http://www.arcresources.net/news/latestnews.rssNews Releases For ARC Resourcesen-CA03/03/2010 10:03:27 AM10/03/2010 3:21:07 PMCopyright (c) 2008, ARC Resources Ltd.http://blogs.law.harvard.edu/tech/rssARC Resources RSS10http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1398348CALGARY, Mar 3, 2010 (Canada NewsWire via COMTEX) -- Notification of live webcast event: <p>ARC Energy Trust (TSX: AET.UN) </p> <p>Live webcast presentation </p> <p>Wednesday, March 10, 2010, 3:50 PM EST (1:50 PM MST) </p> <p>To listen and view this online event, please visit: </p> <p>http://remotecontrol.jetstreammedia.com/16835 </p> <p>The presentation will be available in an archived version at this link for 30 days following the live presentation. </p> <p>SOURCE: ARC Energy Trust </p> <pre>on the webcast please visit www.firstenergy.com or contact: ARC Energy Trust: Raina Vitanov, Senior Advisor, Investor Relations, (403) 503-8600, IR@arcresources.com </pre>03/03/2010 10:11:07 AMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1398348http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1397198CALGARY, Mar 1, 2010 (Canada NewsWire via COMTEX) -- (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 2.74640 to 2.75900. Such increase will be effective on March 15, 2010. <p>The following are the details on the calculation of the exchange ratio: </p> <pre> &lt;&lt; ------------------------------------------------------------------------- 10 day Record weighted Effective date of average date ARC ARC Energy trading of the Exchange Energy Trust price of Increase increase ratio as Trust Opening distrib- AET.UN (prior in in of distrib- exchange ution to the end exchange exchange effective ution ratio per unit of the month) ratio (xx) ratio date ------------------------------------------------------------------------- February March 26, 2010 2.74640 $0.10 $21.8030 0.01260 15, 2010 2.75900 ------------------------------------------------------------------------- (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> <p>ARC RESOURCES LTD. </p> <p>John P. Dielwart, </p> <p>Chief Executive Officer </p> <p>%SEDAR: 00015954E %CIK: 0001029509 </p> <p>SOURCE: ARC Energy Trust </p> <p>SOURCE: ARC Resources Ltd. </p> <p>SOURCE: ARC Energy Trust </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>01/03/2010 5:26:15 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1397198http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1393723CALGARY, Feb. 22, 2010 (Canada NewsWire via COMTEX) -- (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or "the Trust") announces its 2009 U.S. Income Tax Information to be as follows: <pre> &lt;&lt; ARC ENERGY TRUST 2009 U.S. INCOME TAX REPORTING &gt;&gt; </pre> <p>U.S. Income Tax Information </p> <p>The following information is being provided to assist U.S. individual unitholders of ARC Energy Trust ("ARC") in reporting distributions received from ARC during 2009 on their Internal Revenue Service ("IRS") Form 1040, "U.S. Individual Income Tax Return" ("Form 1040"). </p> <pre> &lt;&lt; This summary is of a general nature only and is not intended to be legal or tax advice to any particular holder or potential holder of ARC trust units. Holders or potential holders of ARC trust units should consult their own legal and tax advisors as to their particular tax consequences of holding ARC trust units. &gt;&gt; </pre> <p>Qualified Dividends </p> <p>In consultation with its U.S. tax advisors, ARC believes that its trust units should be properly classified as equity in a corporation, rather than debt, and that dividends paid to individual U.S. unitholders should be "qualified dividends" for U.S. federal income tax purposes. As such, the portion of the distributions made during 2009 that are considered dividends for U.S. federal income tax purposes should qualify for the reduced rate of tax applicable to long-term capital gains. However, the individual taxpayer's situation must be considered before making this determination. </p> <p>Trust Units Held Outside a Qualified Retirement Plan </p> <p>With respect to cash distributions paid during the year to U.S. individual unitholders, 15.97 percent should be reported as a return of capital (to the extent of the unitholder's U.S. tax basis in their respective units) and 84.03 percent should be reported as "qualified dividends". The table below summarizes the distributions paid by ARC in 2009. </p> <p>The portion of the distributions treated as "qualified dividends" should be reported on Line 9b of Form 1040, unless the fact situation of the U.S. individual unitholders determines otherwise. Commentary on page 22 of the Form 1040 Instruction Booklet for 2009 with respect to "qualified dividends" provides examples of individual situations where the dividends would not be "qualified dividends". Where, due to individual situations, the dividends are not "qualified dividends", the amount should be reported on Schedule B - Part II - Ordinary Dividends and Line 9a of Form 1040. </p> <p>For U.S. federal income tax purposes, in reporting a return of capital with respect to distributions received, U.S. unitholders are required to reduce the cost base of their trust units by the total amount of distributions received that represent a return of capital. This amount is non-taxable if it is a return of cost base in the trust units. If the full amount of the cost base has been recovered, any further return of capital distributions should be reported as capital gains. </p> <p>U.S. unitholders are encouraged to utilize the Qualified Dividends and Capital Gain Tax Worksheet of Form 1040 to determine the amount of tax that may be otherwise applicable. </p> <p>The full amount of the distribution paid to a non-resident of Canada is subject to a minimum 15 percent Canadian withholding tax that is withheld prior to any payments being distributed to unitholders. Where trust units are held outside a qualified retirement account, the full amount of all withholding tax should be creditable, subject to numerous limitations, for U.S. tax purposes in the year in which the withholding taxes are withheld. Where trust units are held in a qualified retirement account, the same withholding taxes apply but the amount is not creditable for U.S. tax purposes. </p> <p>The amount of Canadian tax withheld should be reported on Form 1116, "Foreign Tax Credit (Individual, Estate, or Trust)". Information regarding the amount of Canadian tax withheld in 2009 should be determined from your own records and is not available from ARC. Amounts over withheld, if any, from Canada should be claimed as a refund from the Canada Revenue Agency no later than two years after the calendar year in which the payment was paid. </p> <p>Investors should report their dividend income and capital gain (if any), and make adjustments to their tax basis in ARC's units, in accordance with this information and subject to advice from their tax advisors. U.S. individual unitholders who hold their ARC trust units through a stockbroker or other intermediary should receive tax reporting information from their stockbroker or other intermediary. We expect that the stockbroker or other intermediary will issue a Form 1099-DIV, "Dividends and Distributions" or a substitute form developed by the stockbroker or other intermediary. ARC is not required to furnish such unitholders with Form 1099-DIV. Information on the Forms 1099-DIV issued by the brokers or other intermediaries may not accurately reflect the information in this press release for a variety of reasons. Investors should consult their brokers and tax advisors to ensure that the information presented here is accurately reflected on their tax returns. Brokers and/or intermediaries may or may not be required to issue amended Forms 1099-DIV. </p> <p>Trust Units Held Within a Qualified Retirement Plan </p> <p>No amounts are required to be reported on a Form 1040 where ARC trust units are held within a qualified retirement plan. </p> <p>Summary of U.S. Tax Information </p> <p>The following table provides, on a per unit basis, the breakdown of the amount of cash distributions, prior to Canadian withholding tax, paid by ARC for the period January 15 to December 15, 2009. The amounts are segregated between the portion of the cash distribution that could be considered "qualified dividends" and the portion reported as non-taxable return of capital (and/or capital gain). The amounts shown on the following table are in U.S. dollars as converted on the applicable payment dates. This table is for information purposes only. </p> <pre> &lt;&lt; 2009 CASH DISTRIBUTION INFORMATION FOR U.S. UNITHOLDERS (U.S. $/Unit) ------------------------------------------------------------------------- Non- Distrib- Taxable Taxable ution Distrib- Qualified Return of Paid Exchange ution Dividend Capital Record Date Payment Date CDN$ Rate Paid US$ US$ US$ ------------------------------------------------------------------------- ------------------------------------------------------------------------- Dec 31, 2008 Jan 15, 2009 $0.15 0.7921 $0.118815 $0.099840 $0.018975 ------------------------------------------------------------------------- Jan 30, 2009 Feb 16, 2009 $0.12 0.8041 $0.096492 $0.081082 $0.015410 ------------------------------------------------------------------------- Feb 27, 2009 Mar 16, 2009 $0.12 0.7859 $0.094308 $0.079247 $0.015061 ------------------------------------------------------------------------- Mar 31, 2009 Apr 15, 2009 $0.12 0.8307 $0.099684 $0.083764 $0.015920 ------------------------------------------------------------------------- Apr 30, 2009 May 15, 2009 $0.12 0.8506 $0.102072 $0.085771 $0.016301 ------------------------------------------------------------------------- May 29, 2009 Jun 15, 2009 $0.10 0.8818 $0.088180 $0.074098 $0.014082 ------------------------------------------------------------------------- Jun 30, 2009 Jul 15, 2009 $0.10 0.8933 $0.089330 $0.075064 $0.014266 ------------------------------------------------------------------------- Jul 31, 2009 Aug 17, 2009 $0.10 0.9026 $0.090260 $0.075845 $0.014415 ------------------------------------------------------------------------- Aug 31, 2009 Sep 15, 2009 $0.10 0.9291 $0.092910 $0.078072 $0.014838 ------------------------------------------------------------------------- Sep 30, 2009 Oct 15, 2009 $0.10 0.9706 $0.097060 $0.081560 $0.015500 ------------------------------------------------------------------------- Oct 30, 2009 Nov 16, 2009 $0.10 0.9560 $0.095600 $0.080333 $0.015267 ------------------------------------------------------------------------- Nov 30, 2009 Dec 15, 2009 $0.10 0.9416 $0.094160 $0.079123 $0.015037 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total Per Unit $1.33 $1.158871 $0.973799 $0.185072 ------------------------------------------------------------------------- &gt;&gt; </pre> <p>ARC RESOURCES LTD. </p> <pre> &lt;&lt; John P. Dielwart, Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00015954E %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. </pre>22/02/2010 3:27:47 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1393723http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1390682CALGARY, Feb. 12, 2010 (Canada NewsWire via COMTEX) -- (AET.UN and ARX - TSX) ARC Energy Trust (the "Trust" or "ARC") announces that the cash distribution to be paid on March 15, 2010, in respect of the February 2010 production, for unitholders of record on February 26, 2010, will be $0.10 per trust unit. The ex-distribution date is February 24, 2010. <p>As at February 12, 2010 the Trust's trailing twelve-month cash distributions, including the January 15, 2010 payment, total $1.28 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 $6.1 billion. The Trust expects 2010 oil and gas production to average 70,500 to 72,500 of barrels of oil equivalent per day from seven core areas in western Canada. 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 2010 and beyond; the sources, deployment and allocation of expected capital in 2010; 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, Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00015954E %CIK: 0001029509 </p> <p>SOURCE: ARC Energy Trust </p> <p>SOURCE: ARC Resources Ltd. </p> <p>SOURCE: ARC Energy Trust </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>12/02/2010 4:57:53 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1390682http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1385775CALGARY, Feb. 9, 2010 (Canada NewsWire via COMTEX) -- (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or "the Trust") announces the results for the fourth quarter and the year ended December 31, 2009. <pre> &lt;&lt; ------------------------------------------------------------------------- Three Months Ended Twelve Months Ended For the years ended December 31 December 31 December 31 2009 2008 2009 2008 ------------------------------------------------------------------------- FINANCIAL (Cdn$ millions, except per unit and per boe amounts) Revenue before royalties 278.6 300.8 978.2 1,706.4 Per unit(1) 1.17 1.38 4.16 7.90 Per boe 48.44 50.06 42.18 71.59 Cash flow from operating activities(2) 143.2 209.4 497.4 944.4 Per unit(1) 0.60 0.96 2.11 4.37 Per boe 24.90 34.85 21.45 39.62 Net income 65.5 82.7 222.8 533.0 Per unit(3) 0.28 0.38 0.96 2.50 Distributions 70.9 127.2 298.5 570.0 Per unit(1) 0.30 0.59 1.28 2.67 Per cent of cash flow from operating activities(2) 50 61 60 60 Net debt outstanding(4) 902.4 961.9 902.4 961.9 OPERATING Production Crude oil (bbl/d) 27,415 28,935 27,509 28,513 Natural gas (mmcf/d) 189.0 195.1 194.0 196.5 Natural gas liquids (bbl/d) 3,597 3,858 3,689 3,861 Total (boe/d) 62,520 65,313 63,538 65,126 Average prices Crude oil ($/bbl) 72.61 56.26 62.24 94.20 Natural gas ($/mcf) 4.58 7.48 4.18 8.58 Natural gas liquids ($/bbl) 46.12 45.22 40.67 69.71 Oil equivalent ($/boe) 48.35 49.93 42.07 71.25 Operating netback ($/boe) Commodity and other revenue (before hedging) 48.42 50.06 42.17 71.59 Transportation costs (0.92) (0.86) (0.89) (0.80) Royalties (7.94) (9.14) (6.37) (12.91) Operating costs (9.91) (10.09) (10.19) (10.13) Netback (before hedging) 29.65 29.97 24.72 47.75 ------------------------------------------------------------------------- TRUST UNITS (millions) Units outstanding, end of period(5) 239.0 219.2 239.0 219.2 Weighted average trust units(6) 238.5 218.3 235.4 216.0 ------------------------------------------------------------------------- TRUST UNIT TRADING STATISTICS (Cdn$, except volumes) based on intra-day trading High 21.89 22.55 21.89 33.95 Low 19.06 15.01 11.73 15.01 Close 19.94 20.10 19.94 20.10 Average daily volume (thousands) 963 1,523 1,057 975 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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 fourth quarter of 2009 would be $156 million ($0.65 per unit) and for the full year 2009 would be $518 million ($2.20 per unit). Distributions as a percentage of Cash Flow would be 58 per cent in 2009. (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) For 2009, includes 0.9 million (1.1 million in 2008) exchangeable shares exchangeable into 2.720 trust units (2.517 in 2008) each for an aggregate 2.4 million (2.7 million in 2008) trust units. (6) Includes trust units issuable for outstanding exchangeable shares at period end. ACCOMPLISHMENTS / FINANCIAL UPDATE - ARC replaced 347 per cent of annual production at an all-in annual Finding, Development and Acquisition ("FD&amp;A") cost of $6.44 per barrel of oil equivalent ("boe") before consideration of future development capital ("FDC") for the proved plus probable reserves category. This is the third consecutive year of reducing FD&amp;A costs and brings ARC's three year average FD&amp;A prior to FDC down to $9.57 per boe. FD&amp;A costs including FDC were $11.57 per boe, a 32 per cent reduction from the $17 per boe achieved in 2008. Additional information on the reserves evaluation can be found in the "ARC Energy Trust Releases 2009 Year-end Reserves Information" news release dated February 9, 2010 and filed on SEDAR at www.sedar.com. - During the fourth quarter, ARC completed an acquisition for $180 million in cash consideration, prior to normal closing adjustments, of a partnership owning properties in the Ante Creek area. The acquisition consisted of producing wells with production of approximately 2,000 boe per day and undeveloped land holdings. The acquisition closed on December 21, 2009 therefore the financial results from the properties have been included in Consolidated Financial Statements from that date. - Concurrent with the Ante Creek acquisition, ARC entered into a bought deal financing agreement to issue 13 million trust units at $19.40 per trust unit to raise gross proceeds of approximately $252 million and net proceeds of approximately $240 million. The net proceeds of the offering were received on January 5, 2010 and were used to reduce the outstanding indebtedness of ARC by $240 million. - Production volumes for 2009 averaged 63,538 boe per day, a 2.4 per cent decline compared to 2008 production of 65,126 boe per day. This decline was due to ARC's reduction of its 2009 capital expenditures in response to declining commodity prices. The Trust expects 2010 full year average production to increase by approximately 13 per cent to between 70,500 and 72,500 boe per day with the anticipated start- up of a company-owned gas plant in the Dawson area in the second quarter of 2010 and a full year of production from the December 2009 acquisition in Ante Creek. - Cash flow from operating activities for the full year of 2009 was $497.4 million, or $2.11 per unit, a significant decline from the $944.4 million ($4.37 per unit) achieved in fiscal 2008. This decline was primarily due to a 41 per cent decrease in commodity prices in 2009 compared to 2008. Crude oil prices strengthened in the second half of 2009 as the economy showed some positive signs of recovery. Natural gas prices remained soft throughout most of 2009 prior to recovering somewhat late in the fourth quarter of 2009 ending the year at $5.70 per mcf. After payment of distributions the Trust was able to fund 54 per cent of the 2009 capital program with cash flow from operating activities (73 per cent when including the proceeds from the distributions re-investment program ("DRIP")) with the remaining portion funded through debt and working capital. - The Trust executed a $359.6 million capital expenditure program in 2009 that included the purchase of undeveloped land for $7 million and $352.6 million of exploration and development activities. A total of 120 net wells were drilled on ARC's operated properties with a 99 per cent success rate. Included in these capital expenditures is $8.1 million of Alberta Government royalty drilling credits and $3.1 million for British Columbia summer drilling credits. Without these credits, total capital expenditures would have been $370.8 million. - ARC's Board of Directors has approved a $610 million capital program for 2010 that will deliver considerable growth. The program will include over $264 million slated for the first of many stages of production growth and expansion of the Montney assets in Northeast British Columbia. Other major resource play development will take place at Ante Creek where $72 million has been allocated to drill 14 horizontal wells and expand facilities and at Pembina where $54 million will be spent to drill 16 horizontal wells and 16 vertical wells targeting the Cardium formation on operated lands. The remainder of the budget will focus on ARC's base development areas, exploration opportunities and enhanced oil recovery projects. In total, ARC plans to drill 211 gross wells on operated properties and participate in an additional 91 wells on partner operated properties. ARC plans to finance the 2010 capital program through a combination of cash flow, existing credit facilities, DRIP proceeds and potential minor asset disposition proceeds. - On December 31, 2009, ARC's long-term debt was $846 million. After the closing of the equity offering on January 5, 2010, long-term debt was reduced to $606 million leaving ARC with approximately $710 million of unused credit lines. With the current debt level, net debt to 2009 cash flow from operating activities is 1.2 times. At current forward prices for commodities, ARC is well positioned to finance the projected 2010 capital program of $610 million and payout $0.10 per trust unit per month of distributions while keeping debt at a very manageable level. - ARC has hedged approximately 43,000 mcf per day of natural gas for the period of July 1, 2011 to December 31, 2013 at an average price of $6.40 per mcf to protect the economics on the ARC owned gas plant being constructed at Dawson. Overall, commodity price volatility protection has been established for the 2010 capital budget by hedging 34 per cent of forecast natural gas volumes at an average swap price of $5.85 per mcf and 32 per cent of forecast crude oil volumes at an average floor price of US$74.67 per barrel. - ARC plans to convert to a dividend paying corporation effective January 1, 2011. The Board of Directors has approved the overall strategy and currently the detailed implementation steps are being defined. The conversion plans will be mailed to unitholders with a unitholder meeting planned for December of 2010. Current plans would see a dividend policy similar to the existing distribution policy with dividends being paid monthly. - Montney Resource Play Development Production from the Dawson area was on budget at an average rate of 53.6 mmcf per day throughout the fourth quarter and exited the year at 59.2 mmcf per day. During the fourth quarter of 2009, ARC spent $70.8 million on development activities in the Dawson area including drilling seven horizontal wells, two of which were completed during the quarter. ARC tested six horizontal Dawson wells during the quarter at rates between five and nine mmcf per day of natural gas at a flowing pressure of 1,200 to 2,200 pounds per square inch. Included in the fourth quarter spending is $27.8 million for the Dawson Phase 1 60 mmcf per day gas plant discussed below. For the full year of 2009, ARC drilled 22 horizontal wells in the Dawson gas fields that are in various stages of completion. Of these wells, eight were on production by year-end, nine wells are in the completed and waiting on tie-in category and the remaining five wells will be completed early in 2010. ARC is participating in a small development project on partner operated lands at Sunrise. Four wells have been drilled and completed. Production commenced at the end of the fourth quarter and is currently producing at approximately 10 mmcf per day net to ARC's 50 per cent working interest. The British Columbia Oil and Gas Commission ("OGC") issued final approval for the 60 mmcf per day Dawson Phase 1 gas plant on November 13, 2009 at which time all on-site construction began. As of January 31, 2010, the mechanical construction of the plant was approximately 70 per cent complete and the electrical work was underway. ARC expects to complete construction of the plant in early April, with start-up commissioning of the plant occurring during the rest of the month. Sales gas is expected to be flowing from the plant by early May. To date, ARC has spent $57.6 million on the gas plant with an additional $5.7 million expected to be spent in 2010 prior to the commissioning. ARC is already well underway with plans to build a second 60 mmcf per day gas plant at the same location. All long-lead time equipment has been ordered and the application to construct the plant is being prepared. - Enhanced Oil Recovery Initiatives During 2009, ARC spent $25.7 million on enhanced oil recovery ("EOR") initiatives and received $2.8 million in government funding for the Redwater pilot project for net spending of $22.9 million. Work on the Redwater CO(2) pilot project continues and both the CO(2) injection and oil production facilities are operating as expected. Results to date are encouraging but ARC anticipates that it will take until later in 2010 to determine to what extent the pilot has been successful in mobilizing incremental volumes of oil. While the pilot project may indicate enhanced recovery, the outlook for crude oil prices and the cost and availability of CO(2) will be determining factors in ARC's ability to achieve commercial viability for a full scale EOR scheme at Redwater. &gt;&gt; </pre> <p>MANAGEMENT'S DISCUSSION AND ANALYSIS </p> <p>This management's discussion and analysis ("MD&amp;A") is ARC management's analysis of its financial performance and significant trends or external factors that may affect future performance. The MD&amp;A is dated February 8, 2010 and should be read in conjunction with the audited Consolidated Financial Statements as at and for the year ended December 31 2009, the MD&amp;A and the audited Consolidated Financial Statements as at and for the year ended December 31, 2008, the MD&amp;A and the unaudited Consolidated Financial Statements for the periods ended March 31, 2009, June 30, 2009 and September 30, 2009 as well as ARC's Annual Information Form that is filed on SEDAR at www.sedar.com. </p> <p>The MD&amp;A contains Non-GAAP measures and forward-looking statements; and readers are cautioned that the MD&amp;A should be read in conjunction with ARC's disclosure under "Non-GAAP Measures" and "Forward-Looking Statements" included at the end of this MD&amp;A. </p> <p>Executive Overview </p> <p>ARC Energy Trust ("ARC") or ("the Trust") is an actively managed oil and natural gas entity formed to provide investors with indirect ownership in cash generating energy assets, that currently consist of oil and natural gas assets. The major operating activities of ARC are the development, production and sale of crude oil, natural gas liquids and natural gas. </p> <p>ARC's main objective is value creation through the development of large oil and natural gas pools. The business strategy and activities that support this objective are: </p> <pre> &lt;&lt; Resource Plays -------------- - Acquisition and development of land and producing properties with large volumes of oil and gas in place, such as the Montney development in Dawson in northeastern British Columbia, Ante Creek in northern Alberta and the Cardium formation at Pembina in central Alberta. Conventional Oil &amp; Gas Production --------------------------------- - Maximizing production while controlling operating costs on oil and gas wells located within ARC's seven core producing areas all of which are located in western Canada. ARC's total production in 2009 was almost evenly split between commodities with 51 per cent of production from natural gas and 49 per cent from oil and gas liquids. Conventional oil and gas properties continue to be developed to increase the recoverable reserves through development drilling, optimization and waterflood programs. Within ARC's core areas many properties would be considered "resource plays" due to the substantial reserves still in place and the advancement of proved horizontal drilling and multi-stage fracture stimulation technology to develop these reserves. - The periodic acquisition of strategic producing and undeveloped properties to enhance current production or provide the potential for future drilling locations and if successful, additional production and reserves. Enhanced Oil Recovery ("EOR") ----------------------------- - Evaluation and implementation of enhanced oil recovery programs to increase ARC's recoverable reserves in existing oil pools. ARC has a non-operated interest in the Weyburn and Midale units in Saskatchewan. Operators of both these units have implemented CO(2) injection programs to increase recoverable oil reserves. In 2008 ARC advanced this strategy of enhanced oil recovery with the initiation of a CO(2) pilot program at Redwater. &gt;&gt; </pre> <p>ARC's goal is to provide superior long-term returns to unitholders. ARC's structure provides returns to unitholders through both the receipt of monthly cash distributions and the potential for capital appreciation. </p> <p>Currently, ARC distributes $0.10 per unit per month. The remainder of the cash flow is used to fund reclamation costs, and a portion of capital expenditures. In 2009 cash flow and proceeds from the DRIP program funded $194.3 million of capital expenditures and a net contribution of $4.6 million to the reclamation funds. Since ARC's inception in July 1996 to December 31, 2009, ARC has distributed $3.5 billion or $24.98 per unit. </p> <p>Capital appreciation for ARC's unitholders would be associated with increased market values for ARC's production and reserves. ARC's management strives to replace or grow both 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. ARC continues to focus on major properties with significant upside, with the objective to replace production declines through internal development opportunities. ARC's normalized reserves per unit have increased by 10 per cent to 1.57 per unit from 1.42 per unit in 2008 while production per thousand trust units decreased slightly from 0.29 to 0.27. Since year-end 2007, ARC has increased normalized reserves per unit by 16 per cent, and normalized production per thousand trust units has declined by 10 per cent while ARC has made distributions of $3.95 per unit or $868.5 million. Details of the calculations for normalized production and reserves per unit are provided in Table 1. </p> <pre> &lt;&lt; Table 1 ------------------------------------------------------------------------- Per Trust Unit 2009 2008 2007 ------------------------------------------------------------------------- Normalized production per unit(1)(2) 0.27 0.29 0.30 Normalized reserves per unit(1)(3) 1.57 1.42 1.35 Distributions per unit $1.28 $2.67 $2.40 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Normalized indicates that all periods as presented have been adjusted to reflect a net debt to capitalization of 15 per cent. It is assumed that additional trust units were issued (or repurchased) at a period end price for the reserves per unit calculation and at an annual average price for the production per unit calculation in order to achieve a net debt balance of 15 per cent of total capitalization each year. The normalized amounts are presented to enable comparability of per unit values. (2) Production per unit represents daily average production (boe) per thousand trust units and is calculated based on daily average production divided by the normalized weighted average trust units outstanding including trust units issuable for exchangeable shares. (3) Reserves per unit are calculated based on proved plus probable reserves (boe), as determined by ARC's independent reserve evaluator at period end, divided by period end trust units outstanding including trust units issuable for exchangeable shares. &gt;&gt; </pre> <p>ARC's business plan has resulted in significant operational success as seen in Table 2 where ARC's trailing five year annualized return per unit was 12.4 per cent. </p> <pre> &lt;&lt; Table 2 ------------------------------------------------------------------------- Total Returns(1) ($ per unit except for Trailing Trailing Trailing per cent) One Year Three Year Five Year ------------------------------------------------------------------------- Distributions per unit 1.28 6.35 10.74 Capital (depreciation) appreciation per unit (0.16) (2.36) 2.04 Total return per unit 6.9% 20.0% 79.5% Annualized total return per unit 6.9% 6.3% 12.4% S&amp;P/TSX Capped Energy Trust Index 43.5% 2.5% 9.1% ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Calculated as at December 31, 2009. Financial Highlights for the year-ended December 31, 2009 Table 3 ------------------------------------------------------------------------- (Cdn $ millions, except per unit and volume data) 2009 2008 % Change ------------------------------------------------------------------------- Cash flow from operating activities 497.4 944.4 (47) Cash flow from operating activities per unit(1) 2.11 4.37 (52) Net income 222.8 533.0 (58) Net income per unit(2) 0.96 2.50 (62) Distributions per unit(3) 1.28 2.67 (52) Distributions as a per cent of cash flow from operating activities 60 60 - Average daily production (boe/d)(4) 63,538 65,126 (2) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Per unit amounts are based on weighted average trust units outstanding plus trust units issuable for exchangeable shares at period 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 distribution record 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 boe in isolation may be misleading. &gt;&gt; </pre> <p>2009 Guidance and Financial Highlights </p> <p>Table 4 is a summary of ARC's 2009 and 2010 Guidance and a review of 2009 actual results compared to guidance. </p> <pre> &lt;&lt; Table 4 ------------------------------------------------------------------------- 2009 2009 2010 Guidance Actual % Variance Guidance ------------------------------------------------------------------------- Production (boe/d) 63,000- 63,538 - 70,500- 64,000 72,500 ------------------------------------------------------------------------- Expenses ($/boe): Operating costs 10.50 10.19 (3) 10.30 Transportation 0.90 0.89 (1) 1.00 G&amp;A expenses (cash &amp; non-cash)(1) 2.10 2.26 8 2.85 Interest 1.30 1.11 (15) 1.40 Capital expenditures ($ millions) 