gas from coal ("NGC") projects. Year-to-date, the Trust has spent $200.6 million which includes land purchases of $107.5 million. </p> <p>In the Montney, ARC has spent a total of $72.3 million ($159.8 million including crown land purchases and property purchases from other companies) during the period. At September 30, 2008, the Trust had drilled and completed four horizontal and two vertical wells while an additional 15 wells (3 horizontal and 12 vertical) have been drilled and are scheduled to be completed in the fourth quarter. The Trust is on schedule with the construction of its 10 mmcf per day pipeline from Dawson to Fourth Creek with project completion expected in the fourth quarter. </p> <p>In the Bakken, the Trust purchased undeveloped land for $19.9 million and spent $11.7 million on the drilling of five wells that are all on production at the end of the third quarter at a combined rate of over 1,000 boe per day. </p> <p>NGC project spending has totaled $9.2 million for the first nine months of 2008. </p> <p>Tertiary EOR Initiatives </p> <p>Total spending of $34 million included $11.3 million spent on the Redwater CO(2) injection pilot project during the first nine months of 2008. During the third quarter the Trust received final approval from the Energy Resources Conservation Board for the pilot project and began injecting CO(2) on July 29th. In addition, $12.4 million has been spent at Weyburn where the Trust participates in a CO(2) EOR flood operated by EnCana Corporation. Finally, the Trust spent $10 million on projects at Midale where the Trust participates in a CO(2) EOR flood operated by Apache Corporation. </p> <p>Conventional Assets </p> <p>ARC's conventional assets accounted for total spending of $167.7 million, including land purchases. Some of the highlights of the conventional program are as follows. </p> <p>The Trust has drilled and completed 20 oil wells in the Pembina Cardium area, all of which are on production at the end of the third quarter. </p> <p>In Southwest Saskatchewan, the Trust has drilled a total of 49 shallow gas wells. Of these wells, 26 are currently on production and the remaining 23 will be completed and tied-in during the fourth quarter. In addition, the Trust completed 22 wells in the first quarter of 2008 that were drilled in the fourth quarter of 2007. The Trust was planning to drill an additional 26 shallow gas wells in this area, however, environmental regulatory approvals have caused delays which may cause the Trust to defer this project until 2009. </p> <p>In Redwater, the Trust has drilled eight wells of which three are on production with the remaining five expected to be completed in the fourth quarter. </p> <p>Acquisitions and Dispositions </p> <p>The Trust completed minor net producing property acquisitions for $0.2 million and undeveloped land purchases for $23.2 million year-to-date. The acquisition of undeveloped property for $23.2 million is included in the Montney resource play land purchases discussed above. </p> <p>A breakdown of capital expenditures and net acquisitions is shown in Table 19: </p> <pre> &lt;&lt; Table 19 ------------------------------------------------------------------------- Capital Expenditures Three Months Ended Nine Months Ended September 30 September 30 ------------------------------------------------------------------------- % % ------------------------------------------------------------------------- ($ millions) 2008 2007 Change 2008 2007 Change ------------------------------------------------------------------------- Geological and geophysical 1.3 2.9 (55) 23.3 11.9 96 Drilling and completions 91.4 73.4 25 188.3 154.4 22 Plant and facilities 24.2 21.1 15 59.9 54.1 11 Undeveloped land 18.6 33.0 (44) 105.3 34.9 202 Other capital 0.9 1.5 (40) 2.3 2.6 (12) ------------------------------------------------------------------------- Total capital expenditures 136.4 131.9 3 379.1 257.9 47 ------------------------------------------------------------------------- Producing property acquisitions(1) - 27.3 (100) 0.3 42.0 (99) Undeveloped land property acquisitions 13.1 - 100 26.9 - 100 Producing property dispositions(1) - - - (0.1) (4.6) (98) Undeveloped land property dispositions - - - (3.7) - 100 ------------------------------------------------------------------------- Total capital expenditures and net acquisitions 149.5 159.2 (6) 402.5 295.3 36 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Value is net of post-closing adjustments. &gt;&gt; </pre> <p>Approximately 57 per cent of the $136.4 million capital program in the third quarter of 2008 was financed with cash flow from operating activities compared to 38 per cent in the same period of 2007. Property acquisitions were financed through debt. On a year-to-date basis, the Trust has funded 77 per cent of the capital expenditures with cash flow from operating activities as compared to 58 percent for the first nine months of 2007. </p> <pre> &lt;&lt; Table 20 ------------------------------------------------------------------------- Source of Funding of Capital Expenditures and Net Acquisitions ($ millions) ------------------------------------------------------------------------- Three Months Ended Three Months Ended September 30, 2008 September 30, 2007 ------------------------------------------------------------------------- Devel- Net Total Devel- Net Total opment Acquis- Expend- opment Acquis- Expend- Capital itions itures Capital itions itures ------------------------------------------------------------------------- Expenditures 136.4 13.1 149.5 131.9 27.3 159.2 ------------------------------------------------------------------------- Cash flow from operating activities 57% - 53% 38% - 31% Proceeds from DRIP and Rights Plan 29% - 26% 21% - 17% Debt 14% 100% 21% 41% 100% 52% ------------------------------------------------------------------------- 100% 100% 100% 100% 100% 100% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Table 20a ------------------------------------------------------------------------- Source of Funding of Capital Expenditures and Net Acquisitions ($ millions) ------------------------------------------------------------------------- YTD September 30, 2008 YTD September 30, 2007 ------------------------------------------------------------------------- Devel- Net Total Devel- Net Total opment Acquis- Expend- opment Acquis- Expend- Capital itions itures Capital itions itures ------------------------------------------------------------------------- Expenditures 379.1 23.4 402.5 257.9 37.4 295.3 ------------------------------------------------------------------------- Cash flow from operating activities 77% - 72% 58% - 50% Proceeds from DRIP and Rights Plan 23% 38% 24% 33% - 29% Debt - 62% 4% 9% 100% 21% ------------------------------------------------------------------------- 100% 100% 100% 100% 100% 100% ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>Asset Retirement Obligation and Reclamation Fund </p> <p>The Asset Retirement Obligation ("ARO") increased by $3.1 million in the first nine months of 2008 to $143.1 million ($140 million at December 31, 2007) for future abandonment and reclamation of the Trust's properties. </p> <p>Included in the September 30, 2008 ARO balance is a $1.6 million increase related to development activities in the first nine months of 2008 as well as changes in estimates for the existing liability. The ARO liability was also increased by $6.9 million for accretion expense in the period and was reduced by $7.8 million for actual abandonment expenditures incurred in the first nine months of 2008. </p> <p>The Trust maintains two reclamation funds that together held $26.9 million at September 30, 2008, one exclusively for the reclamation of the Redwater property and the other for all of the Trust's other properties. </p> <p>In total, ARC contributed $9 million cash to its reclamation funds in the first nine months of 2008 and earned interest of $0.9 million on the fund balances. The fund balances were reduced by $9 million for cash-funded abandonment expenditures in the first nine months of 2008. </p> <p>Capitalization, Financial Resources and Liquidity </p> <p>A breakdown of the Trust's capital structure is detailed in Table 21 as at September 30, 2008 and December 31, 2007: </p> <pre> &lt;&lt; Table 21 ------------------------------------------------------------------------- Capital Structure and Liquidity September 30, December 31, ($ millions except per cent and ratio amounts) 2008 2007 ------------------------------------------------------------------------- Net debt obligations(1) 773.2 752.7 Market value of trust units and exchangeable shares(2) 5,021.9 4,349.3 ------------------------------------------------------------------------- Total capitalization(3) 5,795.1 5,102.0 ------------------------------------------------------------------------- Net debt as a percentage of total capitalization 13.3% 14.8% Net debt to annualized YTD cash flow from operating activities 0.8 1.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Net debt is a non-GAAP measure and is calculated as long-term debt plus current liabilities less the current assets as they appear on the Consolidated Balance Sheets. Net debt excludes current unrealized amounts pertaining to risk management contracts and the current portion of future income taxes. (2) Calculated using the total trust units outstanding at September 30, 2008 including the total number of trust units issuable for exchangeable shares at September 30, 2008 multiplied by the closing trust unit price of $23.10. (3) Total capitalization as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Total capitalization is not intended to represent the total funds from equity and debt received by the Trust. &gt;&gt; </pre> <p>The Trust's current credit facilities comprise US$218 million in senior secured notes currently outstanding, a Cdn$800 million syndicated bank credit facility, of which $452.3 million was outstanding at September 30, 2008 and a Cdn$25 million demand working capital facility, of which $12.4 million was outstanding at September 30, 2008. On April 15, 2008 ARC extended the credit facility to April 2011 under the same terms. The credit facility syndicate includes 11 domestic and international banks. The Trust's debt agreements contain a number of covenants all of which were met as at September 30, 2008; these agreements are available at www.SEDAR.com. The major financial covenants are described below: </p> <pre> &lt;&lt; - Long-term debt is not to exceed three times annualized cash flow from operating activities prior to interest expense, expenditures on site restoration and reclamation and changes in non-cash working capital. - Long-term debt is not to exceed 50 per cent of unitholders' equity plus long-term debt. &gt;&gt; </pre> <p>As at September 30, 2008 ARC has approximately $270 million of unused credit available, net of the working capital deficiency (before risk management contracts and the current portion of future income tax), under its bank credit facility and the ability to issue an additional US$100 million of long-term notes under an agreement with one lender. This option, which will expire in May 2009, would allow the Trust to issue long-term notes at a rate equal to the related U.S. treasuries corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance. </p> <p>As a result of the weakened global economic situation, the Trust along with all other oil and gas entities will have restricted access to capital and increased borrowing costs. Although the Trust's business and asset base have not changed, the lending capacity of all financial institutions has been diminished and risk premiums have increased. These issues will impact the Trust as it reviews financing alternatives for the 2009 capital program, assesses potential future acquisition opportunities and manages future cash flow decremented by lower commodity prices and higher borrowing costs. The Trust intends to finance the remainder of its 2008 capital program and its 2009 capital program with cash flow, existing credit facilities, proceeds from the DRIP, potential asset dispositions and new borrowings or equity if necessary. Beyond that, the Trust may need to access additional capital and/or curtail capital expenditure plans and if so, will execute the most cost effective and efficient means of financing its ongoing operations. </p> <p>Unitholders' Equity </p> <p>At September 30, 2008, there were 217.4 million trust units issued and issuable for exchangeable shares, an increase of 4.2 million trust units from December 31, 2007. The increase in number of trust units outstanding is mainly attributable to the 3.7 million trust units issued pursuant to the DRIP during the nine months of 2008 at an average price of $25.16 per unit. Unitholders electing to reinvest distributions or make optional cash payments to acquire trust units from treasury under the DRIP may do so at a five per cent discount to the prevailing market price with no additional fees or commissions. </p> <p>The Trust had two thousand rights outstanding as of September 30, 2008 under an employee plan where further rights issuances were discontinued in 2004. The rights are fully vested and may be exercised to purchase trust units at an average adjusted exercise price of $10.33 per unit as at September 30, 2008. The rights will expire on or before December 31, 2008. During the first nine months of 2008, the