365 360 (1) 610 Annual weighted average trust units and trust units issuable (millions)(2) 238 235 (1) 254 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) 2009 G&amp;A guidance amount of $2.10 per boe included $1.75 per boe for cash G&amp;A costs, $0.55 per boe for cash Whole Unit Plan costs and a recovery of $0.20 per boe for the non-cash portion of the Whole Unit Plan. 2010 G&amp;A guidance amount of $2.85 per boe includes $2 per boe for cash G&amp;A costs, $0.90 per boe for cash Whole Unit Plan costs and a recovery of $0.05 per boe for the non-cash portion of the Whole Unit Plan. (2) 2010 Annual weighted average trust units has been revised to reflect the increase in the equity offering that closed in January 2010 from 10.1 million to 13 million units. &gt;&gt; </pre> <p>Actual results for 2009 are in-line with guidance amounts with the exception of the following: </p> <p>G&amp;A expenses - total cash G&amp;A costs were $0.04 per boe below guidance however actual non-cash Whole Unit Plan costs were nil for the year whereas the guidance amount was estimating a recovery of $0.20 per boe. The difference is due to ARC's December 31, 2009 closing trust unit price that was higher than the amount estimated when calculating the original guidance amount. </p> <p>Interest expense - was below guidance for the full year of 2009 due to ARC's ability to cash fund more capital expenditures in the last half of 2009 with the uplift in commodity prices, therefore drawing less funds from debt and saving on interest expense. </p> <p>The 2010 Guidance provides unitholders with information on management's expectations for results of operations, excluding any acquisitions or dispositions for 2010. Readers are cautioned that the 2010 Guidance may not be appropriate for other purposes. </p> <p>Cash Flow from Operating Activities </p> <p>Cash flow from operating activities decreased by 47 per cent in 2009 to $497.4 million from $944.4 million in 2008. Decreases in crown royalties and a cash gain on risk management contracts were more than offset by the 41 per cent ($29.18 per boe) decrease in commodity prices relative to the full year of 2008 as well as a two per cent decrease in volumes during the period. The decrease in 2009 cash flow from operating activities is detailed in Table 5. </p> <pre> &lt;&lt; Table 5 ------------------------------------------------------------------------- ($ per ($ millions) trust unit) (% Change) ------------------------------------------------------------------------- 2008 Cash flow from Operating Activities 944.4 4.37 - ------------------------------------------------------------------------- Volume variance (46.2) (0.21) (5) Price variance (682.0) (3.15) (72) Cash (losses) and gains on risk management contracts 95.1 0.44 10 Royalties 159.9 0.74 17 Expenses: Transportation (1.6) (0.01) (0.2) Operating(1) 6.1 0.03 0.6 Cash G&amp;A 7.7 0.04 0.8 Interest 7.2 0.03 0.8 Taxes (0.3) - - Realized foreign exchange loss 1.9 0.01 0.2 Weighted average trust units - (0.22) - Non-cash and other items(2) 5.2 0.02 - ------------------------------------------------------------------------- 2009 Cash flow from Operating Activities 497.4 2.09 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Excludes non-cash portion of Whole Unit Plan expense recorded in operating costs. (2) Includes the changes in non-cash working capital and expenditures on site restoration and reclamation. &gt;&gt; </pre> <p>2010 Cash Flow from Operating Activities Sensitivity </p> <p>Table 6 illustrates sensitivities to pre-hedged operating income items with operational changes and changes to the business environment and the resulting impact on cash flows from operating activities in total and per trust unit: </p> <pre> &lt;&lt; Table 6 ------------------------------------------------------------------------- Impact on Annual Cash flow from operating activities(4) Business Environment(1) Assumption Change $/Unit ------------------------------------------------------------------------- Oil price (US$WTI/bbl)(2)(3) $ 75.00 $ 1.00 $ 0.04 Natural gas price (Cdn$AECO/mcf)(2)(3) $ 5.50 $ 0.10 $ 0.03 Cdn$/US$ exchange rate(2)(3)(5) 1.05 $ 0.01 $ 0.03 Interest rate on debt(2) % 4.00 % 1.0 $ 0.01 Operational Liquids production volume (bbl/d) 31,500 % 1.0 $ 0.03 Gas production volumes (mmcf/d) 240.0 % 1.0 $ 0.01 Operating expenses per boe $ 10.30 % 1.0 $ 0.01 Cash G&amp;A and LTIP expenses per boe $ 2.85 % 10.0 $ 0.03 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Calculations are performed independently and may not be indicative of actual results that would occur when multiple variables change at the same time. (2) Prices and rates are indicative of published forward prices and rates at the time of this MD&amp;A. The calculated impact on annual cash flow from operating activities would only be applicable within a limited range of these amounts. (3) Analysis does not include the effect of hedging contracts. (4) Assumes constant working capital. (5) Includes impact of foreign exchange on crude oil prices that are presented in U.S. dollars. This amount does not include a foreign exchange impact relating to natural gas prices as they are presented in Canadian dollars in this sensitivity. &gt;&gt; </pre> <p>Net Income </p> <p>Net income in 2009 was $222.8 million ($0.96 per unit), a decrease of $310.2 million from $533 million ($2.50 per unit) in 2008. Net income for 2009 reflects the lower commodity price environment in the current year and includes certain non-cash items that served to increase net income in the current year. </p> <p>In 2009, ARC recorded a $69 million non-cash foreign exchange gain on U.S. denominated debt ($60.4 million net of future income taxes) as compared to a non-cash loss of $88.5 million ($77.4 million net of future income taxes) recorded for the same period in 2008. </p> <p>In 2009, ARC recorded a $1.7 million net cash recovery for non-recoverable accounts receivable ($1.3 million net of future income taxes) as compared to a $32 million ($24 million net of future income taxes) non-cash expense for non-recoverable amounts recorded in 2008. </p> <p>The above amounts were offset by a $7.7 million ($5.8 million net of future income taxes) non-cash loss on unrealized risk management contracts recorded in 2009 as compared to a $68 million ($51 million net of future income taxes) non-cash unrealized gain recorded for the same period in 2008. </p> <p>Production </p> <p>Production volumes averaged 63,538 boe per day in 2009 compared to 65,126 boe per day in 2008 as detailed in Table 7. The decrease in 2009 production is a result of the reduction of the capital expenditure program. </p> <pre> &lt;&lt; Table 7 ------------------------------------------------------------------------- Production 2009 2008 % Change ------------------------------------------------------------------------- Light &amp; medium crude oil (bbl/d) 26,423 27,239 (3) Heavy oil (bbl/d) 1,086 1,274 (15) Natural gas (mmcf/d) 194.0 196.5 (1) NGL (bbl/d) 3,689 3,861 (4) ------------------------------------------------------------------------- Total production (boe/d)(1) 63,538 65,126 (2) % Natural gas production 51 50 2 % Crude oil and liquids production 49 50 (2) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Reported production for a period may include minor adjustments from previous production periods. &gt;&gt; </pre> <p>Light and medium crude oil production decreased to 26,423 boe per day compared to 27,239 boe per day in 2008, while heavy oil production declined by 188 boe per day. Compared to 2008, the total crude oil production is down approximately 1,000 barrels per day. Natural gas production was 194 mmcf per day in 2009, a decrease of one per cent from the 196.5 mmcf per day produced in 2008. This slight decline was primarily due to plant turnarounds completed at third party facilities that shut-in gas production. </p> <p>ARC's objective is to maintain annual production through the drilling of wells and other development activities to the full extent possible, while giving consideration to capital spending constraints and the economics of developing ARC's resources. In fulfilling this objective, there may be fluctuations in production depending on the timing of new wells coming on-stream. During 2009, ARC drilled 145 gross wells (120 net wells) on operated properties; 37 gross oil wells, and 108 gross natural gas wells with a 99 per cent success rate. </p> <p>ARC expects that 2010 full year production will average approximately 70,500 to 72,500 boe per day and that a total of 211 gross wells (195 net) will be drilled by ARC on operated properties with participation in an additional 91 gross wells (18 net) to be drilled on ARC's non-operated properties. ARC estimates that the 2010 drilling program and the start-up of a new gas plant in the Dawson area will increase production in 2010 by 11 per cent to 14 per cent over 2009 production levels. The planned capital expenditures for 2010 have been increased to approximately $610 million from actual expenditures of $360 million in 2009, which were scaled back from an original 2009 planned budget of $585 million due to the significant decline in commodity prices. </p> <p>Table 8 summarizes ARC's production by core area: </p> <pre> &lt;&lt; Table 8 ------------------------------------------------------------------------- 2009 Production Total Oil Gas NGL Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d) ------------------------------------------------------------------------- Central AB 6,984 1,279 27.7 1,083 N.E. BC &amp; N.W. AB 13,794 715 74.4 672 Northern AB 9,004 4,096 24.5 821 Pembina &amp; Redwater 13,560 9,412 19.0 978 S.E. AB &amp; S.W. Sask. 8,841 1,027 46.9 13 S.E. Sask. &amp; MB 11,357 10,980 1.5 122 ------------------------------------------------------------------------- Total 63,538 27,509 194.0 3,689 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2008 Production Total Oil Gas NGL Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d) ------------------------------------------------------------------------- Central AB 7,495 1,406 29.2 1,218 N.E. BC &amp; N.W. AB 12,678 802 67.6 613 Northern AB 9,791 4,516 26.1 921 Pembina &amp; Redwater 13,707 9,495 19.7 936 S.E. AB &amp; S.W. Sask. 9,701 985 52.2 11 S.E. Sask. &amp; MB 11,754 11,309 1.7 162 ------------------------------------------------------------------------- Total 65,126 28,513 196.5 3,861 ------------------------------------------------------------------------- (1) Provincial references: AB is Alberta, BC is British Columbia, Sask. is Saskatchewan, MB is Manitoba, N.E. is northeast, N.W. is northwest, S.E. is southeast and S.W. is southwest. &gt;&gt; </pre> <p>Revenue </p> <p>Revenue decreased to $978.2 million in 2009, $728.2 million lower than 2008 revenues of $1.7 billion. The decrease in realized oil prices accounted for $333.5 million of the $358.1 million decline in oil revenue with only $24.6 million of the decrease attributable to lower oil volumes. Natural gas revenue decreased by $320.8 million of which $316.5 million was attributable to decreased realized prices with the balance of $4.3 million attributed to lower natural gas volumes in 2009. </p> <p>A breakdown of revenue is outlined in Table 9: </p> <pre> &lt;&lt; Table 9 ------------------------------------------------------------------------- Revenue ($ millions) 2009 2008 % Change ------------------------------------------------------------------------- Oil revenue 625.0 983.1 (36) Natural gas revenue 296.0 616.8 (52) NGL revenue 54.8 98.5 (44) ------------------------------------------------------------------------- Total commodity revenue 975.8 1,698.4 (43) Other revenue 2.4 8.0 (70) Total revenue 978.2 1,706.4 (43) ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>Commodity Prices Prior to Hedging </p> <pre> &lt;&lt; Table 10 ------------------------------------------------------------------------- 2009 2008 % Change ------------------------------------------------------------------------- Average Benchmark Prices AECO gas ($/mcf)(1) 4.13 8.13 (49) WTI oil (US$/bbl)(2) 61.93 99.66 (38) Cdn$ / US$ foreign exchange rate 1.13 1.05 8 WTI oil (Cdn$/bbl) 69.70 104.30 (33) ------------------------------------------------------------------------- ARC Realized Prices Prior to Hedging Oil ($/bbl) 62.24 94.20 (34) Natural gas ($/mcf) 4.18 8.58 (51) NGL ($/bbl) 40.67 69.71 (42) ------------------------------------------------------------------------- Total commodity revenue before hedging ($/boe) 42.07 71.25 (41) Other revenue ($/boe) 0.11 0.34 (68) Total revenue before hedging ($/boe) 42.18 71.59 (41) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Represents the AECO monthly posting. (2) WTI represents posting price of West Texas Intermediate oil. &gt;&gt; </pre> <p>Oil prices continued to recover in the second half of 2009 with US$WTI prices averaging $76.17 per bbl in the fourth quarter, and $68.29 per bbl in the third quarter compared to $51.46 per bbl for the first half of 2009. Despite this recovery, prices for oil on average in 2009 were down 38 per cent compared to 2008 as detailed in Table 10. ARC's oil production consists predominantly of light and medium crude oil while heavy oil accounts for less than five per cent of ARC's crude oil production. The realized price for ARC's oil, before hedging, was $62.24 per bbl, a 34 per cent reduction over the 2008 realized price of $94.20 per bbl. </p> <p>Natural gas prices softened throughout 2009 with a strengthening in the fourth quarter. Alberta AECO Hub natural gas prices, which are commonly used as an industry reference, averaged $4.13 per mcf in 2009 compared to $8.13 per mcf in 2008. ARC's realized gas price, before hedging, decreased by 51 per cent to $4.18 per mcf compared to $8.58 per mcf throughout 2008. ARC's realized gas price is based on prices received at the various markets in which ARC sells its natural gas. ARC's natural gas sales portfolio consists of gas sales priced at the AECO monthly index, the AECO daily spot market, eastern and mid-west United States markets and a portion to aggregators. Natural gas prices started to recover in the fourth quarter of 2009 with posted prices in the month of December registering over $5 per mcf. In addition, the forward curve for natural gas prices has strengthened to reflect 2010 prices of approximately $6 per mcf. Management is pursuing strategic initiatives to capitalize on strengthening forward prices, where possible in order to protect the economics of the 2010 capital program. </p> <p>Prior to hedging activities, ARC's total realized commodity price was $42.17 per boe in 2009, a 41 per cent decrease from the $71.59 per boe in 2008. </p> <p>Risk Management and Hedging Activities </p> <p>ARC maintains an ongoing risk management program to reduce the volatility of revenues in order to increase the certainty of cash flows, and to protect acquisition and capital expenditures economics. </p> <p>Gain or loss on risk management contracts comprise realized and unrealized gains or losses on contracts that do not meet the accounting definition requirements of an effective hedge, even though ARC considers all risk management contracts to be effective economic hedges. Accordingly, gains and losses on such contracts are shown as a separate category in the Consolidated Statements of Income and Deficit. </p> <p>Lower natural gas prices in 2009 resulted in realized cash gains of $28.5 million on natural gas risk management contracts as ARC's contracted prices were higher than market prices during the year. Realized cash losses of $14.8 million were recorded on ARC's crude oil risk management contracts as a result of premiums paid during 2009, and small losses recorded on ARC's fixed price swap contracts where the market oil price rose above the contracted price. In addition, ARC realized a $4.8 million cash gain on interest rate risk management contracts. </p> <p>ARC's 2009 results include an unrealized total mark-to-market loss of $7.7 million with a net unrealized mark-to-market loss position of $4.8 million as at December 31, 2009. The mark-to-market values represent the market price to buy-out ARC's contracts as of December 31, 2009 and may differ from what will eventually be realized. </p> <p>Table 11 summarizes the total gain (loss) on risk management contracts for the year-over-year change as of the 2009 year-end: </p> <pre> &lt;&lt; Table 11 ------------------------------------------------------------------------- Risk Management Crude Foreign Contracts Oil &amp; Natural Curr- Inter- 2009 2008 ($ millions) Liquids Gas ency Power(3) est Total Total ------------------------------------------------------------------------- Realized cash (loss) gain on contracts(1) (14.8) 28.5 2.0 (1.1) 4.8 19.4 (75.7) Unrealized gain (loss) on contracts(2) 5.0 (2.5) - (4.8) (5.4) (7.7) 68.0 ------------------------------------------------------------------------- Total (loss) gain on risk management contracts (9.8) 26.0 2.0 (5.9) (0.6) 11.7 (7.7) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Realized cash gains and losses represent actual cash settlements or receipts under the respective contracts. (2) The unrealized gain (loss) on contracts represents the change in fair value of the contracts during the period. (3) Amounts presented in Table 11 exclude a $1.5 million realized loss and an unrealized loss of $3.8 million for ARC's power contracts that have been designated as effective hedges for accounting purposes. Realized gains and losses on these contracts are recorded in operating costs and unrealized gains and losses are recorded in the Consolidated Statement of Comprehensive Income and Accumulated Other Comprehensive Income. &gt;&gt; </pre> <p>ARC currently limits the amount of forecast production that can be hedged to a maximum 50 per cent with the balance of production being sold at market prices. In addition, project specific hedges may be entered into from time to time to protect the economics of certain capital expenditures. Table 12 is an indicative summary of ARC's positions for crude oil and natural gas as at December 31, 2009. </p> <pre> &lt;&lt; Table 12 ------------------------------------------------------------------------- Hedge Positions As at December 31, 2009(1)(2) Q1 2010 Q2 2010 ------------------------------------------------------------------------- Crude Oil US$/bbl bbl/day US$/bbl bbl/day ------------------------------------------------------------------------- Sold Call 95.36 9,000 96.81 8,000 Bought Put 76.17 9,000 77.19 8,000 Sold Put 62.80 2,000 62.80 2,000 ------------------------------------------------------------------------- Natural Gas Cdn$/mcf mcf/day Cdn$/mcf mcf/day ------------------------------------------------------------------------- Sold Call 5.92 75,825 5.77 95,825 Bought Put 5.92 75,825 5.77 95,825 Sold Put - - - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- Hedge Positions As at December 31, 2009(1)(2) Q3 2010(3) Q4 2010 ------------------------------------------------------------------------- Crude Oil US$/bbl bbl/day US$/bbl bbl/day ------------------------------------------------------------------------- Sold Call 96.81 8,000 96.81 8,000 Bought Put 77.19 8,000 77.19 8,000 Sold Put 62.80 2,000 62.80 2,000 ------------------------------------------------------------------------- Natural Gas Cdn$/mcf mcf/day Cdn$/mcf mcf/day ------------------------------------------------------------------------- Sold Call 5.77 95,825 5.92 75,825 Bought Put 5.77 95,825 5.92 75,825 Sold Put - - - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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. (2) In addition to positions shown here, ARC has entered into additional basis positions until October 2012. Please refer to note 13 in the Notes to the Consolidated Financial Statements for full details of ARC's risk management positions as of December 31, 2009. (3) During the last half of 2009, ARC took advantage of favorable forward curve pricing for natural gas and entered into a long-term contract for a small portion of future forecast production. In addition to contracts listed above, ARC has entered into fixed price swaps starting in 2011 and ending in December 2013 at an average price of $6.40 per mcf for 42,654 mcf per day. &gt;&gt; </pre> <p>Table 12 should be interpreted as follows using the first quarter 2010 crude oil hedges as an example. To accurately analyze ARC's hedge position, contracts need to be modeled separately as using average prices and volumes may be misleading. </p> <pre> &lt;&lt; - If the market price is below $62.80, ARC will receive $76.17 less the difference between $62.80 and the market price on 2,000 bbl per day. For example, if the market price is $62.75, ARC will receive $76.12 on 2,000 bbl per day. - If the market price is between $62.80 and $76.17, ARC will receive $76.17 on 9,000 bbl per day. - If the market price is between $76.17 and $95.36, ARC will receive the market price on 9,000 bbl per day. - If the market price exceeds $95.36, ARC will receive $95.36 on 9,000 bbl per day. &gt;&gt; </pre> <p>Operating Netbacks </p> <p>ARC's operating netback, before realized hedging gains and losses, decreased 48 per cent to $24.72 per boe in 2009 compared to $47.75 per boe in 2008. The decrease in netbacks is due mainly to reduced commodity prices partially offset by the corresponding reduction in royalties in the period. </p> <p>ARC's 2009 netback, after realized hedging gains and losses, was $25.26 per boe, a 43 per cent decrease from 2008. The 2009 netback includes net gains recorded on ARC's crude oil and natural gas risk management contracts during 2009 of $0.54 per boe compared to a net loss of $3.17 per boe recorded for the same period in 2008. </p> <p>The components of operating netbacks are summarized in Table 13: </p> <pre> &lt;&lt; Table 13 ------------------------------------------------------------------------- Crude Heavy 2009 2008 Netbacks Oil Oil Gas NGL Total Total ($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe) ------------------------------------------------------------------------- Weighted average sales price 62.51 55.74 4.18 40.67 42.07 71.25 Other revenue - - - - 0.10 0.34 ------------------------------------------------------------------------- Total revenue 62.51 55.74 4.18 40.67 42.17 71.59 Royalties (9.63) (5.34) (0.50) (13.03) (6.37) (12.91) Transportation (0.18) (1.15) (0.26) - (0.89) (0.80) Operating costs(1) (12.88) (12.46) (1.33) (7.85) (10.19) (10.13) ------------------------------------------------------------------------- Netback prior to hedging 39.82 36.79 2.09 19.79 24.72 47.75 Realized (loss) gain on risk management contracts(2) (1.65) - 0.40 - 0.54 (3.17) ------------------------------------------------------------------------- Netback after hedging 38.17 36.79 2.49 19.79 25.26 44.58 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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 include the settlement amounts for crude oil and natural gas and power contracts. Foreign exchange and interest contracts are excluded from the net back calculation. &gt;&gt; </pre> <p>Royalties as a percentage of pre-hedged commodity revenue net of transportation decreased to 15.4 per cent ($6.37 per boe) in 2009 compared to 18.2 per cent ($12.91 per boe) in 2008. </p> <p>The Alberta Government's Alberta Royalty Framework ("Framework" or "ARF") took effect January 1, 2009 and provides for sliding scale crown royalty rates, whereby rates increase in high commodity price environments and decrease in low commodity price environments. The 2009 royalty rate is in line with management's expectations due to the low natural gas price environment. The recovery of crude oil prices in the second half of 2009 has resulted in higher oil crown royalty payments as compared to the first half of 2009, while natural gas crown royalty payments were low until December of 2009 when prices started to increase more significantly. </p> <p>Royalty rates in the other western provinces vary due to production levels and price but to a lesser extent than Alberta royalty rates. Table 14 estimates the royalties applicable to production from ARC's properties at various price levels. </p> <pre> &lt;&lt; Table 14 ------------------------------------------------------------------------- Provincial Royalty Rates - Forecast for 2010 ------------------------------------------------------------------------- Edmonton posted oil (Cdn/$/bbl)(1) $60 $80 $100 AECO natural gas (Cdn$/mcf)(1) $4.00 $5.50 $6.50 ------------------------------------------------------------------------- Alberta royalty rate 12.6% 18.1% 22.6% Saskatchewan royalty rate(2) 17.9% 17.9% 17.9% British Columbia royalty rate(2) 17.0% 17.0% 17.0% Manitoba royalty rate(2) 13.0% 13.0% 13.0% ------------------------------------------------------------------------- Total Corporate Royalty Rate 14.6% 17.8% 20.4% ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Canadian dollar denominated prices before quality differentials. (2) Royalty rate includes Crown, Freehold and Gross Override royalties for all jurisdictions in which ARC operates. &gt;&gt; </pre> <p>Following the implementation of the ARF, the Alberta Government introduced certain transitional rates and incentive programs to provide royalty relief to producers and in turn encourage continued drilling activity in the province. ARC is eligible for the Alberta programs assuming the necessary criteria are met and required elections are filed. The drilling credit program applies to new wells drilled between April 1, 2009 and March 31, 2011. At year-end, ARC has accrued credits of $8.1 million and estimates it will generate a maximum $16.5 million credit over the life of the program based on forward looking prices. ARC is automatically eligible for the reduced royalty rate incentive on new production for wells coming on production between April 1, 2009 and March 31, 2011. These wells will receive a crown royalty rate of five per cent subject to certain production limits. </p> <p>During 2009, the British Columbia government announced a new stimulus package designed to attract investment and produce immediate economic benefits for the province. The stimulus package included royalty incentives in the form of reduced royalty rates for wells drilled in the province between September 1, 2009 and June 30, 2010, and modifications to the existing deep well drilling program to increase available credits and expand depth criteria whereby additional wells may qualify for the program. ARC estimates that the deep well drilling credits could save approximately $1 million per horizontal well drilled. These credits will be recorded as a reduction to royalty expense to the extent that royalties are incurred on the well drilled. The royalty reduction program will result in a two per cent maximum royalty rate for a period of 12 months. Management estimates that for wells that do not qualify for the drilling credit program, the reduced royalty incentive could generate savings of $1 million per well at natural gas prices of $3 per mcf to $2.5 million per well at natural gas prices of $7 per mcf. Wells that qualify for the drilling credit program must draw down the drilling credit before qualifying for the reduced royalty program. Management plans to drill 20 wells in British Columbia on operated properties during the incentive period in order to maximize the total benefit to ARC and its unitholders. New wells drilled that will qualify for the two per cent royalty incentive are expected to come on production in the third and fourth quarters of 2010. </p> <p>Operating costs remained flat at $10.19 per boe compared to $10.13 per boe in 2008 with the costs associated with operating new wells brought on stream offset by lower electricity costs and cost savings and efficiency programs achieved by the operations team. </p> <p>Looking ahead to 2010, ARC expects to incur full year operating costs of $10.30 per boe or approximately $270 million based on annual production of between 70,500 and 72,500 boe per day. </p> <p>General and Administrative Expenses ("G&amp;A") and Trust Unit Incentive Compensation </p> <p>G&amp;A, prior to long-term incentive payments under the Whole Unit Plan and net of overhead recoveries on operated properties, increased 4.9 per cent to $40.7 million in 2009 from $38.8 million in 2008. The modest increase in G&amp;A expenses was primarily due to a decrease in operating recoveries of $1.4 million resulting from lower levels of capital spending during 2009. </p> <p>Cash G&amp;A in 2010 is expected to increase by approximately $10.6 million with increases in compensation and additional staff hires required to exploit our growth opportunities including the Montney, Ante Creek and Pembina assets as well as additional rent costs for the Calgary office relocation. ARC's Calgary office lease on its existing space terminates in May of 2010 and ARC has secured new space at a competitive rate on a 14 year term. ARC has committed to additional space in the new premises to accommodate future growth and expansion that will result in higher year-over-year cash G&amp;A costs. ARC has hired an agent to sublet near-term excess space to partially offset this additional cost. </p> <p>ARC paid out $16.6 million under the Whole Unit Plan in 2009 compared to $28.2 million in 2008 ($11.7 million and $21.3 million of the payouts were allocated to G&amp;A in 2009 and 2008, respectively, and the remainder to operating costs and property, plant and equipment). The reduced payments in 2009 are a result of the decline in ARC's unit price observed throughout 2009 and specifically in March and September when cash payments were made. The next cash payment under the Whole Unit Plan is scheduled to occur in March 2010. </p> <p>Table 15 is a breakdown of G&amp;A and trust unit incentive compensation expense under the Whole Unit Plan: </p> <pre> &lt;&lt; Table 15 ------------------------------------------------------------------------- G&amp;A and Trust Unit Incentive Compensation Expense ($ millions except per boe) 2009 2008 % Change ------------------------------------------------------------------------- G&amp;A expenses 56.1 55.6 1 Operating recoveries (15.4) (16.8) (8) ------------------------------------------------------------------------- Cash G&amp;A expenses before Whole Unit Plan 40.7 38.8 5 Cash Expense - Whole Unit Plan 11.7 21.3 (45) ------------------------------------------------------------------------- Cash G&amp;A expenses including Whole Unit Plan 52.4 60.1 (13) Accrued compensation - Whole Unit Plan (0.1) 1.1 (109) ------------------------------------------------------------------------- Total G&amp;A and trust unit incentive compensation expense 52.3 61.2 (15) ------------------------------------------------------------------------- Total G&amp;A and trust unit incentive compensation expense per boe 2.26 2.57 (12) ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>A non-cash Whole Unit Plan recovery ("non-cash compensation recovery") of $0.1 million ($nil per boe) was recorded in 2009 compared to an expense of $1.1 million ($0.05 per boe) in 2008. The recovery in 2009 relates to the estimated costs of the plan to December 31, 2009, offset by a reversal of the accrual for the cash payments made during the year. </p> <p>Whole Unit Plan </p> <p>The Whole Unit Plan is designed to offer each employee, officer and director (the "plan participants") 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 total return performance of ARC 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. A performance multiplier is applied to the PTUs based on the percentile rank of ARC's total unitholder return compared to its peers. 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 year of RTUs and PTUs outstanding: </p> <pre> &lt;&lt; Table 16 ------------------------------------------------------------------------- Whole Unit Plan (units in thousands and $ millions Number of Number of Total RTUs except per unit) RTUs PTUs and PTUs ------------------------------------------------------------------------- Balance, beginning of period 756 959 1,715 Granted in the period 703 635 1,338 Vested in the period (355) (261) (616) Forfeited in the period (52) (28) (80) ------------------------------------------------------------------------- Balance, end of period(1) 1,052 1,305 2,357 Estimated distributions to vesting date(2) 183 318 501 ------------------------------------------------------------------------- Estimated units upon vesting after distributions 1,235 1,623 2,858 Performance multiplier(3) - 1.2 - ------------------------------------------------------------------------- Estimated total units upon vesting 1,235 1,996 3,231 ------------------------------------------------------------------------- Trust unit price at December 31, 2009 19.94 19.94 19.94 Estimated total value upon vesting 24.6 39.8 64.4 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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 1.2 at December 31, 2009 based on an average calculation of all outstanding grants. The performance multiplier is assessed each period end based on actual results of ARC relative to its peers except during the first year of each grant where a performance multiplier of 1.0 is used. &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, ARC'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 December 31, 2009: </p> <pre> &lt;&lt; Table 17 ------------------------------------------------------------------------- Value of Whole Unit Plan as at December 31, 2009 Performance multiplier (units thousands and $ millions -------------------------------- except per unit) - 1.0 2.0 ------------------------------------------------------------------------- Estimated trust units to vest RTUs 1,235 1,235 1,235 PTUs - 1,623 3,246 ------------------------------------------------------------------------- Total units(1) 1,235 2,858 4,482 ------------------------------------------------------------------------- Trust unit price(2) 19.94 19.94 19.94 Trust unit distributions per month(2) 0.10 0.10 0.10 ------------------------------------------------------------------------- Value of Whole Unit Plan upon vesting(3) 24.6 57.0 89.4 ------------------------------------------------------------------------- 2010 11.0 19.7 28.4 2011 8.2 16.8 25.3 2012 5.4 20.5 35.7 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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 a future trust unit price of $19.94 and $0.10 per trust unit distributions based on the unit price and distribution levels in place at December 31, 2009. (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 September 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, ARC estimates that between $24.6 million and $89.4 million will be paid out from 2010 through 2012 based on the current trust unit price, distribution levels and ARC's market performance relative to its peers. </p> <p>Provision for Non-recoverable Accounts Receivable </p> <p>For the year ended December 31, 2009, ARC recorded a recovery of $1.7 million for amounts received on balances previously included in ARC's allowance for doubtful accounts. The recovery includes $1.2 million for settlement of oil revenues that were previously due from SemCanada Crude ("SemCanada"), a counterparty that marketed a portion of ARC's production, and had filed for protection under the Companies' Creditors Arrangement Act in 2008. The remaining $0.5 million is composed of $0.6 million recovered from one counterparty and $0.1 million written off for balances deemed uncollectable from various counterparties. </p> <p>Interest and Financing Charges </p> <p>Interest and financing charges decreased to $25.7 million in 2009 from $32.9 million in 2008 due to a decrease in short-term interest rates as well as a reduction in debt outstanding. As at December 31, 2009, ARC had $846.1 million of long-term debt outstanding, of which $340.9 million was fixed at a weighted average rate of 5.9 per cent and $505.2 million, including the working capital facility, was floating at current market rates plus a credit spread of 60 to 65 basis points. Forty-six per cent (US$369.1 million) of ARC's debt outstanding is denominated in U.S. dollars. ARC's credit facility is a three year facility maturing in April 2011. Management's current expectation is that the current credit spread would increase upon renewal by 150 to 250 basis points. </p> <p>Foreign Exchange Gains and Losses </p> <p>ARC recorded a gain of $70 million in 2009 on foreign exchange transactions compared to a loss of $89.4 million in 2008. 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. There was a $1 million cash realized foreign exchange gain during the year, as well as a net non-cash realized gain of $2.7 million was recorded relating to debt repayments of $17.2 million made during the year. These debt repayments were financed with ARC's credit facility and therefore are considered to be non-cash transactions. </p> <p>Unrealized foreign exchange gains and losses are due to revaluation of U.S. denominated debt balances. The volatility of the Canadian dollar during the reporting period has a direct impact on the unrealized component of the foreign exchange gain or loss. The unrealized gain or loss impacts net income but does not impact cash flow from operating activities as it is a non-cash amount. From December 31, 2008 to December 31, 2009, the Cdn$/US$ exchange rate decreased from 1.22 to 1.05 resulting in an unrealized gain of $66.3 million on U.S. dollar denominated debt. </p> <p>Taxes </p> <p>In 2009, a future income tax recovery of $32.8 million was included in income compared to a recovery of $4.5 million in 2008. The current year recovery primarily relates to property, plant and equipment, and is a result of the depletion deduction claimed for accounting purposes exceeding the tax pools claimed for income tax purposes. The current year recovery attributable to property, plant and equipment is partially offset by a future income tax liability relating to the unrealized foreign exchange gain on long-term debt. In 2009, ARC's expected future corporate income tax rate decreased marginally from 25.3 per cent to 25.1 per cent. </p> <p>The corporate income tax rate applicable to 2009 is 29 per cent; however, ARC and its subsidiaries did not pay any cash income taxes for fiscal 2009. Due to ARC's structure, currently, both income tax and future tax liabilities are passed on to the unitholders by means of royalty payments made between ARC Resources and ARC. </p> <p>Management continues to work on the plan for converting ARC Energy Trust to a corporation on January 1, 2011. After the conversion, the corporation would expect to allocate its cash flow among funding a portion of capital expenditures, periodic debt repayments, site reclamation expenditures, and cash payments to shareholders in the form of dividends. Current taxes payable by ARC after converting to a corporation will be subject to normal corporate tax rates. Taxable income as a corporation will vary depending on total income and expenses and vary with changes to commodity prices, costs and claims for both accumulated tax pools and tax pools associated with current year expenditures. As ARC has accumulated $2.2 billion of income tax pools, ARC expects that taxable income will be reduced or potentially eliminated for the initial period post conversion. The $2.2 billion of income tax pools (detailed in Table 18) are deductible at various rates and annual deductions associated with the initial tax pools will decline over time. </p> <pre> &lt;&lt; Table 18 ------------------------------------------------------------------------- Income Tax Cdn $ millions at Pool type December, 2009 Annual deductibility ------------------------------------------------------------------------- Canadian Oil and Gas Property Expense 951.6 10% declining balance Canadian Development Expense 391.1 30% declining balance Canadian Exploration Expense 105.6 100% Undepreciated Capital Cost 432.2 Primarily 25% declining balance Non-Capital Losses 181.9 100% Research and Experimental Expenditures 0.8 100% Other 15.2 Various rates, 7% declining balance to 20% ------------------------------------------------------------------------- Total Federal Tax Pools 2,078.4 ------------------------------------------------------------------------- Additional Alberta Tax Pools 155.5 Various rates, 25% declining balance to 100% ------------------------------------------------------------------------- Total Federal and Provincial Pools 2,233.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>Returns to shareholders post conversion will be impacted by the reduction of cash flow required to pay current income taxes, if any. Over the long-term, we would expect Canadian investors who hold their trust units in a taxable account to be relatively indifferent on an after tax basis as to whether ARC is structured as a corporation or as a trust in 2011. However, Canadian tax deferred investors (those holding their trust units in a tax deferred vehicle such as an RRSP, RRIF or pension plan) and foreign investors will realize a lower after tax return on distributions in taxable years after 2011 due to the introduction of the SIFT Tax should ARC stay as a trust, and their inability to claim the dividend tax credit if ARC converts to a corporation. </p> <p>If a conversion from the trust structure to a corporation is approved by the unitholders, ARC expects there will be an opportunity to convert trust units to shares of the new corporation in a non-taxable manner; however, unitholders should consult their own tax advisor for details on the direct impact to themselves. </p> <p>Depletion, Depreciation and Accretion of Asset Retirement Obligation </p> <p>The depletion, depreciation and accretion ("DD&amp;A") rate increased to $16.66 per boe in 2009 from $15.93 per boe in 2008. ARC posted a large increase in proved reserves at year-end 2009; however, these reserves were offset by a significant increase in the future development costs required to convert proven undeveloped reserves to proven producing reserves. </p> <p>A breakdown of the DD&amp;A rate is summarized in Table 19: </p> <pre> &lt;&lt; Table 19 ------------------------------------------------------------------------- DD&amp;A Rate ($ millions except per boe amounts) 2009 2008 % Change ------------------------------------------------------------------------- Depletion of oil &amp; gas assets(1) 377.1 370.3 2 Accretion of asset retirement obligation(2) 9.3 9.3 - ------------------------------------------------------------------------- Total DD&amp;A 386.4 379.6 2 DD&amp;A rate per boe 16.66 15.93 5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes depletion of the capitalized portion of the asset retirement obligation that was capitalized to the property, plant and equipment 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>Goodwill </p> <p>The goodwill balance of $157.6 million arose as a result of the acquisition of Star Oil and Gas in 2003. The goodwill balance was determined based on the excess of total consideration paid plus the future income tax liability less the fair value of the assets, for accounting purposes, acquired in the transaction. </p> <p>Accounting standards require that the goodwill balance be assessed for impairment at least annually or more frequently if events or changes in circumstances indicate that the balance might be impaired. If such impairment exists, it would be charged to income in the period in which the impairment occurs. ARC has determined that there was no goodwill impairment as of December 31, 2009. </p> <p>Capital Expenditures and Net Acquisitions </p> <p>Capital expenditures, excluding acquisitions and dispositions, totaled $359.6 million in 2009, compared to $548.6 million in 2008. This amount was incurred on drilling and completions, geological, geophysical, facilities expenditures and corporate office costs. </p> <p>Of the total amount spent in 2009, $204.8 million was spent in ARC's resource plays, including $188.9 million for the Montney resource play in Northeast British Columbia. A total of $120.3 million was spent on ARC's conventional oil &amp; gas properties, $22.9 million was spent on ARC's enhanced oil recovery initiatives, and the balance of $11.6 million was spent on leasehold improvements for ARC's new office space in downtown Calgary. </p> <p>Included in the above capital expenditures is $8.1 million of Alberta Government royalty drilling credits recorded for the full year of 2009, as well as $3.1 million for British Columbia summer drilling credits relating to 2007 and 2008 drilling programs. Without these credits, capital expenditures would have been $370.8 million. </p> <p>In addition to the total capital expenditures during the year, ARC completed a corporate acquisition to purchase directly and indirectly all of the units of a general partnership formed to hold oil and gas assets in Ante Creek and other areas of northern Alberta ("Ante Creek") for $180 million in cash prior to normal closing adjustments. The acquisition consisted of producing wells with production of approximately 2,000 boe per day and undeveloped land holdings. This acquisition closed on December 21, 2009, and therefore financial results from the properties have been included in consolidated financial statements from that date. </p> <p>ARC completed net property dispositions of both producing property and undeveloped land of $20.5 million that included a previously disclosed disposition of non-core assets in southeast Saskatchewan for proceeds of $33.5 million. </p> <p>A breakdown of capital expenditures and net acquisitions is shown in Table 20: </p> <pre> &lt;&lt; Table 20 ------------------------------------------------------------------------- Capital Expenditures ($ millions) 2009 2008 % Change ------------------------------------------------------------------------- Geological and geophysical 13.7 27.1 (49) Drilling and completions 214.3 305.4 (30) Plant and facilities 110.0 90.4 22 Undeveloped land 7.0 122.4 (94) Other capital 14.6 3.3 342 ------------------------------------------------------------------------- Total capital expenditures 359.6 548.6 (34) ------------------------------------------------------------------------- Producing property acquisitions(1) 8.2 1.4 100 Undeveloped land property acquisitions 14.5 53.5 (73) Producing property dispositions(1) (37.3) (0.2) (100) Undeveloped land property dispositions (5.9) (3.7) 59 Corporate acquisition(2) 178.9 - 100 ------------------------------------------------------------------------- Total capital expenditures and net acquisitions 518.0 599.6 (14) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Value is net of post-closing adjustments. (2) Represents total consideration for the transactions, including fees but is prior to the related future income tax liability and asset retirement cost obligation. &gt;&gt; </pre> <p>Approximately 73 per cent of the $359.6 million capital program in 2009 was financed with cash flow from operating activities and proceeds from the distribution re-investment plan ("DRIP") compared to 91 per cent in 2008. Including proceeds from the net dispositions, capital expenditures were 51 per cent funded internally with the remaining 49 per cent funded through debt and working capital. </p> <pre> &lt;&lt; Table 21 ------------------------------------------------------------------------- Source of Funding of Capital Expenditures and Net Acquisitions ($ millions) ------------------------------------------------------------------------- 2009 2008 ------------------------------------------------------------------------- Capital Net Total Capital Net Total Expend- Acquis- Expend- Expend- Acquis- Expend- itures itions itures itures itions itures ------------------------------------------------------------------------- Expenditures 359.6 158.4 518.0 548.6 51.0 599.6 ------------------------------------------------------------------------- Per cent funded by: Cash flow from operating activities 54% - 38% 68% - 62% Proceeds from Distribution re-investment plan ("DRIP") 19% - 13% 23% - 21% Debt 27% 100% 49% 9% 100% 17% ------------------------------------------------------------------------- 100% 100% 100% 100% 100% 100% ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>Asset Retirement Obligation and Reclamation Fund </p> <p>At December 31, 2009, ARC recorded an Asset Retirement Obligation ("ARO") of $149.9 million ($141.5 million at December 31, 2008) for future abandonment and reclamation of ARC's properties. The estimated ARO includes assumptions in respect of actual costs to abandon wells or reclaim the property as well as annual inflation factors in order to calculate the undiscounted total future liability. A significant portion of the costs are projected to be incurred in years 2050 to 2060. The future liability is then discounted at a weighted average risk adjusted credit rate of 6.5 per cent to reflect ARC's cost of borrowing for the year ended December 31, 2009. </p> <p>Included in the December 31, 2009 ARO balance was a $4 million increase relating to the acquisition of the Ante Creek assets, a $3.8 million increase related to development activities and changes in estimates, $9.3 million for accretion expense in the year and a reduction of $8.7 million for actual abandonment expenditures incurred during 2009. </p> <p>ARC has established two reclamation funds to finance future asset retirement obligations; one fund has been restricted to finance obligations specifically associated with the Redwater property, with the main fund financing all other obligations. Future contributions for the two funds will vary over time in order to provide for the total estimated future abandonment and reclamation costs that are to be incurred upon abandonment of ARC's properties. Minimum contributions to the Redwater fund over the next 46 years will be approximately $86 million. The main fund has no minimum contribution requirement, however, the Board of Directors has approved voluntary contributions that currently result in annual contributions of $6 million. </p> <p>ARC's reclamation funds totaled $33.2 million as at December 31, 2009, compared to $28.2 million as at December 31, 2008. Under the terms of ARC's investment policy, reclamation fund investments and excess cash can only be invested in Canadian or U.S. Government securities, investment grade corporate bonds, or investment grade short-term money market securities. </p> <p>Capitalization, Financial Resources and Liquidity </p> <p>A breakdown of ARC's capital structure is outlined in Table 22, as at December 31, 2009 and 2008: </p> <pre> &lt;&lt; Table 22 ------------------------------------------------------------------------- Capital Structure and Liquidity ($ millions except per cent and December 31, December 31, ratio amounts) 2009 2008 ------------------------------------------------------------------------- Long-term debt 846.1 901.8 Working capital deficit(1) 56.3 60.1 ------------------------------------------------------------------------- Net debt obligations(2) 902.4 961.9 Market value of trust units and exchangeable shares(3) 4,765.7 4,405.9 ------------------------------------------------------------------------- Total capitalization(4) 5,668.1 5,367.8 ------------------------------------------------------------------------- Net debt as a percentage of total capitalization 15.9% 17.9% Net debt to cash flow from operating activities 1.8 1.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Working capital is calculated as current liabilities less the current assets as they appear on the Consolidated Balance Sheets, and excludes current unrealized amounts pertaining to risk management contracts and the current portion of future income taxes. (2) Net debt is a non-GAAP measure and therefore it may not be comparable with the calculation of similar measures for other entities. (3) Calculated using the total trust units outstanding at December 31 including the total number of trust units issuable for exchangeable shares at December 31, multiplied by the closing trust unit price of $19.94 and $20.10 for 2009 and 2008, respectively. (4) 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 ARC. &gt;&gt; </pre> <p>At December 31, 2009, ARC had total credit facilities of $1.3 billion with $846.1 million currently outstanding resulting in unused credit available of $470.5 million. On January 5, 2010 ARC closed on an equity offering of 13 million units that raised net proceeds of approximately $240 million that were used to reduce ARC's outstanding debt. As a result, ARC's credit available as at January 5, 2010 increased to approximately $710 million. </p> <p>The credit facility syndicate includes 11 domestic and international banks. ARC's debt agreements contain a number of covenants all of which were met as at December 31, 2009. These agreements are available at www.sedar.com. The major financial covenants are described below: </p> <pre> &lt;&lt; - Long-term debt and letters of credit not to exceed three times annualized net income before non-cash items and interest expense; - Long-term debt, letters of credit, and subordinated debt not to exceed four times annualized net income before non-cash items and interest expense; and - Long-term debt and letters of credit not to exceed 50 per cent of the book value of unitholders' equity and long-term debt, letters of credit and subordinated debt. &gt;&gt; </pre> <p>ARC's long-term strategy is to keep debt at less than 2.0 times cash flow from operating activities and under 20 per cent of total capitalization. This strategy resulted in manageable debt to cash flow levels in 2009. Debt to trailing cash flow from operating activities of 1.0 times at December 31, 2008 increased to 1.8 times with the significant decline in commodity prices and cash flow in 2009, but were well below the debt covenant levels of 3.0 times. In 2010, with closing of the equity offering the debt to cash flow from operating activities, ratio declined to 1.2 times. The expectation is increasing production volumes and commodity prices will result in further declines in this ratio during the course of the year. </p> <p>The weak global economic situation in 2008 and 2009 impacted ARC along with all other oil and gas entities by restricting access to capital and increasing borrowing costs. The credit situation improved dramatically during the third and fourth quarters of 2009 in the three markets that ARC typically uses to raise capital; equity, bank debt and long-term notes. </p> <p>ARC entered into a bought deal equity offering with a group of underwriters on December 14, 2009, with the intent of issuing 10.3 million units and raising approximately $189 million of net proceeds. Due to the excess demand by both institutional and retailer investors, ARC agreed to increase the size of the offering to 13 million units and raised approximately $240 million of net proceeds. The pricing, discount and fees paid for this equity offering, were similar to those for offerings prior to the 2008/2009 recession period. </p> <p>Credit conditions in the debt markets have improved dramatically in the last six months. Based on discussions with the 11 banks in ARC's revolving credit syndicate, management believes that ARC could expect to renew the $800 million credit facility on or before its maturity on April 1, 2011, at the same or larger dollar amount for a three year term. Costs of borrowing under our bank credit facilities comprise two items: first, the underlying interest rate on Bankers' Acceptances (CDN dollar loans) or LIBOR rates (U.S. denominated borrowings) and second, the credit spread to ARC. The credit spread to ARC in 2008 and 2009 ranged between 60 and 65 basis points. Upon renewal of our credit facilities, management would expect to pay a credit spread of approximately 1.5 per cent to 2.5 per cent. When added to the current three month BA rate, this would put the cost of borrowing under the revolving credit facility below three per cent, keeping bank debt ARC's lowest cost of capital. In addition to paying interest on the outstanding debt under the revolving syndicated credit facility all borrowers including ARC are charged a standby fee for the amount of the undrawn facility currently equal to 13.5 basis points. It is management's expectation that this fee will also increase upon renewal. Due to the increase of this fee, ARC will prudently establish excess credit lines to facilitate future operations and minor acquisitions with the view of increasing credit capacity when required to facilitate larger acquisitions. Bankers' Acceptance rates and LIBOR rates are at all time lows and it is expected these rates will increase as the economy recovers and central banks raise interest rates in an effort to stem inflation. </p> <p>ARC also accesses long-term debt from large institutional investors by issuing long-term notes with an average term normally of five to 10 years. The cost of this debt is based upon two factors: first, the current rate of long-term government bonds and second, ARC's credit spread. Similar to bank credit spreads, these spreads increased significantly in 2008 and early 2009 but are now declining. ARC's average interest rate on its outstanding long-term notes is 5.9 per cent with the last series of notes issued in 2009 at a blended rate of 7.5 per cent. Based upon recent issues by ARC's peers, management believes ARC could access additional funds by issuing long-term notes at a rate similar to or lower than our historical average of 5.9 per cent. </p> <p>ARC expects to finance its 2010 capital program with cash flow from operating activities, proceeds from the DRIP and existing credit capacity. If ARC undertook any major acquisitions, management would finance the transactions with a combination of debt and equity in a cost effective manner. </p> <p>Unitholders' Equity </p> <p>At December 31, 2009, there were 239 million trust units issued and issuable for exchangeable shares, an increase of 19.8 million trust units from December 31, 2008 due mostly to the issuance of 15.5 million trust units as part of an equity offering in February 2009 for net proceeds of $240 million. </p> <p>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. During 2009, ARC raised proceeds of $67 million and issued 4.1 million trust units pursuant to the DRIP at an average price of $16.21 per unit. </p> <p>On December 14, 2009 ARC entered into an agreement to sell 13 million trust units at $19.40 per trust unit to raise gross proceeds of approximately $252 million and net proceeds of approximately $240 million on a bought deal basis. This equity offering was made concurrent with ARC agreeing to purchase properties for $180 million at Ante Creek. The net proceeds of the offering were not received until January 5, 2010 at which time they reduced the outstanding indebtedness of ARC by $240 million. </p> <p>Distributions </p> <p>ARC declared distributions of $298.5 million ($1.28 per unit), representing 60 per cent of 2009 cash flow from operating activities compared to distributions of $570 million ($2.67 per unit) representing 60 per cent of cash flow from operating activities in 2008. </p> <p>The following items may be deducted from cash flow from operating activities to arrive at distributions to unitholders: </p> <pre> &lt;&lt; - a portion of capital expenditures; - annual contribution to the reclamation funds; - debt principal repayments; - income taxes if any; and - certain obligations for future payments relative to the long-term incentive compensation under the Whole Unit Plan. &gt;&gt; </pre> <p>Cash flow from operating activities and distributions in total and per unit are summarized in Table 23: </p> <pre> &lt;&lt; Table 23 ------------------------------------------------------------------------- Cash flow from operating % % activities and 2009 2008 Change 2009 2008 Change distributions ($ millions) ($ per unit) ------------------------------------------------------------------------- Cash flow from operating activities 497.4 944.4 (47) 2.11 4.37 (52) Net reclamation fund contributions(1) (4.6) (2.2) 100 (0.01) (0.01) - Capital expenditures funded with cash flow from operating activities (194.3) (372.2) (48) (0.83) (1.72) (52) Other(2) - - - 0.01 0.03 (67) ------------------------------------------------------------------------- Distributions 298.5 570.0 (48) 1.28 2.67 (52) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Includes interest income earned on the reclamation fund balances that is retained in the reclamation funds. (2) Other represents the difference due to distributions paid being based on actual trust units outstanding at each distribution date whereas per unit cash flow from operating activities, reclamation fund contributions and capital expenditures funded with cash flow from operated activities, are based on weighted average outstanding trust units in the period. &gt;&gt; </pre> <p>ARC continually assesses distribution levels, in light of commodity prices, capital expenditure programs and production volumes, to ensure that distributions are in line with the long-term strategy and objectives of ARC as per the following guidelines: </p> <pre> &lt;&lt; - To maintain a level of distributions that, in normal times, in the opinion of management and the Board of Directors, is sustainable for a minimum period of six months after factoring in the impact of current commodity prices on cash flows. ARC's objective is to normalize the effect of volatility of commodity prices rather than to pass on that volatility to unitholders in the form of fluctuating monthly distributions. - To ensure that ARC's financial flexibility is maintained by a review of ARC's debt to equity and debt to cash flow from operating activities levels. The use of cash flow from operating activities and proceeds from equity offerings to fund capital development activities, reduces the requirements of ARC to use debt to finance these expenditures. In 2009, ARC funded 54 per cent of capital development activities with a portion of cash flow from operating activities. Distributions and the actual amount of cash flows withheld to fund ARC's capital expenditure program is dependent on the commodity price environment and is subject to the approval and discretion of the Board of Directors. &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. </p> <p>Table 24 illustrates the comparison of distributions to net income as a measure of long-term sustainability. With the decline in commodity prices in 2009 relative to 2008, distributions were reduced from $0.15 per unit per month in December 2008, to $0.12 per unit per month in January 2009, and subsequently to the current rate of $0.10 per unit per month in May 2009. </p> <pre> &lt;&lt; Table 24 ------------------------------------------------------------------------- Net income and Distributions ($ millions except per cent) 2009 2008 2007 ------------------------------------------------------------------------- Net income 222.8 533.0 495.3 Distributions 298.5 570.0 498.0 ------------------------------------------------------------------------- Excess (Shortfall) (75.7) (37.0) (2.7) Excess (Shortfall) as per cent of net income (34%) (7%) (1%) ------------------------------------------------------------------------- Cash flow from operating activities 497.4 944.4 704.9 Distributions as a per cent of cash flow from operating activities 60% 60% 71% Average distribution per unit per month $0.11 $0.22 $0.20 ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>The actual amount of future monthly distributions is proposed by Management and is subject to the approval and discretion of the Board of Directors. The Board reviews future distributions in conjunction with their review of quarterly financial and operating results. </p> <pre> &lt;&lt; Table 25 ------------------------------------------------------------------------- Taxable Return of Calendar Year Distributions Portion Capital ------------------------------------------------------------------------- 2010 YTD(2) 0.10 0.10 - 2009 1.28 1.24 0.04 2008 2.67 2.62 0.05 2007 2.40 2.32 0.08 2006(1) 2.60 2.55 0.05 2005 1.94 1.90 0.04 2004 1.80 1.69 0.11 2003 1.78 1.51 0.27 2002 1.58 1.07 0.51 2001 2.41 1.64 0.77 2000 1.86 0.84 1.02 1999 1.25 0.26 0.99 1998 1.20 0.12 1.08 1997 1.40 0.31 1.09 1996 0.81 - 0.81 ------------------------------------------------------------------------- Cumulative $ 25.08 $ 18.17 $ 6.91 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Based on distributions paid and payable in 2006. (2) Based on distributions declared at January 31, 2010 and estimated taxable portion of 2010 distributions of 97 per cent. &gt;&gt; </pre> <p>Please refer to the Trust's website at www.arcresources.com for details of the monthly distribution amounts and distribution dates for 2010. </p> <p>Taxation of Distributions </p> <p>Distributions comprise a return of capital portion (tax deferred) and a return on capital portion (taxable). The return of capital component reduces the cost basis of the trust units held. For 2009, distributions declared in the calendar year will be 97 per cent return on capital or $1.24 per unit for the year (taxable) and three per cent return of capital or $0.04 per unit for the year (tax deferred). For a more detailed breakdown, please visit our website at www.arcresources.com. </p> <p>Environmental Initiatives Impacting ARC </p> <p>There are no new material environmental initiatives impacting ARC at this time. </p> <p>Contractual Obligations and Commitments </p> <p>ARC has contractual obligations in the normal course of operations including purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, lease rental obligations and employee agreements. These obligations are of a recurring, consistent nature and impact ARC's cash flows in an ongoing manner. ARC also has contractual obligations and commitments that are of a less routine nature as disclosed in Table 26. </p> <pre> &lt;&lt; Table 26 ------------------------------------------------------------------------- Payments due by period ------------------------------------------------------------------------- 1 year 2-3 4-5 Beyond Total years years 5 years ------------------------------------------------------------------------- Debt repayments(1) 34.8 571.7 107.4 132.2 846.1 Interest payments(2) 20.1 35.5 24.2 20.8 100.6 Reclamation fund contributions(3) 4.9 8.9 7.7 64.2 85.7 Purchase commitments 41.2 37.1 15.9 14.9 109.1 Transportation commitments(4) 4.8 26.6 24.2 7.1 62.7 Operating leases 4.0 13.0 14.9 74.4 106.3 Risk management contract premiums(5) 1.6 - - - 1.6 ------------------------------------------------------------------------- Total contractual obligations 111.4 692.8 194.3 313.6 1,312.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Long-term and short-term debt, excluding interest. (2) Fixed interest payments on senior secured notes. (3) Contribution commitments to a restricted reclamation fund associated with the Redwater property. (4) Fixed payments for transporting production from the Dawson gas plant, expected to be operational in early second quarter of 2010. (5) Fixed premiums to be paid in future periods on certain commodity risk management contracts. &gt;&gt; </pre> <p>The above noted risk management contract premiums are part of ARC's commitments related to its risk management program and have been recorded at fair market value at December 31, 2009 on the balance sheet as part of risk management contracts. In addition to the premiums, ARC has commitments related to its risk management program. </p> <p>ARC enters into commitments for capital expenditures in advance of the expenditures being made. At any given point in time, it is estimated that ARC has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the capital in a future period. ARC's 2010 capital budget has been approved by the Board at $610 million. This commitment has not been disclosed in the commitment table (Table 26) as it is of a routine nature and is part of normal course of operations for active oil and gas companies and trusts. </p> <p>The 2010 capital budget of $610 million includes $20 million for leasehold development costs related to ARC's new office space in downtown Calgary. These costs will be incurred throughout the first half of 2010. The operating lease commitments for the new space begin in the first quarter of 2010 and are included in Table 26. </p> <p>ARC is involved in litigation and claims arising in the normal course of operations. Management is of the opinion that pending litigation will not have a material adverse impact on ARC's financial position or results of operations and therefore the commitment table (Table 26) does not include any commitments for outstanding litigation and claims. </p> <p>ARC has certain sales contracts with aggregators whereby the price received by ARC is dependent upon the contracts entered into by the aggregator. This commitment has not been disclosed in the commitment table (Table 26) as it is of a routine nature and is part of normal course of operations. </p> <p>Off Balance Sheet Arrangements </p> <p>ARC has certain lease agreements, all of which are reflected in the Contractual Obligations and Commitments table (Table 26), which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&amp;A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the balance sheet as of December 31, 2009. </p> <pre> &lt;&lt; Fourth Quarter Financial and Operational Results - During the fourth quarter, ARC completed an acquisition for $180 million in cash consideration prior to normal closing adjustments of a partnership owning properties in the Ante Creek area. The acquisition consisted of producing wells with production of approximately 2,000 boe per day and undeveloped land holdings. This acquisition closed on December 21, 2009 and therefore financial results from the properties have been included in the Consolidated Financial Statements from that date. - Announced concurrent with the Ante Creek acquisition was a bought deal financing where ARC entered into an agreement to sell 13 million trust units at $19.40 per trust unit to raise gross proceeds of approximately $252 million and net proceeds of approximately $240 million. The net proceeds of the offering were received on January 5, 2010 at which time they reduced the outstanding indebtedness of ARC by $240 million. - ARC's fourth quarter production was 62,520 boe per day, a decrease of 2,793 boe per day from the fourth quarter of 2008 production of 65,313. The decrease in production is attributable, in large part, to the natural declines on ARC's properties as a result of the reduced capital spending throughout 2009. - ARC spent $117.3 million on capital expenditures before net acquisitions in the fourth quarter compared to $169.4 million in 2008. ARC had an active fourth quarter drilling 39 gross wells (38 net wells) on operated properties with a 100 per cent success rate. Included in ARC's fourth quarter capital expenditures is $20.8 million incurred on the Dawson phase 1 60 mmcf per day gas plant scheduled to be commissioned early in the second quarter of 2010. - The fourth quarter netback before hedging decreased slightly to $29.65 per boe as compared to $29.97 for the same period of 2008. While ARC's realized crude oil price was 29 per cent higher in the fourth quarter of 2009 than the same period in 2008, the realized natural gas price was 39 per cent lower than in the fourth quarter of 2008. - Cash G&amp;A expenses before payments made under the Whole Unit Plan in the fourth quarter decreased to $1.73 per boe as compared to $1.78 for the same period in 2008. The decrease in 2009 is attributable to a decreased bonus accrual in 2009 reflecting the lower overall commodity price environment observed throughout 2009. Table 27 ------------------------------------------------------------------------- Fourth Quarter Financial and Operational Highlights (Cdn$ millions except per unit and per cent) Q4 2009 Q4 2008 % Change ------------------------------------------------------------------------- Production (boe/d) 62,520 65,313 (4) Cash flow from operating activities 143.2 209.4 (32) Per unit $ 0.61 $ 0.96 (36) Distributions 70.9 127.2 (44) Per unit $ 0.30 $ 0.58 (48) Per cent of cash flow from operating activities 50 61 (18) Net income 65.5 82.7 (21) Per unit $ 0.28 $ 0.38 (26) ------------------------------------------------------------------------- Prices WTI (US$/bbl) 76.17 58.75 30 Cdn$/US$ exchange rate 1.06 1.21 (12) Realized oil price (Cdn $/bbl) 72.61 56.26 29 AECO gas monthly index (Cdn $/mcf) 4.23 6.79 (38) Realized gas price (Cdn $/mcf) 4.58 7.48 (39) ------------------------------------------------------------------------- Operating netback ($/boe) Revenue, before hedging 48.42 50.06 (3) Royalties (7.94) (9.14) (13) Transportation (0.92) (0.86) 7 Operating costs (9.91) (10.09) (2) Netback (before hedging) 29.65 29.97 (1) Cash hedging gain (loss) (0.47) 2.38 (120) Netback (after hedging) 29.18 $ 32.35 (10) ------------------------------------------------------------------------- Capital expenditures 117.3 169.4 (31) Net acquisitions and dispositions(1) 180.0 27.6 552 Capital funded with cash flow from operating activities (per cent) 73 65 12 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Represents total consideration for the transactions, including fees but is prior to the related future income tax liability and asset retirement cost obligation. &gt;&gt; </pre> <p>Critical Accounting Estimates </p> <p>ARC has continuously evolved and documented its management and internal reporting systems to provide assurance that accurate, timely, internal and external information is gathered and disseminated. </p> <p>ARC's financial and operating results incorporate certain estimates including: </p> <pre> &lt;&lt; - estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received; - estimated capital expenditures on projects that are in progress; - estimated depletion, depreciation and accretion that are based on estimates of oil and gas reserves that ARC expects to recover in the future; - estimated fair values of derivative contracts that are subject to fluctuation depending upon the underlying commodity prices and foreign exchange rates; - estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures; and - estimated future recoverable value of property, plant and equipment and goodwill. &gt;&gt; </pre> <p>ARC has hired individuals and consultants who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates. </p> <p>The ARC leadership team's mandate includes ongoing development of procedures, standards and systems to allow ARC staff to make the best decisions possible and ensuring those decisions are in compliance with ARC's environmental, health and safety policies. </p> <p>Disclosure Controls and Procedures </p> <p>As of December 31, 2009, an internal evaluation was carried out of the effectiveness of ARC's disclosure controls and procedures as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and the Senior Vice President Finance and Chief Financial Officer concluded that the disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that ARC files or submits under the Exchange Act or under Canadian Securities legislation is recorded, processed, summarized and reported, within the time periods specified in the rules and forms therein. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that the information required to be disclosed by ARC in the reports that it files or submits under the Exchange Act or under Canadian Securities Legislation is accumulated and communicated to ARC's management, including the senior executive and financial officers, as appropriate to allow timely decisions regarding the required disclosure. </p> <p>Internal Control over Financial Reporting </p> <p>Internal control over financial reporting is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Management has assessed the effectiveness of ARC's internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. The assessment was based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded that ARC's internal control over financial reporting was effective as of December 31, 2009. The effectiveness of ARC's internal control over financial reporting as of December 31, 2009 has been audited by Deloitte &amp; Touche LLP, as reflected in their report for 2009. No changes were made to the Trust's internal control over financial reporting during the year ending December 31, 2009, that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting. </p> <p>Financial Reporting Update </p> <p>Current Year Accounting Changes </p> <p>Effective January 1, 2009, ARC adopted Section 3064, Goodwill and Intangible Assets issued by the Canadian Institute of Chartered Accountants ("CICA"). Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. This new section has no current impact on ARC or its Consolidated Financial Statements. This standard was adopted prospectively. </p> <p>Effective December 31, 2009, ARC adopted CICA issued amendments to Handbook Section 3862, Financial Instruments - Disclosures. The amendments include enhanced disclosures relating to the fair value of financial instruments and the liquidity risk associated with financial instruments. Section 3862 now requires that all financial instruments measured at fair value be categorized into one of three hierarchy levels. Refer to Note 13 Financial Instruments and Risk Management for enhanced fair value disclosures and Note 9 Financial Liabilities and Liquidity Risk for liquidity risk disclosures. The amendments are consistent with recent amendments to financial instrument disclosure standards in IFRS. </p> <p>Future Accounting Changes </p> <p>Business Combinations </p> <p>The CICA issued Handbook Section 1582 "Business Combinations" that replaces the previous business combinations standard. Under this guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at the market price at acquisition date. Under the current standard, the purchase price used is based on the market price of shares for a reasonable period before and after the date the acquisition is agreed upon and announced. In addition, the guidance generally requires all acquisition costs to be expensed. Current standards allow for the capitalization of these costs as part of the purchase price. This new Section also addresses contingent liabilities, which will be required to be recognized at fair value on acquisition, and subsequently remeasured at each reporting period until settled. Currently, standards require only contingent liabilities that are payable to be recognized. The new guidance requires negative goodwill to be recognized in earnings rather than the current standard of deducting from non-current assets in the purchase price allocation. This standard applies prospectively to business combinations on or after January 1, 2011 with earlier application permitted. ARC is currently assessing the impact of the standard. </p> <p>Consolidated Financial Statements and Non-controlling Interest </p> <p>The CICA issued Handbook Sections 1601 "Consolidated Financial Statements", and 1602 "Non-controlling Interests", which replaces existing guidance under Section 1600 "Consolidated Financial Statements". Section 1601 establishes standards for the preparation of Consolidated Financial Statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in Consolidated Financial Statements subsequent to a business combination. These standards will be effective for ARC for business combinations occurring on or after January 1, 2011, with early application permitted. ARC is currently assessing the impact of the standard. </p> <p>International Financial Reporting Standards ("IFRS") </p> <p>In October 2009, the Accounting Standards Board ("AcSB") issued a third and final IFRS Omnibus Exposure Draft confirming that publicly accounting enterprises will be required to apply IFRS, in full and without modification, for financial periods beginning on January 1, 2011. The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported by ARC for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010. </p> <p>ARC has commenced the process to transition from current Canadian GAAP to IFRS. Internal staff has been appointed to lead the conversion project along with sponsorship from the leadership team. Resource requirements have been identified and all IFRS requirements will be met with internal employees supplemented with consultants as required. Regular progress reporting to the Audit Committee of the Board of Directors on the status of the IFRS conversion has been implemented along with scheduled training sessions throughout 2010. At this time, ARC has begun the process of training key personnel within the accounting and finance functions as well as the management team. This has occurred through external IFRS oil and gas training and workshops that have been attended by key members of the accounting and finance team in 2009 and early 2010. A training session has been scheduled for the Audit Committee in June, 2010. </p> <p>ARC's project consists of three key phases: </p> <pre> &lt;&lt; - Scoping and diagnostic phase - this phase involves performing a high level impact analysis to identify areas that may be affected by the transition to IFRS. The results of this analysis are priority ranked according to complexity and the amount of time required to assess the impact of changes in transitioning to IFRS. - Impact analysis and evaluation phase - during this phase, items identified in the diagnostic are addressed according to the priority levels assigned to them. This phase involves analysis of policy choices allowed under IFRS and their impact on the financial statements. In addition, certain potential differences are further investigated to assess whether there may be a broader impact to ARC's debt agreements, compensation arrangements or management reporting systems. The conclusion of the impact analysis and evaluation phase will require the audit committee of the Board of Directors to review and approve all accounting policy choices as proposed by management. - Implementation phase - involves implementation of all changes approved in the impact analysis phase and will include changes to information systems, business processes, modification of agreements and training of all staff who are impacted by the conversion. &gt;&gt; </pre> <p>ARC has completed the scoping and diagnostic phase and has prepared draft analysis for the impact analysis and evaluation phase. Management has not yet finalized its accounting policies and as such is unable to quantify the impact of adopting IFRS on the financial statements. In addition, due to anticipated changes to IFRS and International Accounting Standards prior to ARC's adoption of IFRS, management's plan is subject to change based on new facts and circumstances that arise after the date of this MD&amp;A. </p> <p>First-Time Adoption of IFRS </p> <p>IFRS 1, "First-Time Adoption of International Financial Reporting Standards" ("IFRS 1"), provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement for full retrospective application of IFRS. Management is analyzing the various accounting policy choices available and will implement those determined to be the most appropriate for ARC which at this time are summarized as follows: </p> <pre> &lt;&lt; - Business Combinations - IFRS 1 would allow ARC to use the IFRS rules for business combinations on a prospective basis rather than re- stating all business combinations. The IFRS business combination rules converge with the new CICA Hanbook section 1582 that is also effective for ARC on January 1, 2011, however, early adoption is permitted. - Property, Plant and Equipment ("PP&amp;E") - IFRS 1 provides the option to value the PP&amp;E assets at their deemed cost being the Canadian GAAP net book value assigned to these assets as at the date of transition, January 1, 2010. This amendment is permissible for entities, such as ARC, who currently follow the full cost accounting guideline under Canadian GAAP that accumulates all oil and gas assets into one cost centre. Under IFRS, ARC's PP&amp;E assets must be divided into smaller cost centers. The net book value of the assets on the date of transition will be allocated to the new cost centers on the basis of ARC's reserve volumes or values at that point in time. - Share-Based Payments - IFRS 1 allows ARC an exemption on IFRS 2, "Share-Based Payments" to equity instruments granted on or before November 2, 2002 or which vested before ARC's transition date to IFRS. &gt;&gt; </pre> <p>The transition from Canadian GAAP to IFRS is a significant undertaking that may materially affect our reported financial position and results of operations. At this time, ARC has identified key differences that will impact the financial statements as follows: </p> <pre> &lt;&lt; - Re-classification of Exploration and Evaluation ("E&amp;E") expenditures from PP&amp;E - Upon transition to IFRS, ARC will re-classify all E&amp;E expenditures that are currently included in the PP&amp;E balance on the Consolidated Balance Sheet. This will consist of the book value for ARC's undeveloped land that relates to exploration properties. E&amp;E assets will not be depleted and must be assessed for impairment when indicators suggest the possibility of impairment. - Calculation of depletion expense for PP&amp;E assets - Upon transition to IFRS, ARC has the option to calculate depletion using a reserve base of proved reserves or both proved and probable reserves, as compared to the Canadian GAAP method of calculating depletion using only proved reserves. ARC has not concluded at this time which method for calculating depletion will be used. - Impairment of PP&amp;E assets - Under IFRS, impairment of PP&amp;E must be calculated at a more granular level than what is currently required under Canadian GAAP. Impairment calculations will be performed at the cash generating unit level using either total proved or proved plus probable reserves. - Due to the recent withdrawal of the exposure draft on IAS 12 Income Taxes in November 2009 and the issuance of the exposure draft on IAS 37 Provisions, Contingent Liabilities and Contingent Assets in January 2010, Management is still determining the impact of these revised standards on its IFRS transition and expects to have all additional potential material impact areas identified during the first quarter of 2010 and approved by the audit committee during the second quarter of 2010. &gt;&gt; </pre> <p>In addition to accounting policy differences, ARC's transition to IFRS will impact the internal controls over financial reporting, the disclosure controls and procedures, ARC's business activities and IT systems as follows: </p> <pre> &lt;&lt; - Internal controls over financial reporting ("ICFR") - As the review of ARC's accounting policies is completed, an assessment will be made to determine changes required for ICFR. As an example, additional controls will be implemented for the IFRS 1 changes such as the allocation of ARC's PP&amp;E as well as the process for re- classifying ARC's E&amp;E expenditures from PP&amp;E. This will be an ongoing process through 2010 to ensure that all changes in accounting policies include the appropriate additional controls and procedures for future IFRS reporting requirements. - Disclosure controls and procedures - Throughout the transition process, ARC will be assessing stakeholders' information requirements and will ensure that adequate and timely information is provided so that all stakeholders are kept apprised. Management anticipates to deliver investor presentations during the fourth quarter of 2011 to explain the differences between the historical Canadian GAAP statements and the IFRS statements. - Business activities - Management has been cognizant of the upcoming transition to IFRS and as such has worked with our counterparties and lenders to ensure that agreement references to Canadian GAAP statements are modified to allow for IFRS statements. Based on the expected changes to ARC's accounting policies at this time, there are no foreseen issues with the existing wording of debts covenants and related agreements as a result of the conversion to IFRS. During the 2010 quarterly meetings held with ARC's lenders there will be an update on IFRS as it relates to ARC and management will continue to monitor these areas closely as final policy choices are made. - IT systems - ARC has completed most of the system updates required in order to ready the company for IFRS reporting. The modifications were not significant, however, deemed critical in order to allow for reporting of both Canadian GAAP and IFRS statements in 2010 as well as the modifications required to track PP&amp;E costs and E&amp;E costs with a more granular level of detail for IFRS reporting. Additional system modifications may be required based on final policy choices. Additional system modifications may be required based on final policy choices. &gt;&gt; </pre> <p>Non-GAAP Measures </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, net asset value and total returns to analyze financial and operating performance. Management feels that these KPIs and benchmarks are key measures of profitability and overall sustainability for ARC. 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> <p>Forward-looking Information and Statements </p> <p>This MD&amp;A contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this MD&amp;A contains forward-looking information and statements pertaining to the following: all of the matters under the heading "2009 Guidance and Financial Highlights" which contains guidance for 2010, the future expenditure plans for 2010 and expected production under the heading "Production", the expected benefits from various incentive plans instituted in the provinces of Alberta and British Columbia and future operating costs under the heading "Operating Netbacks", the expected increase in cash G&amp;A in 2010 and the expected payments in 2010 under the Whole Unit Plan under the heading "General and Administrative Expenses ("G&amp;A") and Trust Unit Incentive Compensation", the increase in interest rates in 2010 as a result of the renewal of our credit facility under the heading "Interest and Financing Charges" and the costs and opportunity for renewal of the bank facility and other information relating to financing the 2010 capital expenditures under the heading: "Capitalization, Financial Resources and Liquidity", the payment of income taxes in the future by ARC and the availability of a non-taxable conversion of trust unit to shares on the conversion of the trust structure to a corporation under the heading "Taxes", and a number of other matters, including the amount of future asset retirement; the amount of future asset retirement obligations; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; future development, exploration, acquisition and development activities (including drilling plans) and related capital expenditures, future tax treatment of income trusts and future taxes payable by ARC; ARC's income tax pools and the future impact of the implementation of IFRS on ARC's financial statements. </p> <p>The forward-looking information and statements contained in this MD&amp;A reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its planned expenditures; ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. </p> <p>The forward-looking information and statements included in this MD&amp;A are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this MD&amp;A and in ARC's Annual Information Form). </p> <p>The forward-looking information and statements contained in this MD&amp;A speak only as of the date of this MD&amp;A, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws. </p> <p>Additional Information </p> <p>Additional information relating to ARC can be found on SEDAR at www.sedar.com. </p> <pre> &lt;&lt; ANNUAL HISTORICAL REVIEW ------------------------------------------------------------------------- For the year ended December 31 (Cdn $ millions, except per unit amounts) 2009 2008 2007 2006 2005 ------------------------------------------------------------------------- FINANCIAL Revenue before royalties 978.2 1,706.4 1,251.6 1,230.5 1,165.2 Per unit(1) 4.16 7.90 5.95 6.02 6.10 Cash flow from operating activities(2) 497.4 944.4 704.9 734.0 616.7 Per unit - basic(1) 2.11 4.37 3.35 3.59 3.23 Per unit - diluted 2.11 4.37 3.35 3.58 3.20 Net income 222.8 533.0 495.3 460.1 356.9 Per unit - basic(3) 0.96 2.50 2.39 2.28 1.90 Per unit - diluted 0.96 2.50 2.39 2.27 1.88 Distributions 298.5 570.0 498.0 484.2 376.6 Per unit(4) 1.28 2.67 2.40 2.40 1.99 Total assets 3,914.5 3,766.7 3,533.0 3,479.0 3,251.2 Total liabilities 1,540.1 1,624.6 1,491.3 1,550.6 1,415.5 Net debt outstanding(5) 902.4 961.9 752.7 739.1 578.1 Weighted average trust units (millions)(6) 235.4 216.0 210.2 204.4 191.2 Trust units outstanding and issuable at period end (millions)(6) 239.0 219.2 213.2 207.2 202.0 ------------------------------------------------------------------------- CAPITAL EXPENDITURES Geological and geophysical 13.7 27.1 14.9 11.4 9.2 Land 7.0 122.4 77.5 32.4 9.1 Drilling and completions 214.3 305.4 229.5 240.5 191.8 Plant and facilities 110.0 90.4 72.1 77.6 55.0 Other capital 14.6 3.3 3.2 2.6 3.7 Total capital expenditures 359.6 548.6 397.2 364.5 268.8 Property acquisitions (dispositions), net (20.5) 51.0 42.5 115.2 91.3 Corporate acquisitions(7) 178.9 - - 16.6 505.0 Total capital expenditures and net acquisitions 518.0 599.6 439.7 496.3 865.1 ------------------------------------------------------------------------- OPERATING Production Crude oil (bbl/d) 27,509 28,513 28,682 29,042 23,282 Natural gas (mmcf/d) 194.0 196.5 180.1 179.1 173.8 Natural gas liquids (bbl/d) 3,689 3,861 4,027 4,170 4,005 Total (boe per day 6:1) 63,538 65,126 62,723 63,056 56,254 Average prices Crude oil ($/bbl) 62.24 94.20 69.24 65.26 61.11 Natural gas ($/mcf) 4.18 8.58 6.75 6.97 8.96 Natural gas liquids ($/bbl) 40.67 69.71 54.79 52.63 49.92 Oil equivalent ($/boe) 42.07 71.25 54.54 53.33 56.54 ------------------------------------------------------------------------- RESERVES (company interest)(8) Proved plus probable reserves Crude oil and NGL (mbbl) 153,413 153,020 158,341 162,193 163,385 Natural gas (bcf) 1,353.2 1,012.2 768.2 743.6 741.7 Total (mboe) 378,953 321,723 286,370 286,125 286,997 ------------------------------------------------------------------------- TRUST UNIT TRADING (based on intra-day trading) Unit prices High 21.89 33.95 23.86 30.74 27.58 Low 11.73 15.01 18.90 19.20 16.55 Close 19.94 20.10 20.40 22.30 26.49 Average daily volume (thousands) 1,057 975 597 706 656 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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. (2) This is a GAAP measure and a change from the non-GAAP measure reported in prior quarters. Refer to non-GAAP section. (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) Based on number of trust units outstanding at each distribution date. (5) Net debt excludes the current unrealized risk management contracts asset and liability and the current portion of future income taxes. (6) Includes trust units issuable for outstanding exchangeable shares based on the period end exchange ratio. (7) Represents total consideration for the corporate acquisition including fees but prior to working capital, asset retirement obligation and future income tax liability assumed on acquisition. (8) Company interest reserves are the gross interest reserves plus the royalty interest prior to the deduction of royalty burdens. QUARTERLY HISTORICAL REVIEW ------------------------------------------------------------------------- (Cdn $ millions, except per unit amounts) 2009 ------------------------------------------------------------------------- FINANCIAL Q4 Q3 Q2 Q1 Revenue before royalties 278.6 239.2 235.2 225.2 Per unit(1) 1.17 1.01 0.99 0.98 Cash flow from operating activities(2) 143.2 125.6 104.3 124.3 Per unit - basic(1) 0.60 0.53 0.44 0.54 Per unit - diluted 0.60 0.53 0.44 0.54 Net income 65.5 68.9 66.1 22.3 Per unit - basic(3) 0.28 0.29 0.28 0.10 Per unit - diluted 0.28 0.29 0.28 0.10 Distributions 70.9 70.6 75.0 82.0 Per unit(4) 0.30 0.30 0.32 0.36 Total assets 3,914.5 3,642.9 3,672.5 3,733.1 Total liabilities 1,540.1 1,278.4 1,323.1 1,392.1 Net debt outstanding(5) 902.4 705.4 737.6 781.5 Weighted average trust units(6) 238.5 237.7 236.6 228.9 Trust units outstanding and issuable(6) 239.0 238.1 237.1 236.0 ------------------------------------------------------------------------- CAPITAL EXPENDITURES Geological and geophysical 2.9 3.0 5.0 2.8 Land 2.0 4.5 0.2 0.2 Drilling and completions 66.1 61.0 18.6 68.5 Plant and facilities 35.3 26.1 23.6 25.1 Other capital 11.0 1.6 1.5 0.6 Total capital expenditures 117.3 96.2 48.9 97.2 Property acquisitions (dispositions) net 1.1 (30.1) 2.3 6.2 Corporate acquisitions(7) 178.9 - - - Total capital expenditures and net acquisitions 297.3 66.1 51.2 103.4 ------------------------------------------------------------------------- OPERATING Production Crude oil (bbl/d) 27,415 26,921 26,917 28,806 Natural gas (mmcf/d) 189.0 193.1 200.2 193.8 Natural gas liquids (bbl/d) 3,597 3,717 3,679 3,764 Total (boe per day 6:1) 62,520 62,824 63,969 64,872 Average prices Crude oil ($/bbl) 72.61 67.74 62.74 46.44 Natural gas ($/mcf) 4.58 3.25 3.73 5.20 Natural gas liquids ($/bbl) 46.12 38.92 38.89 38.86 Oil equivalent ($/boe) 48.35 41.31 40.32 38.40 ------------------------------------------------------------------------- TRUST UNIT TRADING (based on intra-day trading) Unit prices High 21.89 20.20 19.25 20.90 Low 19.06 15.48 14.12 11.73 Close 19.94 20.20 17.81 14.15 Average daily volume (thousands) 963 1,038 988 1,240 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- (Cdn $ millions, except per unit amounts) 2008 ------------------------------------------------------------------------- FINANCIAL Q4 Q3 Q2 Q1 Revenue before royalties 300.8 485.7 512.0 407.9 Per unit(1) 1.38 2.24 2.38 1.91 Cash flow from operating activities(2) 209.4 251.4 273.4 209.9 Per unit - basic(1) 0.96 1.16 1.27 0.98 Per unit - diluted 0.96 1.16 1.27 0.98 Net income 82.7 311.7 57.3 81.3 Per unit - basic(3) 0.38 1.46 0.27 0.39 Per unit - diluted 0.38 1.46 0.27 0.38 Distributions 127.2 171.3 144.7 126.8 Per unit(4) 0.59 0.80 0.68 0.60 Total assets 3,766.7 3,687.5 3,664.3 3,592.6 Total liabilities 1,624.6 1,530.8 1,689.6 1,560.4 Net debt outstanding(5) 961.9 773.2 756.1 770.1 Weighted average trust units(6) 218.3 216.6 215.2 213.8 Trust units outstanding and issuable(6) 219.2 217.4 215.8 214.7 ------------------------------------------------------------------------- CAPITAL EXPENDITURES Geological and geophysical 3.7 1.3 16.4 5.5 Land 17.1 18.6 57.8 28.8 Drilling and completions 117.1 91.4 32.6 64.4 Plant and facilities 30.5 24.2 24.1 11.6 Other capital 1.0 0.9 0.4 1.0 Total capital expenditures 169.4 136.4 131.3 111.3 Property acquisitions (dispositions) net 27.6 13.1 0.3 10.1 Corporate acquisitions(7) - - - - Total capital expenditures and net acquisitions 197.0 149.5 131.6 121.4 ------------------------------------------------------------------------- OPERATING Production Crude oil (bbl/d) 28,935 28,509 27,541 29,064 Natural gas (mmcf/d) 195.1 192.0 194.7 204.3 Natural gas liquids (bbl/d) 3,858 3,822 3,906 3,856 Total (boe per day 6:1) 65,313 64,325 63,896 66,976 Average prices Crude oil ($/bbl) 56.26 114.20 118.32 89.72 Natural gas ($/mcf) 7.48 8.68 10.41 7.80 Natural gas liquids ($/bbl) 45.22 82.87 82.29 68.54 Oil equivalent ($/boe) 49.93 81.42 87.73 66.67 ------------------------------------------------------------------------- TRUST UNIT TRADING (based on intra-day trading) Unit prices High 22.55 33.30 33.95 27.06 Low 15.01 22.33 25.19 20.00 Close 20.10 23.10 33.95 26.38 Average daily volume (thousands) 1,523 841 659 863 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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. (2) This is a GAAP measure and a change from the non-GAAP measure reported in prior quarters. Refer to non-GAAP section. (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) Based on number of trust units outstanding at each distribution date. (5) Net debt excludes the current unrealized risk management contracts asset and liability and the current portion of future income taxes. (6) Includes trust units issuable for outstanding exchangeable shares based on the period end exchange ratio. (7) Represents total consideration for the corporate acquisition including fees but prior to working capital, asset retirement obligation and future income tax liability assumed on acquisition. CONSOLIDATED BALANCE SHEETS (unaudited) As at December 31 (Cdn$ millions) 2009 2008 ------------------------------------------------------------------------- ASSETS Current assets Cash and cash equivalents (Note 5) $ - $ 40.0 Accounts receivable (Note 6) 115.9 110.0 Prepaid expenses 18.2 16.8 Risk management contracts (Note 13) 5.9 24.4 Future income taxes (Note 15) 7.1 3.9 ------------------------------------------------------------------------- 147.1 195.1 Reclamation funds (Note 7) 33.2 28.2 Risk management contracts (Note 13) 3.2 9.2 Property, plant and equipment (Note 8) 3,573.4 3,376.6 Goodwill 157.6 157.6 ------------------------------------------------------------------------- Total assets $ 3,914.5 $ 3,766.7 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES Current liabilities Accounts payable and accrued liabilities (Note 9) $ 166.7 $ 194.4 Distributions payable 23.7 32.5 Risk management contracts (Note 13) 12.9 23.5 ------------------------------------------------------------------------- 203.3 250.4 Risk management contracts (Note 13) 1.0 3.4 Long-term debt (Note 10) 846.1 901.8 Accrued long-term incentive compensation (Note 21) 10.9 14.2 Asset retirement obligations (Note 11) 149.9 141.5 Future income taxes (Note 15) 328.9 313.3 ------------------------------------------------------------------------- Total liabilities 1,540.1 1,624.6 ------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES (Note 22) SUBSEQUENT EVENT (Note 23) NON-CONTROLLING INTEREST Exchangeable shares (Note 16) 36.0 42.4 UNITHOLDERS' EQUITY Unitholders' capital (Note 17) 2,917.6 2,600.7 Deficit (Note 18) (578.6) (502.9) Accumulated other comprehensive (loss) income (Note 18) (0.6) 1.9 ------------------------------------------------------------------------- Total unitholders' equity 2,338.4 2,099.7 ------------------------------------------------------------------------- Total liabilities and unitholders' equity $ 3,914.5 $ 3,766.7 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the Consolidated Financial Statements CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (unaudited) For the three and twelve months ended December 31 Three Months Ended Twelve Months Ended (Cdn$ millions, except December 31 December 31 per unit amounts) 2009 2008 2009 2008 ------------------------------------------------------------------------- REVENUES Oil, natural gas and natural gas liquids $ 278.6 $ 300.8 $ 978.2 $ 1,706.4 Royalties (45.6) (54.9) (147.8) (307.7) ------------------------------------------------------------------------- 233.0 245.9 830.4 1,398.7 Gain (loss) on risk management contracts (Note 13) Realized (1.7) 32.8 19.4 (75.7) Unrealized 0.2 42.0 (7.7) 68.0 ------------------------------------------------------------------------- 231.5 320.7 842.1 1,391.0 ------------------------------------------------------------------------- EXPENSES Transportation 5.3 5.2 20.6 19.0 Operating 57.0 60.7 236.2 241.5 General and administrative 13.8 14.0 52.3 61.2 Provision for non- recoverable accounts receivable (Note 6) (1.3) 14.0 (1.7) 32.0 Interest and financing charges (Note 10) 5.9 8.1 25.7 32.9 Depletion, depreciation and accretion (Notes 8 and 11) 96.1 96.2 386.4 379.6 (Gain) loss on foreign exchange (Note 14) (9.7) 61.2 (70.0) 89.4 ------------------------------------------------------------------------- 167.1 259.4 649.5 855.6 ------------------------------------------------------------------------- Capital and other taxes (0.1) - (0.3) - Future income tax recovery (Note 15) 1.9 22.3 32.8 4.5 ------------------------------------------------------------------------- Net income before non- controlling interest 66.2 83.6 225.1 539.9 Non-controlling interest (Note 16) (0.7) (0.9) (2.3) (6.9) ------------------------------------------------------------------------- Net income $ 65.5 $ 82.7 $ 222.8 $ 533.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Deficit, beginning of period $ (573.2) $ (458.4) $ (502.9) $ (465.9) Distributions paid or declared (Note 19) (70.9) (127.2) (298.5) (570.0) ------------------------------------------------------------------------- Deficit, end of period (Note 18) $ (578.6) $ (502.9) $ (578.6) $ (502.9) ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net income per unit (Note 17) Basic and Diluted $ 0.28 $ 0.38 $ 0.96 $ 2.50 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the Consolidated Financial Statements CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE INCOME (unaudited) For the three and twelve months ended December 31 Three Months Ended Twelve Months Ended December 31 December 31 (Cdn$ millions) 2009 2008 2009 2008 ------------------------------------------------------------------------- Net income $ 65.5 $ 82.7 $ 222.8 $ 533.0 Other comprehensive (loss) income, net of tax Losses and gains on financial instruments designated as cash flow hedges(1) (0.5) 0.6 (3.9) (2.2) De-designation of cash flow hedge(2) (Note 13) - - - 10.0 Gains and losses on financial instruments designated as cash flow hedges in prior periods realized in net income in the current period(3) (Note 13) 0.3 (0.9) 1.1 (2.9) Net unrealized gains (losses) on available- for-sale reclamation funds' investments(4) - - 0.3 (0.1) ------------------------------------------------------------------------- Other comprehensive (loss) income (0.2) (0.3) (2.5) 4.8 ------------------------------------------------------------------------- Comprehensive income $ 65.3 $ 82.4 $ 220.3 $ 537.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Accumulated other comprehensive (loss) income, beginning of period (0.4) 2.2 1.9 (2.9) Other comprehensive (loss) income (0.2) (0.3) (2.5) 4.8 ------------------------------------------------------------------------- Accumulated other comprehensive (loss) income, end of period (Note 18) $ (0.6) $ 1.9 $ (0.6) $ 1.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Amounts are net of tax of $0.1 million and $1.3 million, respectively, for the three months and twelve months ended December 31, 2009 (net of tax of $0.2 million and $0.8 million, respectively, for the three and twelve months ended December 31, 2008). (2) Amount is net of tax of $3.6 million for the twelve months ended December 31, 2008. (3) Amounts are net of tax of $0.1 million and $0.4 million, respectively, for the three and twelve months ended December 31, 2009 (net of tax of $0.3 million and $1 million, respectively, for the three and twelve months ended December 31, 2008). (4) Nominal future income tax impact for the three months ended December 31, 2009 and $0.1 million for the twelve months ended December 31, 2009 (nominal for the three and twelve months ended December 31, 2008). See accompanying notes to the Consolidated Financial Statements CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) For the three and twelve months ended December 31 Three Months Ended Twelve Months Ended December 31 December 31 (Cdn$ millions) 2009 2008 2009 2008 ------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 65.5 $ 82.7 $ 222.8 $ 533.0 Add items not involving cash: Non-controlling interest (Note 16) 0.7 0.9 2.3 6.9 Future income tax recovery (Note 15) (1.9) (22.3) (32.8) (4.5) Depletion, depreciation and accretion (Notes 8 and 11) 96.1 96.2 386.4 379.6 Non-cash (gain) loss on risk management contracts (Note 13) (0.2) (42.0) 7.7 (68.0) Non-cash (gain) loss on foreign exchange (Note 14) (8.8) 61.6 (69.0) 88.5 Non-cash trust unit incentive compensation expense (recovery) (Note 21) 4.7 (4.2) 0.6 1.0 Expenditures on site restoration and reclamation (Note 11) (4.8) (4.7) (8.7) (12.4) Change in non-cash working capital (8.1) 41.2 (11.9) 20.3 ------------------------------------------------------------------------- 143.2 209.4 497.4 944.4 ------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issue of long-term debt under revolving credit facilities, net 224.5 164.0 (120.7) 105.9 Issue of Senior Secured Notes - - 152.9 - Repayment of Senior Secured Notes (6.3) (7.1) (18.9) (7.1) Issue of trust units 0.5 0.5 255.0 4.9 Trust unit issue costs (0.5) - (13.8) - Cash distributions paid (Note 19) (56.1) (117.6) (242.3) (458.8) Change in non-cash working capital (4.3) (1.5) 1.6 (0.4) ------------------------------------------------------------------------- 157.8 38.3 13.8 (355.5) ------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Corporate acquisition (Note 4) (178.9) - (178.9) - Acquisition of petroleum and natural gas properties (1.1) (27.6) (11.8) (51.2) Proceeds on disposition of petroleum and natural gas properties - - 32.3 0.2 Capital expenditures (116.5) (169.9) (359.4) (548.1) Net reclamation fund contributions (Note 7) (1.5) (1.3) (4.6) (2.2) Change in non-cash working capital (3.0) 3.5 (28.8) 45.4 ------------------------------------------------------------------------- (301.0) (195.3) (551.2) (555.9) ------------------------------------------------------------------------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS - 52.4 (40.0) 33.0 CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD - (12.4) 40.0 7.0 ------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS, END OF PERIOD $ - $ 40.0 $ - $ 40.0 ------------------------------------------------------------------------- See accompanying notes to the Consolidated Financial Statements NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) December 31, 2009 and 2008 (all tabular amounts in Cdn$ millions, except per unit amounts) 1. STRUCTURE OF THE TRUST ARC Energy Trust ("ARC" or "the Trust") was formed on May 7, 1996 pursuant to a Trust indenture (the "Trust Indenture") that has been amended from time to time, most recently on May 15, 2006. Computershare Trust Company of Canada was appointed as Trustee under the Trust Indenture. The beneficiaries of ARC are the holders of the Trust units. ARC was created for the purposes of issuing trust units to the public and investing the funds so raised to purchase a royalty in the properties of ARC Resources Ltd. ("ARC Resources"). The Trust Indenture was amended on June 7, 1999 to convert ARC from a closed- end to an open-ended investment Trust. The current business of ARC includes investment in energy business-related assets including, but not limited to, petroleum and natural gas-related assets, gathering, processing and transportation assets. The operations of ARC consist of the acquisition, development, exploitation and disposition of these assets and the distribution of the net cash proceeds from these activities to the unitholders. 2. SUMMARY OF ACCOUNTING POLICIES The Consolidated Financial Statements have been prepared by management following Canadian generally accepted accounting principles ("GAAP"). Effective January 1, 2011, ARC will be required to prepare Consolidated Financial Statements in accordance with International Financial Reporting Standards ("IFRS"). The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingencies at the date of the financial statements, and revenues and expenses during the reporting year. Actual results could differ from those estimated. The amounts recorded for depreciation and depletion of petroleum and natural gas property and equipment and for asset retirement obligations are based on estimates of petroleum and natural gas reserves and future costs. Estimates of reserves also provide the basis for determining whether the carrying value of property, plant and equipment is impaired. Accounts receivable are recorded at the estimated net recoverable amount which involves estimates of uncollectable accounts. Goodwill impairment tests involve estimates of ARC's fair value. By their nature, these estimates are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material. Principles of Consolidation The Consolidated Financial Statements include the accounts of ARC and its subsidiaries. Any reference to "the Trust" or "ARC" throughout these Consolidated Financial Statements refers to the Trust and its subsidiaries. All inter-entity transactions have been eliminated. Revenue Recognition Revenue associated with the sale of crude oil, natural gas, and natural gas liquids ("NGLs") owned by ARC are recognized when title passes from ARC to its customers. Transportation Costs paid by ARC for the transportation of natural gas, crude oil and NGLs from the wellhead to the point of title transfer are recognized when the transportation is provided. Joint Interests ARC conducts many of its oil and gas production activities through jointly controlled operations and the financial statements reflect only ARC's proportionate interest in such activities. Depletion and Depreciation Depletion of petroleum and natural gas properties and depreciation of production equipment are calculated on the unit-of-production basis based on: (a) total estimated proved reserves calculated in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities; (b) total capitalized costs, excluding undeveloped lands, plus estimated future development costs of proved undeveloped reserves, including future estimated asset retirement costs; and (c) relative volumes of petroleum and natural gas reserves and production, before royalties, converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. Whole Trust Unit Incentive Plan Compensation ARC has established a Whole Trust Unit Incentive Plan (the "Whole Unit Plan") for employees, independent directors and long-term consultants who otherwise meet the definition of an employee of ARC. Compensation expense associated with the Whole Unit Plan is granted in the form of Restricted Trust Units ("RTUs") and Performance Trust Units ("PTUs") and is determined based on the intrinsic value of the Whole Trust Units at each period end. The intrinsic valuation method is used as participants of the Whole Unit Plan receive a cash payment on a fixed vesting date. This valuation incorporates the year-end unit price, the number of RTUs and PTUs outstanding at each period end, and certain management estimates. As a result, large fluctuations, even recoveries, in compensation expense may occur due to changes in the underlying unit price. In addition, compensation expense is amortized and recognized in earnings over the vesting period of the Whole Unit Plan with a corresponding increase or decrease in liabilities. Classification between accrued liabilities and accrued long-term incentive compensation is dependent on the expected payout date. ARC charges amounts relating to head office employees to general and administrative expense, amounts relating to field employees to operating expense and amounts relating to geologists and geophysicists to property, plant and equipment. ARC has not incorporated an estimated forfeiture rate for RTUs and PTUs that will not vest, rather it accounts for actual forfeitures as they occur. Cash Equivalents Cash equivalents include short-term investments, such as money market deposits or similar type instruments, with an original maturity of three months or less when purchased. Reclamation Funds Reclamation funds hold investment grade assets and cash and cash equivalents. Investments are categorized as either held-to-maturity or available-for-sale assets, which are initially measured at fair value. Held-to-maturity investments are subsequently measured at amortized cost using the effective interest method. Available-for- sale investments are subsequently measured at fair value with changes in fair value recognized in other comprehensive income, net of tax. Investments carried at amortized cost are subject to impairment losses in the event of an other than temporary decline in market value. Property, Plant and Equipment ("PP&amp;E") ARC follows the full cost method of accounting. All costs of exploring, developing, enhancing and acquiring petroleum and natural gas properties, including asset retirement costs, are capitalized and accumulated in one cost centre as all operations are in Canada. Maintenance and repairs are charged against earnings, and renewals and enhancements that extend the economic life of the PP&amp;E are capitalized. Gains and losses are not recognized upon disposition of petroleum and natural gas properties unless such a disposition would alter the rate of depletion by 20 per cent or more. Impairment ARC places a limit on the aggregate carrying value of PP&amp;E, which may be amortized against revenues of future periods. Impairment is recognized if the carrying amount of the PP&amp;E exceeds the sum of the undiscounted cash flows expected to result from ARC's proved reserves. Cash flows are calculated based on third party quoted forward prices, adjusted for ARC's contract prices and quality differentials. Upon recognition of impairment, ARC would then measure the amount of impairment by comparing the carrying amounts of the PP&amp;E to an amount equal to the estimated net present value of future cash flows from proved plus risked probable reserves. ARC's risk-free interest rate is used to arrive at the net present value of the future cash flows. Any excess carrying value above the net present value of ARC's future cash flows would be recorded as a permanent impairment and charged against net income. The cost of unproved properties is excluded from the impairment test described above and subject to a separate impairment test. In the case of impairment, the book value of the impaired properties is moved to the petroleum and natural gas depletable base. Goodwill ARC must record goodwill relating to a corporate acquisition when the total purchase price exceeds the fair value for accounting purposes of the net identifiable assets and liabilities of the acquired company. The goodwill balance is assessed for impairment annually at year-end or as events occur that could result in an indication of impairment. Impairment is recognized based on the fair value of the reporting entity compared to the book value of the reporting entity. If the fair value of the entity is less than the book value, impairment is measured by allocating the fair value to the identifiable assets and liabilities as if the entity had been acquired in a business combination for a purchase price equal to its fair value. The excess of the fair value over the amounts assigned to the identifiable assets and liabilities is the fair value of the goodwill. Any excess of the book value of goodwill over this implied fair value of goodwill is the impairment amount. Impairment is charged to earnings in the period in which it occurs. Goodwill is stated at cost less impairment and is not amortized. Asset Retirement Obligations ARC recognizes an Asset Retirement Obligation ("ARO") in the period in which it is incurred when a reasonable estimate of the fair value can be made. On a periodic basis, management will review these estimates and changes, if any, will be applied prospectively. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost would also result in an increase or decrease to the ARO. Actual costs incurred upon settlement of the obligation are charged against the ARO to the extent of the liability recorded. Income Taxes ARC follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements of ARC and ARC's corporate subsidiaries and their respective tax base, using substantively enacted future income tax rates. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs, provided that the income tax rates are substantively enacted. Temporary differences arising on acquisitions result in future income tax assets and liabilities. Basic and Diluted per Trust Unit Calculations Basic net income per unit is computed by dividing net income after non-controlling interest by the weighted average number of trust units outstanding during the period. Diluted net income per unit amounts are calculated based on net income before non-controlling interest divided by dilutive trust units. Dilutive trust units are arrived at by adding weighted average trust units to trust units issuable on conversion of exchangeable shares, and to the potential dilution that would occur if rights were exercised at the beginning of the period. The treasury stock method assumes that proceeds received from the exercise of in-the-money rights and the unrecognized trust unit incentive compensation are used to repurchase units at the average market price. Financial Instruments Financial assets, financial liabilities and non-financial derivatives are measured at fair value on initial recognition. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, available-for-sale, held-to- maturity, loans and receivables, or other financial liabilities. a. Held-for-trading Financial assets and liabilities designated as held-for-trading are subsequently measured at fair value with changes in those fair values charged immediately to earnings. With the exception of risk management contracts that qualify for hedge accounting, ARC classifies all risk management contracts as held-for-trading. Cash and cash equivalents are also classified as held-for-trading. b. Available-for-sale assets Available-for-sale financial assets are subsequently measured at fair value with changes in fair value recognized in Other Comprehensive Income ("OCI"), net of tax. Amounts recognized in OCI for available-for-sale financial assets are charged to earnings when the asset is derecognized or when there is an other than temporary asset impairment. ARC classifies its reclamation funds as available-for-sale assets. c. Held-to-maturity investments, loans and receivables and other financial liabilities Held-to-maturity investments, loans and receivables, and other financial liabilities are subsequently measured at amortized cost using the effective interest method. ARC classifies accounts receivable to loans and receivables, and accounts payable, distributions payable and long-term debt to other financial liabilities. Transaction costs are expensed as incurred for all financial instruments. ARC has elected January 1, 2003 as the effective date to identify and measure embedded derivatives in financial and non-financial contracts that are not closely related to the host contracts. ARC is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. A variety of derivative instruments are used by ARC to reduce its exposure to fluctuations in commodity prices, foreign exchange rates, and interest rates. The fair values of these derivative instruments are based on an estimate of the amounts that would have been received or paid to settle these instruments prior to maturity. ARC considers all of these transactions to be effective economic hedges; however, most of ARC's contracts do not qualify or have not been designated as effective hedges for accounting purposes. For transactions that do not qualify for hedge accounting, ARC applies the fair value method of accounting by recording an asset or liability on the Consolidated Balance Sheet and recognizing changes in the fair value of the instruments in earnings during the current period. For derivative instruments that do qualify as effective accounting hedges, policies and procedures are in place to ensure that the required documentation and approvals are obtained. This documentation specifically ties the derivative financial instruments to their use, and in the case of commodities, to the mitigation of market price risk associated with cash flows expected to be generated. When applicable, ARC also identifies all relationships between hedging instruments and hedged items, as well as its risk management objective and the strategy for undertaking hedge transactions. This would include linking the particular derivative to specific assets and liabilities on the Consolidated Balance Sheet or to specific firm commitments or forecasted transactions. Where specific hedges are executed, ARC assesses, both at the inception of the hedge and on an ongoing basis, whether the derivative used in the particular hedging transaction is effective in offsetting changes in fair value or cash flows of the hedged item. Hedge accounting is discontinued prospectively when the derivative no longer qualifies as an effective hedge, or the derivative is terminated or sold, or upon the sale or early termination of the hedged item. ARC has currently designated a portion of its financial electricity contracts as effective cash flow hedges. In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in OCI while the ineffective portion is recognized in earnings. When hedge accounting is discontinued, the amounts previously recognized in Accumulated Other Comprehensive Income ("AOCI") are reclassified to earnings during the periods when the variability in the cash flows of the hedged item affects earnings. Gains and losses on derivatives are reclassified immediately to earnings when the hedged item is sold or early terminated. When hedge accounting is applied to a derivative used to hedge an anticipated transaction and it is determined that the anticipated transaction will not occur within the originally specified time period, hedge accounting is discontinued and the unrealized gains and losses are reclassified from AOCI to earnings. Foreign Currency Translation Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at the Consolidated Balance Sheet date. Revenues and expenses are translated at the period average rates of exchange. Translation gains and losses are included in earnings in the period in which they arise. Non-Controlling Interest ARC must record non-controlling interest when exchangeable shares issued by a subsidiary of ARC are transferable to third parties. Non- controlling interest on the Consolidated Balance Sheet is recognized based on the fair value of the exchangeable shares upon issuance plus the accumulated earnings attributable to the non-controlling interest. Net income is reduced for the portion of earnings attributable to the non-controlling interest. As the exchangeable shares are converted to Trust units, the non-controlling interest on the Consolidated Balance Sheet is reduced by the cumulative book value of the exchangeable shares and Unitholders' capital is increased by the corresponding amount. 3. NEW ACCOUNTING POLICIES Current Year Accounting Changes Effective January 1, 2009, ARC adopted Section 3064, Goodwill and Intangible Assets issued by the Canadian Institute of Chartered Accountants ("CICA"). Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. This new section has no current impact on ARC or its Consolidated Financial Statements. This standard was adopted prospectively. Effective December 31, 2009, ARC adopted CICA issued amendments to Handbook Section 3862, Financial Instruments - Disclosures. The amendments include enhanced disclosures relating to the fair value of financial instruments and the liquidity risk associated with financial instruments. Section 3862 now requires that all financial instruments measured at fair value be categorized into one of three hierarchy levels. Refer to Note 13 Financial Instruments and Risk Management for enhanced fair value disclosures and Note 9 Financial Liabilities and Liquidity Risk for liquidity risk disclosures. The amendments are consistent with recent amendments to financial instrument disclosure standards in IFRS. Future Accounting Changes A. Business Combinations The CICA issued Handbook Section 1582 "Business Combinations" that replaces the previous business combinations standard. Under this guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at the market price at acquisition date. Under the current standard, the purchase price used is based on the market price of shares for a reasonable period before and after the date the acquisition is agreed upon and announced. In addition, the guidance generally requires all acquisition costs to be expensed. Current standards allow for the capitalization of these costs as part of the purchase price. This new Section also addresses contingent liabilities, which will be required to be recognized at fair value on acquisition, and subsequently remeasured at each reporting period until settled. Currently, standards require only contingent liabilities that are payable to be recognized. The new guidance requires negative goodwill to be recognized in earnings rather than the current standard of deducting from non-current assets in the purchase price allocation. This standard applies prospectively to business combinations on or after January 1, 2011 with earlier application permitted. ARC is currently assessing the impact of the standard. B. Consolidated Financial Statements and Non-controlling Interest The CICA issued Handbook Sections 1601 "Consolidated Financial Statements", and 1602 "Non-controlling Interests", which replaces existing guidance under Section 1600 "Consolidated Financial Statements". Section 1601 establishes standards for the preparation of Consolidated Financial Statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in Consolidated Financial Statements subsequent to a business combination. These standards will be effective for ARC for business combinations occurring on or after January 1, 2011 with early application permitted. ARC is currently assessing the impact of the standard. 4. CORPORATE ACQUISITIONS On December 21, 2009, ARC acquired all of the issued and outstanding shares of two legal entities - 1504793 Alberta Ltd. and PetroBakken General Partnership No. 1 (collectively "Ante Creek") - for total consideration of $178.9 million. The allocation of the purchase price and consideration paid were as follows: Net Assets Acquired --------------------------------------------------------------------- Property, plant and equipment $ 231.0 Asset retirement obligations (4.0) Future income taxes (48.1) --------------------------------------------------------------------- Total net assets acquired $ 178.9 --------------------------------------------------------------------- --------------------------------------------------------------------- Consideration Paid --------------------------------------------------------------------- Cash and fees paid $ 178.9 --------------------------------------------------------------------- Total consideration paid $ 178.9 --------------------------------------------------------------------- --------------------------------------------------------------------- The acquisition of Ante Creek has been accounted for as an asset acquisition pursuant to EIC - 124. The future income tax liability on acquisition was based on the difference between the fair value of the acquired net assets of $178.9 million and the associated tax basis of $35.8 million. These Consolidated Financial Statements incorporate the results of operations of the acquired Ante Creek properties from December 21, 2009. 5. CASH AND CASH EQUIVALENTS Cash and cash equivalents are nil as at December 31, 2009 ($40 million in Canadian Treasury Bills as at December 31, 2008). 6. FINANCIAL ASSETS AND CREDIT RISK Credit risk is the risk of financial loss to ARC if a partner or counterparty to a product sales contract or financial instrument fails to meet its contractual obligations. ARC is exposed to credit risk with respect to its cash equivalents, accounts receivable, reclamation funds, and risk management contracts. Most of ARC's accounts receivable relate to oil and natural gas sales and are subject to typical industry credit risks. ARC manages this credit risk as follows: - By entering into sales contracts with only established credit worthy counterparties as verified by a third party rating agency, through internal evaluation or by requiring security such as letters of credit; - By limiting exposure to any one counterparty in accordance with ARC's credit policy; and - By restricting cash equivalent investments, reclamation fund investments, and risk management transactions to counterparties that, at the time of transaction, are not less than investment grade. The majority of the credit exposure on accounts receivable at December 31, 2009 pertains to accrued revenue for December 2009 production volumes. ARC transacts with a number of oil and natural gas marketing companies and commodity end users ("commodity purchasers"). Commodity purchasers and marketing companies typically remit amounts to ARC by the 25th day of the month following production. Joint interest receivables are typically collected within one to three months following production. At December 31, 2009, no one counterparty accounted for more than 25 per cent of the total accounts receivable balance and the largest commodity purchaser receivable balance is fully secured with Letters of Credit. For the year ended December 31, 2009, ARC recorded a recovery of $1.7 million for amounts received on balances previously included in ARC's allowance for doubtful accounts. The recovery includes $1.2 million for settlement of oil revenues that were previously due from SemCanada Crude ("SemCanada"), a counterparty that marketed a portion of ARC's production and had filed for protection under the Companies' Creditors Arrangement Act in 2008. The remaining $0.5 million is composed of $0.6 million recovered from one counterparty and $0.1 million written off for balances deemed uncollectable from various counterparties. ARC's allowance for doubtful accounts was $0.8 million as at December 31, 2009 and $32 million as at December 31, 2008. In 2008, ARC recorded a provision for the full receivable of $30.6 million due from SemCanada. As noted above, upon settlement of the SemCanada oil revenue claim, ARC recovered $1.2 million and has written off the balance in the allowance of $28.8 million. As at December 31, 2009, $0.6 million remains in the allowance for the SemCanada gas revenue claim. The remaining movement of $1.2 million is composed of $0.6 million settled on balances previously included in the provision and $0.6 million written off for balances deemed uncollectable. During the twelve months of 2009 ARC did not record any additional provision for non-collectible accounts receivable. When determining whether amounts that are past due are collectable, management assesses the credit worthiness and past payment history of the counterparty, as well as the nature of the past due amount. ARC considers all amounts greater than 90 days to be past due. As at December 31, 2009, $4.4 million of accounts receivable are past due, excluding amounts described above, all of which are considered to be collectable. Maximum credit risk is calculated as the total recorded value of cash equivalents, accounts receivable, reclamation funds, and risk management contracts at the balance sheet date. 7. RECLAMATION FUNDS --------------------------------------------------------------------- December 31, 2009 December 31, 2008 --------------------------------------------------------------------- Unrestricted Restricted Unrestricted Restricted --------------------------------------------------------------------- Balance, beginning of year $ 11.2 $ 17.0 $ 14.4 $ 11.7 Contributions 6.2 5.3 5.8 5.9 Reimbursed expenditures(1) (5.9) (1.8) (9.7) (1.0) Interest earned on funds 0.7 0.1 0.8 0.4 Net unrealized gains and losses on available-for-sale investments 0.4 - (0.1) - --------------------------------------------------------------------- Balance, end of year(2) $ 12.6 $ 20.6 $ 11.2 $ 17.0 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Amount differs from actual expenditures incurred by ARC due to timing differences and discretionary reimbursements. (2) As at December 31, 2009 the unrestricted reclamation fund held $0.2 million in cash and cash equivalents (nil at December 31, 2008), with the balance held in investment grade assets. ARC has established two reclamations funds to finance future asset retirement obligations; one fund has been restricted to finance obligations specifically associated with the Redwater property, with the unrestricted fund financing all other obligations. Contributions to the restricted and unrestricted reclamation funds and interest earned on the balances have been deducted from the cash distributions to the unitholders. The Board of Directors of ARC Resources has approved voluntary contributions to the unrestricted reclamation fund over a 20-year period that currently results in minimum annual contributions of $6 million ($6 million in 2008) based upon properties owned as at December 31, 2009. Required contributions to the restricted reclamation fund will vary over time and have been disclosed in Note 22. Contributions for both funds are continually reassessed to ensure that the funds are sufficient to finance the majority of future abandonment obligations. Interest earned on the funds is retained within the funds. For the years ended December 31, 2009 and December 31, 2008, nominal amounts relating to available-for-sale reclamation fund assets were classified from accumulated other comprehensive income into earnings. As at December 31, 2009 all reclamation fund assets are reflected at fair value. The fair values are obtained from third parties, determined directly by reference to quoted market prices. 8. PROPERTY, PLANT AND EQUIPMENT --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Property, plant and equipment, at cost $ 6,242.8 $ 5,668.9 Accumulated depletion and depreciation (2,669.4) (2,292.3) --------------------------------------------------------------------- Property, plant and equipment, net $ 3,573.4 $ 3,376.6 --------------------------------------------------------------------- --------------------------------------------------------------------- The calculation of 2009 depletion and depreciation included an estimated $1,060 million ($872 million in 2008) for future development costs associated with proved undeveloped reserves and excluded $268.9 million ($287.5 million in 2008) for the book value of unproved properties. ARC performed a ceiling test calculation at December 31, 2009 to assess the recoverable value of property plant and equipment ("PP&amp;E"). Based on the calculation, the value of future net revenues from ARC's reserves exceeded the carrying value of ARC's PP&amp;E at December 31, 2009. The benchmark prices used in the calculation were as follows: WTI Oil AECO Gas Cdn$/US$ Year (US$/bbl) (Cdn$/mmbtu) Exchange Rates --------------------------------------------------------------------- 2010 80.00 5.96 0.95 2011 83.00 6.79 0.95 2012 86.00 6.89 0.95 2013 89.00 6.95 0.95 2014 92.00 7.05 0.95 2015 93.84 7.16 0.95 2016 95.72 7.42 0.95 2017 97.64 7.95 0.95 2018 99.59 8.52 0.95 2019 101.58 8.69 0.95 --------------------------------------------------------------------- Remainder(1) 2.0% 2.0% 0.95 --------------------------------------------------------------------- (1) Percentage change represents the change in each year after 2019 to the end of the reserve life. 9. FINANCIAL LIABILITIES AND LIQUIDITY RISK Liquidity risk is the risk that ARC will not be able to meet its financial obligations as they become due. ARC actively manages its liquidity through cash, distribution policy, and debt and equity management strategies. Such strategies include continuously monitoring forecasted and actual cash flows from operating, financing and investing activities, available credit under existing banking arrangements and opportunities to issue additional Trust units. Management believes that future cash flows generated from these sources will be adequate to settle ARC's financial liabilities. The following table details ARC's financial liabilities as at December 31, 2009: --------------------------------------------------------------------- ($ millions) 1 year 2 - 3 4 - 5 Beyond Total years years 5 years --------------------------------------------------------------------- Accounts payable and accrued liabilities(1) 166.7 - - - 166.7 Distributions payable(2) 18.9 - - - 18.9 Risk management contracts(3) 14.8 2.1 - - 16.9 Senior secured notes and interest 47.1 109.9 131.6 152.9 441.5 Revolving credit facilities - 497.3 - - 497.3 Working capital facility 7.9 - - - 7.9 Accrued long-term incentive compensation(1) 28.4 36.0 - - 64.4 --------------------------------------------------------------------- Total financial liabilities 283.8 645.3 131.6 152.9 1,213.6 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Liabilities under the Whole Trust Unit Incentive Plan represent the total amount expected to be paid out on vesting. (2) Amounts payable for the distribution represents the net cash payable after distribution reinvestment. (3) Amounts payable for the risk management contracts have been included gross at their future value. ARC actively maintains credit and working capital facilities to ensure that it has sufficient available funds to meet its financial requirements at a reasonable cost. Refer to Note 10 for further details on available amounts under existing banking arrangements and Note 12 for further details on capital management. 10. LONG-TERM DEBT --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Syndicated credit facilities: Cdn$ denominated(1) $ 423.0 $ 399.5 US$ denominated 74.3 240.6 Working capital facility 7.9 2.1 Senior secured notes: Master Shelf Agreement 5.42% US$ Note 78.5 91.9 4.94% US$ Note 6.3 14.7 2004 Note Issuance 4.62% US$ Note 54.5 76.5 5.10% US$ Note 65.4 76.5 2009 Note Issuance 7.19% US$ Note 70.6 - 8.21% US$ Note 36.6 - 6.50% Cdn$ Note 29.0 - --------------------------------------------------------------------- Total long-term debt outstanding $ 846.1 $ 901.8 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Syndicated credit facility balance was reduced on January 5, 2010. Refer to Note 23 for further details. Credit Facilities ARC has an $800 million secured, annually extendible, financial covenant-based syndicated credit facility. ARC also has in place a $25 million demand working capital facility. The working capital facility is also secured and is subject to the same covenants as the syndicated credit facility. Borrowings under the syndicated credit facility bear interest at bank prime (2.25 per cent at December 31, 2009, four per cent at December 31, 2008) or, at ARC's option, Canadian dollar bankers' acceptances or U.S. dollar LIBOR loans, plus a stamping fee. At the option of ARC, the lenders will review the syndicated credit facility each year and determine whether they will extend the revolving period for another year. In the event that the syndicated credit facility is not extended at any time before the maturity date, the loan balance will become repayable on the maturity date. The maturity date of the current syndicated credit facility is April 15, 2011. All drawings under the facility are subject to stamping fees. These stamping fees vary between a minimum of 60 basis points ("bps") to a maximum of 110 bps. During 2009, the weighted-average interest rate under the credit facility was 1.1 per cent (3.8 per cent in 2008). Senior Secured Notes Issued Under a Master Shelf Agreement These senior secured notes were issued in two separate tranches pursuant to an Uncommitted Master Shelf Agreement. The terms and rates of these senior secured notes are summarized below: --------------------------------------------------------------------- Remaining Coupon Maturity Principal Issue Date Principal Rate Date Payment Terms --------------------------------------------------------------------- October 19, US$6.0 4.94% October 19, Five equal 2002 2010 installments beginning October 19, 2006 December 15, US$75.0 5.42% December 15, Eight equal 2005 2017 installments beginning December 15, 2010 --------------------------------------------------------------------- --------------------------------------------------------------------- In the second quarter of 2009 ARC extended its Uncommitted Master Shelf Agreement from May 2009 to April 2012. The extended agreement allows for an aggregate draw of up to US$225 million in 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. Senior Secured Notes not Subject to the Master Shelf Agreement 2004 Note Issuance These notes were issued on April 27, 2004 via a private placement in two tranches. The terms and rates of these senior secured notes are summarized below. 2009 Note Issuance These notes were issued on April 14, 2009 via a private placement in three tranches. The terms and rates of these senior secured notes are summarized below. --------------------------------------------------------------------- Remaining Coupon Maturity Issue Date Principal Rate Date Payment Terms --------------------------------------------------------------------- April 27, US$52.1 4.62% April 27, Six equal 2004 2014 installments beginning April 27, 2009 April 27, US$62.5 5.10% April 27, Five equal 2004 2016 installments beginning April 27, 2012 April 14, US$67.5 7.19% April 14, Five equal 2009 2016 installments beginning April 14, 2012 April 14, US$35.0 8.21% April 14, Five equal 2009 2021 installments beginning April 14, 2017 April 14, Cdn$29.0 6.50% April 14, Five equal 2009 2016 installments beginning April 14, 2012 --------------------------------------------------------------------- --------------------------------------------------------------------- Credit Capacity The following table summarizes ARC's available credit capacity and the current amounts drawn as at December 31, 2009: --------------------------------------------------------------------- Credit Capacity Drawn Remaining --------------------------------------------------------------------- Syndicated Credit Facility $ 800.0 $ 497.3 $ 302.7 Working Capital Facility 25.0 7.9 17.1 Senior Secured Notes Subject to a Master Shelf Agreement(1) 235.5 84.8 150.7 Senior Secured Notes Not Subject to a Master Shelf Agreement 256.1 256.1 - --------------------------------------------------------------------- Total $ 1,316.6 $ 846.1 $ 470.5 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Total credit capacity is US$225 million. Debt Covenants The following are the significant financial covenants governing the revolving credit facilities: - Long-term debt and letters of credit not to exceed three times trailing twelve month net income before non-cash items and interest expense; - Long-term debt, letters of credit, and subordinated debt not to exceed four times trailing twelve month net income before non- cash items and interest expense; and - Long-term debt and letters of credit not to exceed 50 per cent of the book value of unitholders' equity and long-term debt, letters of credit, and subordinated debt. In the event that ARC enters into a material acquisition whereby the purchase price exceeds 10 per cent of the book value of ARC's assets, the ratio in the first covenant is increased to 3.5 times, while the third covenant is increased to 55% for the subsequent six month period. As at December 31, 2009, ARC had $2 million in letters of credit ($1.9 million in 2008), no subordinated debt, and was in compliance with all covenants. The payment of principal and interest are allowable deductions in the calculation of cash available for distribution to unitholders and rank ahead of cash distributions payable to unitholders. Should the properties securing this debt generate insufficient revenue to repay the outstanding balances, the unitholders have no direct liability. Supplemental disclosures The fair value of all senior secured notes as at December 31, 2009, is $347.3 million compared to a carrying value of $340.9 million ($289.9 million compared to $259.6 million as at December 31, 2008), and is calculated as the present value of principal and interest payments discounted at ARC's credit adjusted risk free rate. Amounts of US$16.4 million due under the senior secured notes (includes US$6 million attributable to the Master Shelf Agreement) and $7.9 million due under ARC's working capital facility in the next 12 months have not been included in current liabilities as management has the ability and intent to refinance this amount through the syndicated credit facility. Interest paid during 2009 was $2.6 million more than interest expense ($1.6 million more in 2008). ARC's total long-term debt is secured in the form of a floating charge on all lands and assignments and a negative pledge on petroleum and natural gas properties. 11. ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligations were estimated by management based on ARC's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. ARC has estimated the net present value of its total asset retirement obligations to be $149.9 million as at December 31, 2009 ($141.5 million in 2008) based on a total future undiscounted liability of $1.36 billion ($1.32 billion in 2008). At December 31, 2009 management estimates that these payments are expected to be made over the next 51 years with the majority of payments being made in years 2050 to 2060. ARC's weighted average credit adjusted risk free rate of 6.5 per cent (6.6 per cent in 2008) and an inflation rate of two per cent (two per cent in 2008) were used to calculate the present value of the asset retirement obligations. During the year, no gains or losses were recognized on settlements of asset retirement obligations. The following table reconciles ARC's asset retirement obligations: --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Balance, beginning of year $ 141.5 $ 140.0 Increase in liabilities relating to corporate acquisitions 4.0 - Increase in liabilities relating to development activities 1.7 2.0 Increase in liabilities relating to change in estimate 2.1 2.6 Settlement of reclamation liabilities during the year (8.7) (12.4) Accretion expense 9.3 9.3 --------------------------------------------------------------------- Balance, end of year $ 149.9 $ 141.5 --------------------------------------------------------------------- --------------------------------------------------------------------- 12. CAPITAL MANAGEMENT The objective of ARC when managing its capital is to maintain a conservative structure that will allow it to: - Fund its development and exploration program; - Provide financial flexibility to execute on strategic opportunities; - Maintain a level of distributions that, in normal times, in the opinion of Management and the Board of Directors, is sustainable for a minimum period of six months in order to normalize the effect of commodity price volatility to unitholders; and ARC manages the following capital: - Trust units and exchangeable shares; - Long-term debt; and - Working capital (defined as current assets less current liabilities excluding risk management contracts and future income taxes). When evaluating ARC's capital structure, management's objective is to limit net debt to less than two times annualized cash flow from operating activities and 20 per cent of total capitalization. As at December 31, 2009 ARC's net debt to annualized cash flow from operating activities ratio is 1.8 and its net debt to total capitalization ratio is 15.9 per cent. --------------------------------------------------------------------- ($ millions, except per unit December 31, December 31, and per cent amounts) 2009 2008 --------------------------------------------------------------------- Long-term debt 846.1 901.8 Accounts payable and accrued liabilities 166.7 194.4 Distributions payable 23.7 32.5 Cash and cash equivalents, accounts receivable and prepaid expenses (134.1) (166.8) --------------------------------------------------------------------- Net debt obligations(1) 902.4 961.9 --------------------------------------------------------------------- Trust units outstanding and issuable for exchangeable shares (millions) 239.0 219.2 Trust unit price(2) 19.94 20.10 --------------------------------------------------------------------- Market capitalization(1) 4,765.7 4,405.9 Net debt obligations(1) 902.4 961.9 --------------------------------------------------------------------- Total capitalization(1) 5,668.1 5,367.8 --------------------------------------------------------------------- Net debt as a percentage of total capitalization 15.9% 17.9% Net debt obligations to annualized cash flow from operating activities 1.8 1.0 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Market capitalization, net debt obligations and total capitalization 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. (2) TSX close price as at December 31, 2009 and December 31, 2008 respectively. ARC manages its capital structure and makes adjustments to it in response to changes in economic conditions and the risk characteristics of the underlying assets. ARC is able to change its capital structure by issuing new trust units, exchangeable shares, new debt or changing its distribution policy. In addition to internal capital management ARC is subject to various covenants under its credit facilities. Compliance with these covenants is monitored on a quarterly basis and as at December 31, 2009 ARC is in compliance with all covenants. Refer to Note 10 for further details. 13. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT Financial Instrument Classification and Measurement Financial instruments of ARC carried on the Consolidated Balance Sheet are carried at amortized cost with the exception of cash and cash equivalents, reclamation fund assets and risk management contracts, which are carried at fair value. With the exception of ARC's senior secured notes, there were no significant differences between the carrying value of financial instruments and their estimated fair values as at December 31, 2009. The fair value of the ARC's senior secured notes is disclosed in Note 10. All of ARC's cash and cash equivalents, risk management contracts, and reclamation fund investments are transacted in active markets. ARC classifies the fair value of these transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument. - Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. - Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. - Level 3 - Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. ARC's cash and cash equivalents, reclamation fund assets and risk management contracts have been assessed on the fair value hierarchy described above. ARC's cash and cash equivalents and reclamation fund assets are classified as Level 1 and risk management contracts as Level 2. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level. Market Risk Management ARC is exposed to a number of market risks that are part of its normal course of business. ARC has a risk management program in place that includes financial instruments as disclosed in the risk management section of this note. ARC's risk management program is overseen by its Risk Committee based on guidelines approved by the Board of Directors. The objective of the risk management program is to support ARC's business plan by mitigating adverse changes in commodity prices, interest rates and foreign exchange rates. In the sections below, ARC has prepared sensitivity analyses in an attempt to demonstrate the effect of changes in these market risk factors on ARC's net income. For the purposes of the sensitivity analyses, the effect of a variation in a particular variable is calculated independently of any change in another variable. In reality, changes in one factor may contribute to changes in another, which may magnify or counteract the sensitivities. For instance, trends have shown a correlation between the movement in the foreign exchange rate of the Canadian dollar to the U.S. dollar and the West Texas Intermediate posting ("WTI") crude oil price. Commodity price risk ARC's operational results and financial condition are largely dependent on the commodity prices received for oil and natural gas production. Commodity prices have fluctuated widely during recent years due to global and regional factors including supply and demand fundamentals, inventory levels, weather, economic, and geopolitical factors. Movement in commodity prices could have a significant positive or negative impact on distributions to unitholders. ARC manages the risks associated with changes in commodity prices by entering into a variety of risk management contracts (see Risk Management Contracts below). The following table illustrates the effects of movement in commodity prices on net income due to changes in the fair value of risk management contracts in place at December 31, 2009. The sensitivity is based on a $15 increase and $15 decrease in the price of US$ WTI crude oil and a $1.50 increase and $1.50 decrease in the price of Cdn$ AECO natural gas. The commodity price assumptions are based on management's assessment of reasonably possible changes in oil and natural gas prices that could occur between December 31, 2009 and ARC's next reporting date. --------------------------------------------------------------------- Increase in Commodity Price Decrease in Commodity Price --------------------------------------------------------------------- Crude oil Natural gas Crude oil Natural gas --------------------------------------------------------------------- Net income (decrease) increase $ (21.7) $ (54.6) $ 19.1 $ 54.1 --------------------------------------------------------------------- --------------------------------------------------------------------- As noted above, the sensitivities are hypothetical and based on Management's assessment of reasonably possible changes in commodity prices between the balance sheet date and ARC's next reporting date. The results of the sensitivity should not be considered to be predictive of future performance. Changes in the fair value of risk management contracts cannot generally be extrapolated because the relationship of change in certain variables to a change in fair value may not be linear. Interest Rate Risk ARC has both fixed and variable interest rates on its debt. Changes in interest rates could result in an increase or decrease in the amount ARC pays to service variable interest rate debt, potentially impacting distributions to unitholders. Changes in interest rates could also result in fair value risk on ARC's fixed rate senior secured notes. Fair value risk of the senior secured notes is mitigated due to the fact that ARC does not intend to settle its fixed rate debt prior to maturity. If interest rates applicable to floating rate debt at December 31, 2009 were to have increased by 50 bps (0.5 per cent) it is estimated that ARC's net income would decrease by $1.9 million. Management does not expect interest rates to decrease. Foreign Exchange Risk North American oil and natural gas prices are based upon U.S. dollar denominated commodity prices. As a result, the price received by Canadian producers is affected by the Canadian/U.S. dollar exchange rate that may fluctuate over time. In addition ARC has U.S. dollar denominated debt and interest obligations of which future cash repayments are directly impacted by the exchange rate in effect on the repayment date. Variations in the Canadian/U.S. dollar exchange rate could also have a positive or negative impact on distributions to unitholders. The following table demonstrates the effect of exchange rate movements on net income due to changes in the fair value of risk management contracts in place at December 31, 2009 as well as the unrealized gain or loss on revaluation of outstanding US$ denominated debt. The sensitivity is based on a $0.10 Cdn$/US$ increase and $0.10 Cdn$/US$ decrease in the foreign exchange rate. --------------------------------------------------------------------- Increase in Decrease in Cdn$/US$ rate Cdn$/US$ rate --------------------------------------------------------------------- Increase gain/decrease loss (increase loss/decrease gain) on risk management contracts $ 1.5 $ (1.5) (Increase loss/decrease gain) increase gain/decrease loss on foreign exchange (28.6) 29.5 --------------------------------------------------------------------- Net income (decrease) increase $ (27.1) $ 28.0 --------------------------------------------------------------------- --------------------------------------------------------------------- Increases and decreases in foreign exchange rates applicable to US$ payables and receivables would have a nominal impact on ARC's net income for the period ended December 31, 2009. Risk Management Contracts ARC uses a variety of derivative instruments to reduce its exposure to fluctuations in commodity prices, foreign exchange rates, interest rates and power prices. ARC considers all of these transactions to be effective economic hedges; however, the majority of ARC's contracts do not qualify as effective hedges for accounting purposes. Following is a summary of all risk management contracts in place as at December 31, 2009 that do not qualify for hedge accounting: --------------------------------------------------------------------- Financial WTI Crude Oil Option Contracts(1) --------------------------------------------------------------------- Bought Sold Sold Volume Put Put Call Term Contract bbl/d US$/bbl US$/bbl US$/bbl --------------------------------------------------------------------- 1-Jan-10 31-Mar-10 Collar 1,000 $65.00 - $80.00 1-Jan-10 31-Dec-10 Collar 4,000 $70.00 - $90.00 1-Jan-10 31-Dec-10 Collar 2,000 $75.00 - $95.00 1-Jan-10 31-Dec-10 3-way collar 2,000 $80.00 $60.00 $95.00 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Monthly average --------------------------------------------------------------------- Financial AECO Natural Gas Swap Contracts(2) --------------------------------------------------------------------- Sold Volume Swap Term Contract GJ/d Cdn$/GJ --------------------------------------------------------------------- 1-Jan-10 31-Dec-10 Swap 80,000 $5.61 1-Jan-11 31-Dec-13 Swap 20,000 $6.16 --------------------------------------------------------------------- --------------------------------------------------------------------- (2) AECO 7a monthly index --------------------------------------------------------------------- Financial NYMEX Natural Gas Swap Contracts(3) --------------------------------------------------------------------- Volume Sold Swap Term Contract mmbtu/d US$/mmbtu --------------------------------------------------------------------- 1-Apr-10 31-Oct-10 Swap 20,000 $6.00 --------------------------------------------------------------------- --------------------------------------------------------------------- (3) Last 3 Day Settlement --------------------------------------------------------------------- Financial Basis Swap Contract(4) --------------------------------------------------------------------- Volume Basis Swap Term Contract mmbtu/d US$/mmbtu --------------------------------------------------------------------- 1-Jan-10 31-Oct-10 Basis Swap-L3d 50,000 ($1.0430) 1-Nov-10 31-Oct-11 Basis Swap-Ld 15,000 ($0.4850) 1-Nov-11 31-Oct-12 Basis Swap-Ld 15,000 ($0.4067) --------------------------------------------------------------------- --------------------------------------------------------------------- (4) Receive Nymex Last Day (Ld) or Last 3 Day (L3d); pay AECO 7a monthly index --------------------------------------------------------------------- US$ Debt Repayment Contracts --------------------------------------------------------------------- Notional Volume Swap Swap Settlement Date Contract US$ millions Cdn$/US$ US$/Cdn$ --------------------------------------------------------------------- 21-Jan-10 Forward 20.00 $1.0480 $0.9542 --------------------------------------------------------------------- --------------------------------------------------------------------- --------------------------------------------------------------------- Financial Electricity Heat Rate Contracts(5) --------------------------------------------------------------------- Heat Volume AESO Power AECO 5a multiplied Rate Term Contract MWh $/MWh $/GJ by GJ/MWh --------------------------------------------------------------------- 1-Jan-10 Heat Rate Receive Pay AECO 31-Dec-10 Swap 10 AESO 5a x 9.15 1-Jan-11 Heat Rate Receive Pay AECO 31-Dec-11 Swap 15 AESO 5a x 9.08 1-Jan-12 Heat Rate Receive Pay AECO 31-Dec-13 Swap 10 AESO 5a x 9.15 --------------------------------------------------------------------- --------------------------------------------------------------------- (5) Alberta Power Pool (monthly average 24x7); AECO 5a monthly index --------------------------------------------------------------------- Financial Electricity Contracts(6) --------------------------------------------------------------------- Volume Bought Swap Term Contract MWh Cdn$/MWh --------------------------------------------------------------------- 1-Jan-10 31-Dec-12 Swap 5 $72.495 --------------------------------------------------------------------- --------------------------------------------------------------------- (6) Alberta Power Pool (monthly average 24x7); AECO 5a monthly index Following is a summary of all risk management contracts in place as at December 31, 2009 that qualify for hedge accounting: --------------------------------------------------------------------- Financial Electricity Contracts(7) --------------------------------------------------------------------- Volume Bought Swap Term Contract MWh Cdn$/MWh --------------------------------------------------------------------- 1-Jan-10 31-Dec-10 Swap 5 $63.00 --------------------------------------------------------------------- --------------------------------------------------------------------- (7) Alberta Power Pool (monthly average 24x7), AECO 5a monthly index At December 31, 2009, the fair value of the contracts that were not designated as accounting hedges was a loss of $4.3 million. ARC recorded a gain on risk management contracts of $11.7 million in the statement of income for the year ended December 31, 2009 ($7.7 million loss in 2008). This amount includes the realized and unrealized gains and losses on risk management contracts that do not qualify as effective accounting hedges. The following table reconciles the movement in the fair value of ARC's financial risk management contracts that have not been designated as effective accounting hedges: --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Fair value, beginning of year $ 3.4 $ (64.6) Fair value, end of year(1) (4.3) 3.4 --------------------------------------------------------------------- Change in fair value of contracts in the year (7.7) 68.0 Realized gain (loss) in the year 19.4 (75.7) --------------------------------------------------------------------- Gain (loss) on risk management contracts $ 11.7 $ (7.7) --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Intrinsic value of risk management contracts not designated as effective accounting hedges equals a loss of $3.5 million at December 31, 2009 ($0.9 million loss at December 31, 2008). During 2007 ARC entered into treasury rate lock contracts in order to manage ARC's interest rate exposure on future debt issuances. During 2008 it was determined that the previously anticipated debt issuance was no longer expected to occur and the associated treasury rate lock contracts were unwound at a loss of $13.6 million. The loss was reclassified from Other Comprehensive Income ("OCI"), net of tax $10 million and recognized in net income. ARC's electricity contracts are intended to manage price risk on electricity consumption. Portions of ARC's financial electricity contracts were designated as effective accounting hedges on their respective contract dates. A realized loss of $1.5 million for the year ended December 31, 2009 (gain of $3.9 million in 2008) has been included in operating costs on these electricity contracts. The accumulated unrealized fair value loss of $0.5 million on these contracts has been recorded on the Consolidated Balance Sheet at December 31, 2009 with the movement in fair value recorded in OCI, net of tax. The fair value movement for the year ended December 31, 2009 is an unrealized loss of $3.8 million. As at December 31, 2009 all of the unrealized fair value loss is attributed to contracts that will settle over the next twelve months. The following table reconciles the movement in the fair value of ARC's financial risk management contracts that have been designated as effective accounting hedges: --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Fair value, beginning of year $ 3.3 $ (3.4) Change in fair value of financial electricity contracts (3.8) (0.7) Change in fair value of treasury rate lock contracts prior to de-designation - (6.2) Reclassification of loss on treasury rate lock contracts to net income - 13.6 --------------------------------------------------------------------- Fair value, end of year(1) $ (0.5) $ 3.3 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Intrinsic value of risk management contracts designated as effective accounting hedges equals a loss of $0.5 million at December 31, 2009 ($3.4 million gain at December 31, 2008). 14. GAIN (LOSS) ON FOREIGN EXCHANGE The following is a summary of the total gain (loss) on US$ denominated transactions: --------------------------------------------------------------------- Three Months Twelve Months Ended Ended December 31 December 31 --------------------------------------------------------------------- 2009 2008 2009 2008 --------------------------------------------------------------------- Unrealized gain (loss) on US$ denominated debt $ 5.7 $ (63.9) $ 66.3 $ (90.8) Realized gain on US$ denominated debt repayments 3.1 2.3 2.7 2.3 --------------------------------------------------------------------- Total non-cash gain (loss) on US$ denominated transactions 8.8 (61.6) 69.0 (88.5) Realized cash gain (loss) on US$ denominated transactions 0.9 0.4 1.0 (0.9) --------------------------------------------------------------------- Total foreign exchange gain (loss) $ 9.7 $ (61.2) $ 70.0 $ (89.4) --------------------------------------------------------------------- --------------------------------------------------------------------- 15. INCOME TAXES In 2007, Income Trust tax legislation was passed resulting in a two- tiered tax structure subjecting distributions to the federal corporate income tax rate plus a deemed 13 per cent provincial income tax at the Trust level commencing in 2011. On March 4, 2009 legislation was passed providing that the provincial component of the tax on ARC is to be calculated based on the general provincial rate in each province in which ARC has a permanent establishment. This is the same way that a corporation would calculate its provincial tax rate. The provincial component of the tax was substantively enacted as of December 31, 2009 but was not substantively enacted as of December 31, 2008. ARC has reflected a reduced tax rate in the calculation of future income taxes in 2009. The tax provision differs from the amount computed by applying the combined Canadian federal and provincial statutory income tax rates to income before future income tax recovery as follows: --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Income before future income tax recovery and non-controlling interest $ 192.3 $ 535.4 --------------------------------------------------------------------- Canadian statutory rate(1) 29.0% 32.4% --------------------------------------------------------------------- Expected income tax expense at statutory rates 55.8 173.4 Effect on income tax of: Net income of ARC (86.0) (181.2) Effect of change in corporate tax rate 7.2 (8.9) Unrealized loss (gain) on foreign exchange (9.7) 13.4 Change in estimated pool balances (0.7) (1.0) Other non-deductible items 0.6 (0.2) --------------------------------------------------------------------- Future income tax recovery $ (32.8) $ (4.5) --------------------------------------------------------------------- --------------------------------------------------------------------- (1) The statutory rate consists of the combined Trust and Trust's subsidiaries statutory tax rate The net future income tax liability is comprised of the following: --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Future tax liabilities: Capital assets in excess of tax value $ 418.3 $ 381.4 Risk management contracts - 1.7 Other comprehensive income - 0.8 Long-term debt 8.5 0.2 Future tax assets: Asset retirement obligations (37.6) (35.8) Non-capital losses (49.9) (24.4) Risk management contracts (1.1) - Other comprehensive loss (0.1) - Trust unit incentive compensation expense (8.2) (8.3) Attributed Canadian royalty income (4.5) (4.6) CEC, SR&amp;ED pools and deductible share issue costs (3.6) (1.6) --------------------------------------------------------------------- Net future income tax liability $ 321.8 $ 309.4 --------------------------------------------------------------------- Net future income tax asset, current $ 7.1 $ 3.9 Net future income tax liability, long-term $ 328.9 $ 313.3 --------------------------------------------------------------------- --------------------------------------------------------------------- The petroleum and natural gas properties and facilities owned by ARC have an approximate tax basis of $2.23 billion ($2.07 billion in 2008) available for future use as deductions from taxable income. Included in this tax basis are estimated non-capital loss carry forwards of $181.9 million ($86.9 million in 2008) that expire in the years 2027 through 2029. The following is a summary of the estimated ARC tax pools: --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Canadian oil and gas property expenses $ 951.6 $ 1,001.3 Canadian development expenses 391.1 360.7 Canadian exploration expenses 105.6 41.5 Undepreciated capital costs 432.2 414.5 Non-capital losses 181.9 86.9 SR&amp;ED tax pools 0.8 0.3 Other 15.2 7.0 --------------------------------------------------------------------- Estimated tax basis, federal 2,078.4 1,912.2 --------------------------------------------------------------------- Provincial tax pools 155.5 155.9 --------------------------------------------------------------------- Estimated tax basis, federal and provincial $ 2,233.9 $ 2,068.1 --------------------------------------------------------------------- --------------------------------------------------------------------- No current income taxes were paid or payable in both 2009 and 2008. 16. EXCHANGEABLE SHARES ARC is authorized to issue an unlimited number of ARL Exchangeable Shares that can be converted (at the option of the holder) into trust units at any time. The number of Trust units issuable upon conversion is based upon the exchange ratio in effect at the conversion date. The exchange ratio is calculated monthly based on the cash distribution paid divided by the 10 day weighted average unit price preceding the record date and multiplied by the opening exchange ratio. The exchangeable shares are not eligible for distributions and, in the event that they are not converted, any outstanding shares are redeemable by ARC for Trust units on August 28, 2012. The ARL Exchangeable Shares are publicly traded. --------------------------------------------------------------------- December 31, December 31, (units thousands) 2009 2008 --------------------------------------------------------------------- Balance, beginning of year 1,092 1,310 Exchanged for trust units(1) (221) (218) --------------------------------------------------------------------- Balance, end of year 871 1,092 Exchange ratio, end of year 2.71953 2.51668 Trust units issuable upon conversion, end of year 2,369 2,748 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) During 2009, 220,573 ARL exchangeable shares were converted to trust units at an average exchange ratio of 2.59547, compared to 218,455 exchangeable shares at an average exchange ratio of 2.36901 during the year ended 2008. The non-controlling interest on the Consolidated Balance Sheet consists of the fair value of the exchangeable shares upon issuance plus the accumulated earnings attributable to the non-controlling interest. The net income attributable to the non-controlling interest on the Consolidated Statement of Income represents the cumulative share of net income attributable to the non-controlling interest based on the Trust units issuable for exchangeable shares in proportion to total Trust units issued and issuable at each period end. Following is a summary of the non-controlling interest for 2009 and 2008: --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Non-controlling interest, beginning of year $ 42.4 $ 43.1 Reduction of book value for conversion to trust units (8.7) (7.6) Current period net income attributable to non-controlling interest 2.3 6.9 --------------------------------------------------------------------- Non-controlling interest, end of year 36.0 42.4 --------------------------------------------------------------------- --------------------------------------------------------------------- Accumulated earnings attributable to non-controlling interest $ 43.3 $ 41.0 --------------------------------------------------------------------- --------------------------------------------------------------------- 17. UNITHOLDERS' CAPITAL ARC is authorized to issue 650 million Trust units of which 236.6 million units were issued and outstanding as at December 31, 2009 (216.4 million as at December 31, 2008). ARC has in place a Distribution Reinvestment and Optional Cash Payment Program ("DRIP") in conjunction with the Trusts' transfer agent to provide the option for unitholders to reinvest cash distributions into additional trust units issued from treasury at a five per cent discount to the prevailing market price with no additional fees or commissions. ARC is an open ended mutual fund under which unitholders have the right to request redemption directly from ARC. Trust units tendered by holders are subject to redemption under certain terms and conditions including the determination of the redemption price at the lower of the closing market price on the date units are tendered or 90 per cent of the weighted average trading price for the 10 day trading period commencing on the tender date. Cash payments for trust units tendered for redemption are limited to $100,000 per month with redemption requests in excess of this amount eligible to receive a note from ARC Resources Ltd. accruing interest at 4.5 per cent and repayable within 20 years. --------------------------------------------------------------------- December 31, 2009 December 31, 2008 --------------------------------------------------------------------- Number Number of trust of trust (units thousands) units $ units $ --------------------------------------------------------------------- Balance, beginning of year 216,435 2,600.7 210,232 2,465.7 Issued for cash 15,474 253.0 - - Issued on conversion of ARL exchangeable shares (Note 16) 572 8.6 517 7.6 Issued on exercise of employee rights - - 238 4.2 Distribution reinvestment program 4,134 67.0 5,448 123.2 Trust unit issue costs, net of tax(1) - (11.7) - - --------------------------------------------------------------------- Balance, end of year(2) 236,615 2,917.6 216,435 2,600.7 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Amount is net of tax of $2.1 million for the period ended December 31, 2009. (2) The number of Trust units outstanding increased significantly on January 5, 2010. Refer to Note 23 for further details. Net income per trust unit has been determined based on the following: --------------------------------------------------------------------- Three Months Twelve Months Ended Ended December 31 December 31 --------------------------------------------------------------------- (units thousands) 2009 2008 2009 2008 --------------------------------------------------------------------- Weighted average trust units(1) 236,138 215,579 233,025 213,259 Trust units issuable on conversion of exchangeable shares(2) 2,369 2,748 2,369 2,748 Dilutive impact of rights(3) - 2 - 50 --------------------------------------------------------------------- Diluted trust units and exchangeable shares 238,507 218,329 235,394 216,057 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Weighted average trust units exclude trust units issuable for exchangeable shares. (2) Diluted trust units include trust units issuable for outstanding exchangeable shares at the year-end exchange ratio. (3) There are no rights outstanding as of December 31, 2009 and therefore, no dilutive impact. Previously outstanding rights were dilutive and therefore were included in the diluted unit calculation for 2008. Basic net income per unit has been calculated based on net income after non-controlling interest divided by weighted average trust units. Diluted net income per unit has been calculated based on net income before non-controlling interest divided by diluted trust units. 18. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Accumulated earnings $ 2,946.9 $ 2,724.1 Accumulated distributions (3,525.5) (3,227.0) --------------------------------------------------------------------- Deficit (578.6) (502.9) Accumulated other comprehensive (loss) income (0.6) 1.9 --------------------------------------------------------------------- Deficit and accumulated other comprehensive (loss) income $ (579.2) $ (501.0) --------------------------------------------------------------------- --------------------------------------------------------------------- The accumulated other comprehensive (loss) income balance is composed of the following items: --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Unrealized gains and losses on financial instruments designated as cash flow hedges $ (0.7) $ 2.0 Net unrealized gains and losses on available-for-sale reclamation funds' investments 0.1 (0.1) --------------------------------------------------------------------- Accumulated other comprehensive (loss) income, end of year $ (0.6) $ 1.9 --------------------------------------------------------------------- --------------------------------------------------------------------- 19. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND DISTRIBUTIONS Distributions are calculated in accordance with the Trust Indenture. To arrive at distributions, cash flow from operating activities is reduced by reclamation fund contributions including interest earned on the funds, a portion of capital expenditures and, when applicable, debt repayments. The portion of cash flow from operating activities withheld to fund capital expenditures and to make debt repayments is at the discretion of the Board of Directors. --------------------------------------------------------------------- Three Months Twelve Months Ended Ended December 31 December 31 --------------------------------------------------------------------- 2009 2008 2009 2008 --------------------------------------------------------------------- Cash flow from operating activities $ 143.2 $ 209.4 $ 497.4 $ 944.4 Deduct: Cash withheld to fund current period capital expenditures (70.8) (80.9) (194.3) (372.2) Net reclamation fund contributions (1.5) (1.3) (4.6) (2.2) --------------------------------------------------------------------- Distributions(1) 70.9 127.2 298.5 570.0 Accumulated distributions, beginning of period 3,454.6 3,099.8 3,227.0 2,657.0 --------------------------------------------------------------------- Accumulated distributions, end of period $ 3,525.5 $ 3,227.0 $ 3,525.5 $ 3,227.0 --------------------------------------------------------------------- --------------------------------------------------------------------- Distributions per unit(2) $ 0.30 $ 0.59 $ 1.28 $ 2.67 Accumulated distributions per unit, beginning of period $ 24.68 $ 23.11 $ 23.70 $ 21.03 Accumulated distributions per unit, end of period(3) $ 24.98 $ 23.70 $ 24.98 $ 23.70 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Distributions include accrued and non-cash amounts of $14.9 million and $56.2 million for the three and twelve months ended December 31, 2009, respectively ($9.7 million and $111.2 million for the same periods in 2008). (2) Distributions per trust unit reflect the sum of the per trust unit amounts declared monthly to unitholders. (3) Accumulated distributions per unit reflect the sum of the per trust unit amounts declared monthly to unitholders since the inception of ARC in July 1996. 20. TRUST UNIT INCENTIVE RIGHTS PLAN The Trust Unit Incentive Rights Plan (the "Rights Plan") was established in 1999 and authorized ARC to grant up to 8,000,000 rights to its employees, independent directors and long-term consultants to purchase Trust units, of which 7,866,088 were granted before the plan was discontinued in 2004 and replaced with the Whole Trust Unit Incentive Plan (see Note 21). During 2008 the remaining 238,000 rights were exercised, at a weighted average exercise price of $10.40. As at December 31, 2008 all rights issued under the Rights Plan had been exercised or cancelled. 21. WHOLE TRUST UNIT INCENTIVE PLAN The Whole Trust Unit Incentive Plan (the "Whole Unit Plan") results in employees, officers and directors (the "plan participants") receiving cash compensation in relation to the value of a specified number of underlying notional trust units. The Whole Unit Plan consists of Restricted Trust Units ("RTUs") for which the number of trust units is fixed and will vest evenly over a period of three years and Performance Trust Units ("PTUs") for which the number of trust units is variable and will vest at the end of three years. Upon vesting, the plan participant receives 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 future performance of ARC compared to its peers based on a performance multiplier. The performance multiplier is based on the percentile rank of ARC's Total Unitholder Return. The cash compensation issued upon vesting of the PTUs may range from zero to two times the value of the PTUs originally granted. During the year, cash payments of $16.6 million were made to employees relating to the Whole Unit Plan compared to $28.2 million in 2008. In October 2008, vesting periods were revised from April and October to March and September of each year commencing in 2009. Non-cash compensation expense associated with the Whole Unit Plan is determined based on the intrinsic value of the Whole Trust Units at each period end and is expensed in the statement of income and capitalized on the balance sheet over the vesting period. As the value of the RTUs and PTUs is dependent upon the trust unit price, the expense recorded may fluctuate over time. ARC recorded non-cash compensation expense of $(0.1) million and $0.7 million to general and administrative and operating expenses, respectively, and capitalized $0.1 million to property, plant and equipment in the year ended December 31, 2009 for the estimated change in the Plan liability ($1.1 million, $(0.1) million, and $0.6 million for the year ended December 31, 2008). The non-cash compensation expense was based on the December 31, 2009 unit price of $19.94 ($20.10 at December 31, 2008), accrued distributions, a performance multiplier, and the estimated number of units to be issued on maturity. The following table summarizes the RTU and PTU movement for the year ended December 31, 2009: --------------------------------------------------------------------- (thousands) Number of RTUs Number of PTUs --------------------------------------------------------------------- Balance, beginning of year 756 959 Granted 703 635 Vested (355) (261) Forfeited (52) (28) --------------------------------------------------------------------- Balance, end of year 1,052 1,305 --------------------------------------------------------------------- --------------------------------------------------------------------- The change in the net accrued long-term incentive compensation liability relating to the Whole Trust Unit Incentive Plan can be reconciled as follows: --------------------------------------------------------------------- December 31, December 31, 2009 2008 --------------------------------------------------------------------- Balance, beginning of year $ 31.9 $ 30.3 Change in net liabilities in the year General and administrative expense (0.1) 1.1 Operating expense 0.7 (0.1) Property, plant and equipment 0.1 0.6 --------------------------------------------------------------------- Balance, end of year(1) $ 32.6 $ 31.9 --------------------------------------------------------------------- Current portion of liability(2) 22.4 18.8 --------------------------------------------------------------------- Accrued long-term incentive compensation $ 10.9 $ 14.2 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Includes $0.7 million of recoverable amounts recorded in accounts receivable as at December 31, 2009 ($1.1 million for 2008). (2) Included in accounts payable and accrued liabilities on the Consolidated Balance Sheet. 22. COMMITMENTS AND CONTINGENCIES Following is a summary of ARC's contractual obligations and commitments as at December 31, 2009: --------------------------------------------------------------------- Payments Due by Period --------------------------------------------------------------------- 2011- 2013- There- ($ millions) 2010 2012 2014 after Total --------------------------------------------------------------------- Debt repayments(1) 34.8 571.7 107.4 132.2 846.1 Interest payments(2) 20.1 35.5 24.2 20.8 100.6 Reclamation fund contributions(3) 4.9 8.9 7.7 64.2 85.7 Purchase commitments 41.2 37.1 15.9 14.9 109.1 Transportation commitments(4) 4.8 26.6 24.2 7.1 62.7 Operating leases 4.0 13.0 14.9 74.4 106.3 Risk management contract premiums(5) 1.6 - - - 1.6 --------------------------------------------------------------------- Total contractual obligations 111.4 692.8 194.3 313.6 1,312.1 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Long-term and short-term debt. (2) Fixed interest payments on senior secured notes. (3) Contribution commitments to a restricted reclamation fund associated with the Redwater property. (4) Fixed payments for transporting production from the Dawson gas plant, expected to be operational in 2010. (5) Fixed premiums to be paid in future periods on certain commodity risk management contracts. In addition to the above Risk management contract premiums, ARC has commitments related to its risk management program (see Note 13). As the premiums are part of the underlying risk management contract, they have been recorded at fair market value at December 31, 2009 on the balance sheet as part of risk management contracts. ARC enters into commitments for capital expenditures in advance of the expenditures being made. At a given point in time, it is estimated that ARC has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the expenditures in a future period. ARC's 2010 capital budget has been approved by the Board at $610 million. This commitment has not been disclosed in the commitment table as it is of a routine nature and is part of normal course of operations for active oil and gas companies and trusts. The 2010 capital budget of $610 million includes approximately $20 million for leasehold development costs related to ARC's new office space in downtown Calgary. The operating lease commitments for the new space are included in the table above. ARC is involved in litigation and claims arising in the normal course of operations. Management is of the opinion that pending litigation will not have a material adverse impact on ARC's financial position or results of operations and therefore the above table does not include any commitments for outstanding litigation and claims. 23. SUBSEQUENT EVENTS On January 5, 2010 ARC issued 13 million trust units at a price of $19.40 per trust unit for total net proceeds of approximately $240 million. A portion of the net proceeds has been used to repay bank indebtedness of approximately $180 million which was incurred to fund the Ante Creek purchase outlined in Note 4, with the remainder used to repay other outstanding bank indebtedness. 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. &gt;&gt; </pre> <p>FORWARD-LOOKING INFORMATION AND STATEMENTS </p> <p>This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the volumes and estimated value of ARC's oil and gas reserves; the life of ARC's reserves; the volume and product mix of ARC's oil and gas production; future oil and natural gas prices and ARC's commodity risk management programs; the amount of future asset retirement obligations; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; future development, exploration, acquisition and development activities (including drilling plans) and related capital expenditures, future tax treatment of income trusts and future taxes payable by ARC; and ARC's tax pools. </p> <p>The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserve and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its planned expenditures; ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. </p> <p>The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this news release and in ARC's Annual Information Form). </p> <p>The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws. </p> <p>ARC Energy Trust is one of Canada's largest conventional oil and gas royalty trusts with a current enterprise value of approximately $6 billion. The Trust currently has an interest in oil and gas production of approximately 65,000 barrels of oil equivalent per day from seven core areas in western Canada. ARC Energy Trust trades on the TSX under the symbol AET.UN and its Exchangeable Shares trade under the symbol ARX. </p> <pre> &lt;&lt; ARC RESOURCES LTD. John P. Dielwart, Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00015954E %CIK: 0001029509 </p> <p>SOURCE: ARC Energy Trust </p> <p>SOURCE: ARC Resources Ltd. </p> <pre>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, www.arcenergytrust.com </pre>09/02/2010 6:52:55 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1385775http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1385774CALGARY, Feb. 9, 2010 (Canada NewsWire via COMTEX) -- (AET.UN and ARX - TSX) ARC Energy Trust ("ARC") released today its 2009 year-end reserves information. <pre> &lt;&lt; HIGHLIGHTS - Proved reserves increased by 11 per cent to 270 mmboe and proved plus probable reserves increased by 18 per cent to 379 mmboe, compared to year-end 2008 levels. On a per-unit basis at year-end 2009, proved reserves increased by two per cent and proved plus probable reserves increased by eight per cent relative to year-end 2008. - ARC replaced 347 per cent of annual production at an all-in annual Finding, Development and Acquisition ("FD&amp;A") cost of $6.44 per barrel of oil equivalent ("boe") before consideration of future development capital ("FDC") for the proved plus probable reserves category. This is the third consecutive year of reducing FD&amp;A costs and brings our three year average FD&amp;A prior to FDC down to $9.57 per boe. FD&amp;A costs including FDC were $11.57 per boe, a 32 per cent reduction from the $17 per boe achieved in 2008. - ARC has realized its lowest proved plus probable F&amp;D cost in a decade of $5.45 per boe prior to FDC. - Net acquisition spending was $158 million resulting in a net acquisition cost of $10.97 per boe for the proved plus probable category and $19.87 per boe for the total proved category, prior to FDC. - These reserves additions result in a one year recycle ratio of 3.8 times, using our $6.44 per boe proved plus probable FD&amp;A cost prior to FDC, and 2.6 times using our $9.57 per boe three year average FD&amp;A, based on the 2009 operating netback of $24.72 per boe. - Total proved plus probable reserves for the Upper Montney in the Dawson and West Montney areas have increased to 784 Bcf, a 73 per cent increase over year-end 2008 and a 333 per cent increase from year-end 2007. - The proved plus probable reserve life index ("RLI") increased to 14.5 years with the proved RLI remaining effectively unchanged at 10.3 years based on the mid-point 2010 production guidance of 71,500 boe per day. &gt;&gt; </pre> <p>RESERVES </p> <p>Reserves included herein are stated on a company interest basis (before royalty burdens and including royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument ("NI") 51-101. This news release contains several cautionary statements that are specifically required by NI 51-101 under the heading "Resources and Operational Information". In addition to the detailed information disclosed in this news release more detailed information on a company gross basis (working interest before deduction of royalties without including any royalty interests) will be included in ARC's Annual Information Form ("AIF"). Numbers presented may not add due to rounding. </p> <p>Based on an independent reserves evaluation conducted by GLJ Petroleum Consultants Ltd. ("GLJ") effective December 31, 2009 and prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGEH") and NI 51-101, ARC had proved plus probable reserves of 379 mmboe. Reserve additions from exploration and development activities (including revisions) were 66 mmboe while 14 mmboe were added through acquisitions (net of minor dispositions), bringing the total additions to 80 mmboe. The 66 mmboe addition through development activities represents 285 per cent of the 23 mmboe produced during 2009 and the total 80 mmboe represents 347 per cent of the 23 mmboe produced during 2009. As a result, year-end 2009 reserves are 18 per cent higher than the 322 mmboe of proved plus probable reserves recorded at year-end 2008. Proved developed producing reserves represent 69 per cent of total proved reserves and 49 per cent of proved plus probable reserves; total proved reserves account for 71 per cent of proved plus probable reserves. Approximately 40 per cent of ARC's proved plus probable reserves are crude oil and natural gas liquids and 60 per cent are natural gas on a 6:1 boe conversion basis. </p> <pre> &lt;&lt; RESERVES SUMMARY Using GLJ January 1, 2010 Forecast Prices and Costs ------------------------------------------------------------------------- Company Interest (Gross + Royalties Receivable) Oil Oil Light and Heavy Total Total Equi- Equi- Medium Crude Crude Natural valent valent Crude Oil Oil Oil NGLs Gas 2009 2008 (mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe) ------------------------------------------------------------------------- Proved Producing 93,137 2,353 95,490 8,443 490.1 185,623 180,777 Proved Developed Non- Producing 1,113 13 1,126 420 37.9 7,863 7,794 Proved Undeveloped 8,667 0 8,667 2,636 388.5 76,048 54,719 Total Proved 102,917 2,366 105,284 11,500 916.5 269,535 243,292 Proved plus Probable 134,570 3,027 137,598 15,815 1,353.2 378,953 321,723 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Company Gross Oil Oil Light and Heavy Total Total Equi- Equi- Medium Crude Crude Natural valent valent Crude Oil Oil Oil NGLs Gas 2009 2008 (mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe) ------------------------------------------------------------------------- Proved Producing 92,989 2,199 95,187 8,299 481.1 183,663 178,659 Proved Developed Non- Producing 1,112 13 1,125 420 37.9 7,862 7,793 Proved Undeveloped 8,655 0 8,655 2,636 388.4 76,018 54,700 Total Proved 102,756 2,212 104,968 11,355 907.3 267,543 241,154 Proved plus Probable 134,363 2,834 137,197 15,637 1,342.3 376,543 319,114 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net Interest Oil Oil Light and Heavy Total Total Equi- Equi- Medium Crude Crude Natural valent valent Crude Oil Oil Oil NGLs Gas 2009 2008 (mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe) ------------------------------------------------------------------------- Proved Producing 79,083 2,157 81,239 5,857 419.2 156,959 152,789 Proved Developed Non- Producing 921 12 933 297 29.8 6,194 5,604 Proved Undeveloped 7,151 0 7,151 2,062 319.9 62,525 41,350 Total Proved 87,154 2,168 89,322 8,216 768.8 225,678 199,742 Proved plus Probable 112,919 2,745 115,664 11,399 1,123.7 314,350 262,928 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RESERVES RECONCILIATION Company Interest (Company Gross + Royalties Receivable) Light and Heavy Total Total Oil Medium Crude Crude Natural Equiv- Crude Oil Oil Oil NGLs Gas alent (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mboe) ------------------------------------------------------------------------- PROVED PRODUCING Opening Balance 94,922 2,552 97,474 8,692 447,665 180,777 Exploration Discoveries 0 0 0 0 0 0 Drilling Extensions 501 0 501 128 32,136 5,985 Improved Recovery 3,871 7 3,878 192 8,678 5,516 Infill Drilling 1,433 12 1,445 301 52,041 10,419 Technical Revisions 1,775 120 1,895 203 9,271 3,643 Acquisitions 615 0 615 294 14,522 3,330 Dispositions -241 0 -241 -1 -90 -257 Economic Factors -71 36 -35 -20 -3,258 -598 Production -9,667 -374 -10,041 -1,346 -70,824 -23,191 Closing Balance 93,137 2,353 95,490 8,443 490,140 185,623 ------------------------------------------------------------------------- TOTAL PROVED Opening Balance 105,031 2,561 107,592 11,214 746,914 243,292 Exploration Discoveries 11 0 11 3 1,267 225 Drilling Extensions 450 0 450 371 110,976 19,317 Improved Recovery 1,897 16 1,913 14 807 2,061 Infill drilling 1,962 12 1,974 456 61,394 12,662 Technical Revisions 2,176 116 2,292 202 31,824 7,797 Acquisitions 1,369 0 1,369 606 37,535 8,231 Dispositions -241 0 -241 -1 -90 -257 Economic Factors -70 35 -35 -20 -3,294 -602 Production -9,667 -374 -10,041 -1,346 -70,824 -23,191 Closing Balance 102,918 2,366 105,284 11,500 916,509 269,535 ------------------------------------------------------------------------- PROBABLE Opening Balance 30,168 682 30,850 3,364 265,302 78,431 Exploration Discoveries 4 0 4 1 435 77 Drilling Extensions 571 0 571 218 109,540 19,046 Improved Recovery 371 2 373 5 89 393 Infill Drilling 442 2 444 294 33,252 6,280 Technical Revisions -1,516 -36 -1,552 4 3,148 -1,021 Acquisitions 1,843 0 1,843 440 26,205 6,650 Dispositions -183 0 -183 0 -24 -186 Economic Factors -46 10 -36 -11 -1,210 -251 Production 0 0 0 0 0 0 Closing Balance 31,653 661 32,314 4,315 436,736 109,419 ------------------------------------------------------------------------- PROVED PLUS PROBABLE Opening Balance 135,199 3,243 138,442 14,578 1,012,216 321,723 Exploration Discoveries 15 0 15 4 1,702 302 Drilling Extensions 1,021 0 1,021 589 220,516 38,363 Improved Recovery 2,268 18 2,286 19 896 2,454 Infill Drilling 2,404 14 2,418 750 94,646 18,942 Technical Revisions 660 80 740 206 34,972 6,776 Acquisitions 3,212 0 3,212 1,046 63,740 14,881 Dispositions -424 0 -424 -1 -114 -443 Economic Factors -116 45 -71 -31 -4,504 -853 Production -9,667 -374 -10,041 -1,346 -70,824 -23,191 Closing Balance 134,571 3,027 137,598 15,815 1,353,245 378,954 ------------------------------------------------------------------------- &gt;&gt; </pre> <p>Additional reserves reconciliation information on a Company Gross basis is included at the end of this news release. </p> <p>RESERVE LIFE INDEX ("RLI") </p> <p>ARC's proved plus probable RLI was 14.5 years at year-end 2009 while the proved RLI was 10.3 years based upon the GLJ reserves and ARC's 2010 production guidance mid-point of 71,500 boe per day. The following table summarizes ARC's historical RLI. </p> <pre> &lt;&lt; Reserve Life Index 2009 2008 2007 2006 2005 2004 ------------------------------------------------------------------------- Total Proved 10.3 10.4 9.8 9.8 10.3 9.7 Proved Plus Probable 14.5 13.8 12.5 12.4 12.9 12.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>NET PRESENT VALUE ("NPV") SUMMARY </p> <p>ARC's crude oil, natural gas and natural gas liquids reserves were evaluated using GLJ's product price forecasts effective January 1, 2010 prior to provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the NPV estimated by GLJ represent the fair market value of the reserves. </p> <pre> &lt;&lt; NPV of Cash Flow Before Income Taxes Using GLJ January 1, 2010 Forecast Prices and Costs NI 51-101 Net Discounted Discounted Discounted Discounted interest Undiscounted at 5% at 10% at 15% at 20% $MM $MM $MM $MM $MM ------------------------------------------------------------------------- Proved Producing 7,164 4,755 3,618 2,956 2,520 Proved Developed Non-Producing 230 157 119 96 80 Proved Undeveloped 1,889 1,219 847 615 458 Total Proved 9,283 6,130 4,584 3,666 3,058 Probable 4,285 2,072 1,222 806 569 Proved plus Probable 13,568 8,202 5,805 4,472 3,627 ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>At a 10 per cent discount factor, the proved producing reserves make up 62 per cent of the proved plus probable value while total proved reserves account for 79 per cent of the proved plus probable value. </p> <p>The following table provides an estimate of the NPV of Cash Flow on an after tax basis assuming that ARC would be subject to the equivalent of corporate income tax on its income beginning in 2011. It should be noted that this estimate does not take into account any corporate tax deductions such as interest and general and administrative expenses or for any tax pools generated by capital expenditures beyond what exists in the GLJ forecast. Details of ARC's tax pools at year-end 2009 are presented in the MD&amp;A section of the year-end financial results news release dated February 9, 2010. </p> <pre> &lt;&lt; NPV of Cash Flow After Income Taxes Using GLJ January 1, 2010 Forecast Prices and Costs NI 51-101 Net Discounted Discounted Discounted Discounted interest Undiscounted at 5% at 10% at 15% at 20% $MM $MM $MM $MM $MM ------------------------------------------------------------------------- Proved Producing 6,023 4,095 3,173 2,629 2,267 Proved Developed Non-Producing 177 121 92 74 62 Proved Undeveloped 1,416 891 598 415 291 Total Proved 7,616 5,107 3,863 3,118 2,621 Probable 3,220 1,548 903 588 409 Proved plus Probable 10,836 6,655 4,766 3,706 3,030 ------------------------------------------------------------------------- ------------------------------------------------------------------------- GLJ January 1, 2010 Price Forecast ------------------------------------------------------------------------- West Texas Edmonton Natural Intermediate Light Gas at Foreign Crude Oil Crude Oil AECO Exchange Year ($US/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($US/$Cdn) ------------------------------------------------------------------------- 2010 80.00 83.26 5.96 0.95 2011 83.00 86.42 6.79 0.95 2012 86.00 89.58 6.89 0.95 2013 89.00 92.74 6.95 0.95 2014 92.00 95.90 7.05 0.95 2015 93.84 97.84 7.16 0.95 2016 95.72 99.81 7.42 0.95 2017 97.64 101.83 7.95 0.95 2018 99.59 103.88 8.52 0.95 2019 101.58 105.98 8.69 0.95 Escalate thereafter at +2.0%/yr +2.0%/yr +2.0%/yr ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>NET ASSET VALUE </p> <p>The following net asset value ("NAV") table shows what is normally referred to as a "produce-out" NAV calculation under which the current value of the Trust's reserves would be produced at forecast future prices and costs and do not necessarily represent a "going concern" value of the Trust. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the net present values estimated by GLJ represent the fair market value of the reserves. </p> <pre> &lt;&lt; NAV at December 31, 2009(a) ------------------------------------------------------------------------- 2009 NAV 2008 NAV GLJ Price GLJ Price Forecast Forecast $Millions, except per unit amounts (2010-01) (2009-01) ------------------------------------------------------------------------- Value of NI 51-101 Net interest Proved Plus Probable Reserves discounted at 10% (Before Tax)(b) $5,805 $5,292 Undeveloped Lands(c) $359 $428 Working Capital Deficit(d) $(56) $(60) Reclamation Fund $33 $28 Risk Management Contracts(e) $(15) $1 Long-term Debt $(846) $(902) Asset Retirement Obligation(f) $(27) $(57) ------------------------------------------------------------------------- Net Asset Value $5,253 $4,732 Units Outstanding (000's)(g) 238,984 219,182 ------------------------------------------------------------------------- NAV/Unit $21.98 $21.59 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (a) Financial information is per ARC's 2009 Consolidated Financial Statements. (b) Excludes future income taxes estimated at $1 billion for the GLJ price forecast using a 10% discount rate and after deducting ARC's accumulated federal tax pools of $2.1 billion and $0.1 billion of provincial pools as at Dec 31, 2009 and the pools associated with the future development capital. The estimated future taxes were calculated assuming ARC would be subject to the equivalent of corporate income tax on its income beginning in 2011. Estimated future taxes do not take into account any corporate tax deductions such as interest or general and administrative expenses. (c) Internal estimate taking into account the December 31, 2009 Seaton- Jordan and Associates Ltd. evaluation. (d) Working capital deficit excludes risk management contracts and future income tax asset. (e) Risk management contracts represent the fair market value of such contracts as at December 31, 2009 based on the GLJ future pricing used to arrive at the value of Proved plus Probable reserves. This amount differs from the value of risk management contracts in the 2009 Consolidated Financial Statements due to differing future pricing assumptions. (f) The Asset Retirement Obligation ("ARO") is calculated based on the same methodology that was used to calculate the ARO on ARC's year-end financial statements, with the exception that future expected ARO costs were discounted at 10 per cent. The total discounted ARO at 10 per cent of $75 million was reduced by $48 million, relating to well abandonment costs, which were incorporated in the Value of the Proved Plus Probable reserves discounted at 10 per cent pursuant to the escalated price case as per NI 51-101. (g) Represents total trust units outstanding and trust units issuable for exchangeable shares as at December 31, 2009. &gt;&gt; </pre> <p>In the absence of adding reserves to the Trust, the NAV per unit will decline as the reserves are produced out. The evaluation includes future capital expenditure expectations required to bring undeveloped reserves on production. ARC works continuously to add value, improve profitability and increase reserves, which enhances the Trust's NAV. </p> <p>At inception of the Trust on July 16, 1996, the NAV was determined to be $11.42 per unit based on a 10 per cent discount rate; since that time, including the January 2010 distribution, the Trust has distributed $25.08 per unit. After having distributed more cash than the initial NAV, the NAV as at December 31, 2009 was $21.98 per unit using GLJ prices. As a result of ARC's development activities, the NAV per unit using GLJ prices increased $0.39 per unit during 2009 after distributing $1.28 per unit to unitholders. Following is a summary of historical NAVs calculated at each of the Trust's year-ends utilizing the then current GLJ price forecasts and other assumptions and values utilized at such times. </p> <pre> &lt;&lt; Historical NAV - Discounted at 10 Per Cent ------------------------------------------------------------------------- $Millions, except per unit amounts 2009 2008 2007 2006 2005 2004 ------------------------------------------------------------------------- Value of NI 51-101 Net interest Proved plus Probable reserves $5,805 $5,292 $4,651 $4,056 $3,891 $2,389 Undeveloped lands 359 428 229 109 59 48 Reclamation fund 33 28 26 31 23 21 Risk Management Contracts (15) 1 (36) (9) (2) (12) Long term-debt, net of working capital (902) (962) (753) (739) (578) (265) Asset retirement obligation (27) (57) (26) (62) (35) (23) ------------------------------------------------------------------------- Net asset value $5,253 $4,732 $4,091 $3,386 $3,358 $2,158 Units outstanding (000's) 238,984 219,182 213,179 207,173 202,039 188,804 ------------------------------------------------------------------------- NAV per unit $21.98 $21.59 $19.19 $16.34 $16.62 $11.43 ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>FINDING, DEVELOPMENT AND ACQUISITION ("FD&amp;A") COSTS </p> <p>Under NI 51-101, the methodology to be used to calculate FD&amp;A costs includes incorporating changes in future development capital ("FDC") required to bring the proved undeveloped and probable reserves to production. For continuity, ARC has presented herein FD&amp;A costs calculated both excluding and including FDC. </p> <p>The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. </p> <p>FINDING AND DEVELOPMENT COSTS ("F&amp;D") </p> <p>During 2009 ARC spent $360 million on exploration, development and corporate activities and participated in 218 gross (132 net) wells. On ARC's operated lands, we drilled 146 gross (120 net) wells with a 99.3 per cent success rate. Positive results from the capital program and continued strong production results at Dawson resulted in ARC adding 66 mmboe of proved plus probable reserves in 2009 prior to acquisitions. This represents a 285 per cent replacement of 2009 production of 23 mmboe prior to acquisitions and dispositions. This is the second year in a row that ARC has been able to replace greater than 200 per cent of production from drilling and development activities. Excluding changes in future development capital ARC's F&amp;D costs were $5.45/boe for proved plus probable reserves and $8.67/boe for total proved reserves. </p> <p>ARC's 2009 capital program was focused on resource play development with the Montney in northeastern British Columbia accounting for 53 per cent of the spending. At Dawson, record average production of 52 mmcf per day of gas and 230 bbl per day of liquids was achieved in 2009. A total of 22 horizontal wells were drilled and significant progress was made towards the completion of the 60 mmcf per day Dawson Phase One gas plant, which is currently expected to be onstream early in May of 2010. Only eight of the 22 wells drilled in 2009 were on production at year-end, with the remaining 14 horizontal wells ready to be brought on production with the completion of the gas plant. The 2010 capital budget calls for the drilling of three step out vertical wells along with the drilling of 30 Montney horizontal wells and the substantial completion of an additional Phase Two 60 mmcf per day gas plant at Dawson. ARC will also be testing the Lower Montney zone that has proven to be productive elsewhere. </p> <p>In the West Montney assets, ARC participated in a partner operated four well Montney horizontal drilling program at Sunrise, drilled one vertical well at Sunset and one in Sundown in 2009. The four Sunrise horizontal wells have recently been brought on production and are expected to average 10 mmcf per day net to ARC's 50 per cent interest in the first quarter of 2010. ARC's 2010 drilling plans in the West Montney include the drilling of nine gross horizontal wells with a portion of funds specifically targeted towards the assessment of the Lower Montney zone. Spending will also be devoted to the initial procurement of equipment for a new Sunrise gas plant, currently planned for early 2012. </p> <p>In Ante Creek, ARC drilled four horizontal Montney wells targeting a mixture of oil and gas production. With the success of these wells and a late year acquisition of approximately 1,000 boe per day, ARC was able to grow Ante Creek production to a record 7,000 boe per day at year-end 2009. ARC has allocated $70 million of capital to this field for 2010 and expects to drill 14 horizontal and two vertical wells. With the expansion of ARC's liquid handling facilities, the upgrade of a third party operated gas plant and further successful drilling, ARC expects production to grow to approximately 8,500 boe per day by early 2011. </p> <p>At Redwater, ARC drilled three horizontal wells, only two of which were on production prior to year-end. Carbon dioxide injection into the enhanced oil recovery ("EOR") pilot area continued successfully through the end of 2009 with plans to continue optimization and evaluation of the pilot into 2010. </p> <p>The Pembina area development included nine successful Cardium drills, including four horizontal wells coming on at stable one month production rates averaging over 150 boe per day per well. The 2010 capital budget will build on 2009 success with 17 more planned horizontal Cardium wells. </p> <p>In the central Alberta area, ARC continued to develop the Natural Gas from Coal prospects with the drilling of 38 more wells. The other key strategic investment in 2009 was the drilling of two horizontal Cardium wells in the Garrington area, which should be on production in early 2010. </p> <p>In ARC's shallow gas regions in southeastern Alberta and southwestern Saskatchewan there were 44 shallow gas wells drilled with 23 of them coming on production before year-end. </p> <p>ARC experienced significant drilling success in southeast Saskatchewan and Manitoba with 15 new horizontal oil wells. Some of the key areas that will receive continued development focus into 2010 are Elmore, Lougheed, Midale, Weyburn and Goodlands. </p> <p>MONTNEY UPDATE </p> <p>The Dawson gas field was the center piece of the Star Oil and Gas purchase made by ARC in April of 2003, at that time production was approximately 17 mmcf per day and the proved plus probable reserves were just 110 Bcf. Since then ARC has added to its land base in the area, drilled 77 vertical wells and 41 horizontal wells and increased production to 55 mmcf per day. As a result of the development activities, advances in technology and knowledge gained through the longer production history, proved plus probable reserves have increased to 593 Bcf. See "Information Regarding Disclosure on Oil and Gas Resources and Operational Information". The majority of the reserve additions have come in the past two years - 254 Bcf were added in 2008 and a further 205 Bcf were added in 2009, as successful development with horizontal wells lead to the implementation of a major development project at Dawson. Despite this success, ARC still believes that there are significant volumes of gas that can be added to reserves in the future assuming continued successful development of the field. </p> <p>This discussion on the Montney resource at Dawson and West Montney is subject to a number of cautionary statements, assumptions and risks, some of which are included below and others under "Information Regarding Disclosure on Oil and Gas Resources and Operational Information". </p> <p>DAWSON </p> <p>ARC has 105 net sections of land at Dawson on which GLJ have assigned a best estimate of 3.4 Tcf of gas identified as Discovered Petroleum Initially In Place ("DPIIP") net to ARC in the Upper Montney as at December 31, 2009. ARC has booked 78 proved drilling locations and 35 probable locations on the 58 net sections of land to which reserves have been assigned. The assigned reserves of 0.6 Tcf and cumulative production of 0.1 Tcf represent 30 per cent of the 2.3 Tcf of DPIIP associated with the 58 sections and 20 per cent of the total DPIIP of 3.4 Tcf. Assigned reserves and cumulative production on the 58 sections range from three per cent to greater than 50 per cent of the DPIIP for such sections, dependent upon drilling density, production history and certain reservoir factors. There are currently no reserves assigned to the remaining 47 sections. It is management's belief that with drilling success on the undeveloped acreage consistent with historical success, further development and completion refinements and changing economic circumstances, that ARC will recognize significant additional reserves over time. See "Information Regarding Disclosure on Oil and Gas Resources and Operational Information" and "Forwarding Looking Statements". </p> <p>WEST MONTNEY </p> <p>In the West Montney area, the Upper Montney section thickens and a second porous and permeable zone referred to as the Montney B is present. To date, all of the production has come from the Montney A. While gas has been tested from the Montney B by ARC, current development plans are focused on the Montney A. There is a deeper zone, referred to as the Lower Montney that also has shown development potential in the region, but DPIIP has not been evaluated in the Lower Montney zone due to insufficient data on ARC lands. </p> <pre> &lt;&lt; Sunrise/Sunset Area (Sunrise) ------------------------------ &gt;&gt; </pre> <p>In the greater Sunrise / Sunset area ARC has 32 net sections of land on which GLJ have assigned a best estimate of 2.9 Tcf of gas classified as DPIIP net to ARC as at December 31, 2009, with 1.3 Tcf in the Montney A and 1.6 Tcf in the Montney B. GLJ has booked 24.5 net proved undeveloped locations and 24.5 net probable locations on the 16 net sections of land to which Montney A reserves have been assigned. These reserves represent 26 per cent of the 0.7 Tcf of DPIIP associated with the Montney A in the 16 booked sections and seven per cent of the total A and B DPIIP of 2.9 Tcf. It is management's belief that with drilling success on the undeveloped acreage consistent with historical success, further development and completion refinements and changing economic circumstances, that ARC will recognize significant additional reserves over time. ARC will be drilling and completing several wells into other Montney intervals in 2010 to gain a better understanding of the production potential of these zones. </p> <pre> &lt;&lt; Saturn/Monias (Septimus) and Sundown ------------------------------------- &gt;&gt; </pre> <p>ARC also owns 19 net sections of land in the Septimus area and 18 net sections of land in the Sundown area on which GLJ have assigned a best estimate of 2.1 Tcf of gas currently classified as DPIIP net to ARC in the Upper Montney. Approximately 60 per cent of the DPIIP are attributed to the Septimus area where considerable industry activity is taking place. A very small amount of reserves have been assigned at Septimus, with no reserves currently assigned to the Sundown property. Additional drilling will be required to explore and delineate these properties before it will be possible to define the timing of potential development projects. </p> <p>All estimates of DPIIP of GLJ are as at December 31, 2009. A recovery project has not been defined for the volumes of DPIIP, which are not classified as reserves. At this time, there is no certainty that it will be technically feasible or commercially viable to produce any of the resources. </p> <p>ARC's belief that it will recognize significant additional reserves in Dawson and the West Montney assets is based on a combination of historic recoveries of the more fully developed Montney acreage, abundant well log and production test data, and the application of drilling densities of ARC and third parties in the area and assume continuous development through multi-year exploration and development programs, changing economic circumstances and further development and completion refinements. The principal risks of not achieving the reserve additions relate to the potential for variations in the quality of the Montney formation where no current well data exists, access to capital, low gas prices that would impact the economics of development, and the future performance of wells. Unless otherwise indicated, all reserves are proved plus probable. </p> <p>See "Information Regarding Disclosure on Oil and Gas Resources and Operational Information" for additional cautionary language, explanations and discussion and "Forward Looking Statements" for a statement of principal assumptions and risks that may apply. </p> <p>ACQUISITIONS AND DISPOSITIONS </p> <p>In 2009, ARC spent $158 million on acquisitions net of dispositions. The two primary transactions were the purchase of assets in the Ante Creek Area of Alberta for $178 million and the disposition of scattered Bakken assets in southeast Saskatchewan for $34 million. A net total of 14 mmboe of proved plus probable and 8 mmboe of total proved reserves were added from these activities. The net acquisition costs for the 2009 transactions were $10.97 per boe for proved plus probable reserves and $19.87 per boe for total proved reserves prior to including FDC. Including FDC the net acquisition costs were $16.25 per boe proved plus probable and $24.67 per proved boe. </p> <p>FINDING DEVELOPMENT AND ACQUISITION COSTS ("FD&amp;A") </p> <p>Incorporating the net acquisitions during the year, ARC's proved plus probable FD&amp;A costs excluding FDC were $6.44 per boe while proved FD&amp;A costs excluding FDC were $10.48 per boe. These results represent the third year in a row that ARC has reduced the cost of adding reserves. The three year average costs have dropped to $9.57 per boe for proved plus probable reserves and $13.76 per boe for total proved excluding FDC. </p> <p>FUTURE DEVELOPMENT CAPITAL ("FDC") </p> <p>NI 51-101 requires that FD&amp;A costs be calculated including changes in FDC. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the independent evaluator's best estimate of what it will cost to bring the proved undeveloped and probable reserves on production. The increased level of undeveloped reserves now booked in the Montney acreage has yielded an increased capital cost expectation in the 2009 evaluation. </p> <pre> &lt;&lt; FD&amp;A Costs - Company Interest Reserves Proved plus Proved Probable ------------------------------------------------------------------------- FD&amp;A Costs Excluding Future Development Capital ----------------------------------------------- Exploration and Development Capital Expenditures - $thousands $359,561 $359,561 Exploration and Development Reserve Additions including Revisions - mboe 41,460 65,984 Finding and Development Cost - $/boe $8.67 $5.45 Three Year Average F&amp;D Cost - $/boe $12.58 $8.91 Net Acquisition Capital - $thousands $158,440 $158,440 Net Acquisition Reserve Additions - mboe 7,975 14,438 Net Acquisition Cost - $/boe $19.87 $10.97 Three Year Average Net Acquisition Cost - $/boe $26.77 $15.47 Total Capital Expenditures including Net Acquisitions - $thousands $518,001 $518,001 Reserve Additions including Net Acquisitions - mboe 49,435 80,422 Finding Development and Acquisition Cost - $/boe $10.48 $6.44 Three Year Average FD&amp;A Cost - $/boe $13.76 $9.57 FD&amp;A Costs Including Future Development Capital ------------------------------------------------ Exploration and Development Capital Expenditures - $thousands $359,561 $359,561 Exploration and Development Change in FDC - $thousands $150,181 $335,803 Exploration and Development Capital including Change in FDC- $thousands $509,741 $695,364 Exploration and Development Reserve Additions including Revisions - mboe 41,460 65,984 Finding and Development Cost - $/boe $12.29 $10.54 Three Year Average F&amp;D Cost - $/boe $17.10 $14.12 Net Acquisition Capital - $thousands $158,440 $158,440 Net Acquisition FDC - $thousands $38,321 $76,236 Net Acquisition Capital including FDC - $thousands $196,761 $234,677 Net Acquisition Reserve Additions - mboe 7,975 14,438 Net Acquisition Cost - $/boe $24.67 $16.25 Three Year Average Net Acquisition Cost - $/boe $31.16 $20.34 Total Capital Expenditures including Net Acquisitions - $thousands $518,001 $518,001 Total Change in FDC - $thousands $188,501 $412,040 Total Capital Including Change in FDC - $thousands $706,502 $930,041 Reserve Additions including Net Acquisitions - mboe 49,435 80,422 Finding Development and Acquisition Cost including FDC - $/boe $14.29 $11.56 Three Year Average FD&amp;A Cost Including FDC - $/boe $18.27 $14.75 ------------------------------------------------------------------------- ------------------------------------------------------------------------- In all cases, the F&amp;D, or FD&amp;A number is calculated by dividing the identified capital expenditures by the applicable reserves additions. Historic Company Interest Proved FD&amp;A Costs ------------------------------------------------------------------------- 2009 2008 2007 2006 2005 2004 ------------------------------------------------------------------------- Annual FD&amp;A excluding FDC $10.48 $14.22 $20.37 $24.51 $15.60 $16.53 Three year average FD&amp;A excluding FDC $13.76 $18.28 $18.51 $17.77 $13.30 $11.05 ------------------------------------------------------------------------- Annual FD&amp;A including FDC $14.29 $21.87 $20.37 $27.53 $17.64 $20.46 Three year average FD&amp;A including FDC $18.27 $22.85 $20.30 $20.31 $15.45 $13.02 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Historic Company Interest Proved Plus Probable FD&amp;A Costs ------------------------------------------------------------------------- 2009 2008 2007 2006 2005 2004 ------------------------------------------------------------------------- Annual FD&amp;A excluding FDC $6.44 $10.13 $19.00 $22.41 $13.64 $13.76 Three Year Average FD&amp;A excluding FDC $9.57 $14.70 $16.57 $15.59 $11.00 $9.30 ------------------------------------------------------------------------- Annual FD&amp;A including FDC $11.56 $17.00 $20.03 $27.20 $16.09 $19.14 Three Year Average FD&amp;A including FDC $14.75 $19.84 $19.19 $18.99 $13.50 $11.65 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RESERVES RECONCILIATION Company Gross (Company Interest - Royalties Payable) Light and Heavy Total Total Oil Medium Crude Crude Natural Equiv- Crude Oil Oil Oil NGLs Gas alent (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mboe) ------------------------------------------------------------------------- PROVED PRODUCING Opening Balance 94,805 2,357 97,162 8,535 437,774 178,659 Exploration Discoveries 0 0 0 0 0 0 Drilling Extensions 500 0 500 128 32,101 5,978 Improved Recovery 3,845 7 3,852 192 8,666 5,489 Infill Drilling 1,432 12 1,444 301 52,041 10,418 Technical Revisions 1,714 121 1,835 202 8,466 3,448 Acquisitions 612 0 612 294 14,504 3,324 Dispositions -241 0 -241 -1 -90 -257 Economic Factors -70 36 -34 -19 -3,152 -579 Production -9,607 -335 -9,942 -1,333 -69,252 -22,817 Closing Balance 92,988 2,199 95,187 8,299 481,057 183,663 ------------------------------------------------------------------------- TOTAL PROVED Opening Balance 104,912 2,366 107,278 11,057 736,916 241,154 Exploration Discoveries 11 0 11 3 1,267 225 Drilling Extensions 449 0 449 371 110,941 19,310 Improved Recovery 1,862 16 1,878 14 794 2,024 Infill Drilling 1,961 12 1,973 456 61,394 12,661 Technical Revisions 2,112 117 2,229 202 31,016 7,600 Acquisitions 1,366 0 1,366 606 37,517 8,225 Dispositions -241 0 -241 -1 -90 -257 Economic Factors -69 36 -33 -19 -3,187 -583 Production -9,607 -335 -9,942 -1,333 -69,252 -22,817 Closing Balance 102,756 2,212 104,968 11,355 907,316 267,543 ------------------------------------------------------------------------- PROBABLE Opening Balance 30,137 640 30,777 3,329 263,119 77,959 Exploration Discoveries 4 0 4 1 435 77 Drilling Extensions 572 0 572 218 109,531 19,045 Improved Recovery 360 2 362 5 86 382 Infill Drilling 432 2 434 295 33,251 6,271 Technical Revisions -1,510 -31 -1,541 5 3,541 -945 Acquisitions 1,841 0 1,841 440 26,194 6,646 Dispositions -183 0 -183 0 -24 -186 Economic Factors -46 8 -38 -11 -1,192 -248 Production 0 0 0 0 0 0 Closing Balance 31,607 622 32,229 4,281 434,941 109,000 ------------------------------------------------------------------------- PROVED PLUS PROBABLE Opening Balance 135,049 3,006 138,055 14,386 1,000,035 319,113 Exploration Discoveries 15 0 15 4 1,702 302 Drilling Extensions 1,021 0 1,021 588 220,472 38,355 Improved Recovery 2,222 18 2,240 19 880 2,406 Infill Drilling 2,393 14 2,407 750 94,645 18,932 Technical Revisions 602 86 688 207 34,557 6,655 Acquisitions 3,207 0 3,207 1,046 63,711 14,871 Dispositions -424 0 -424 -1 -114 -443 Economic Factors -115 44 -71 -30 -4,379 -831 Production -9,607 -335 -9,942 -1,333 -69,252 -22,817 Closing Balance 134,363 2,834 137,197 15,637 1,342,257 376,543 ------------------------------------------------------------------------- ------------------------------------------------------------------------- FD&amp;A Costs - Company Gross Reserves Proved plus Proved Probable ------------------------------------------------------------------------- NI 51-101 Calculation Including Future Development Capital -------------------------------------------------- Capital Expenditures excluding Net Acquisitions - $thousands $359,561 $359,561 Net Change in FDC excluding Net Acquisitions - $thousands $150,181 $335,803 Total Capital including FDC - $thousands $509,741 $695,364 Reserve additions excluding Net Acquisitions - mboe 41,238 65,818 Finding and Development Cost - $/boe $12.36 $10.57 Three Year Average F&amp;D Cost - $/boe $17.18 $14.11 Capital Expenditures including net acquisitions - $thousands $518,001 $518,001 Net Change in FDC including net acquisitions - $thousands $188,501 $412,040 Total Capital - $thousands $706,502 $930,041 Reserve additions including net acquisitions - mboe 49,206 80,246 Finding Development and Acquisition Cost - $/boe $14.36 $11.59 Three Year Average FD&amp;A Cost - $/boe $18.41 $14.81 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Historic Company Gross Proved FD&amp;A Costs ------------------------------------------------------------------------- 2009 2008 2007 2006 2005 2004 2003 ------------------------------------------------------------------------- Annual FD&amp;A including FDC $14.36 $22.01 $20.71 $28.05 $17.81 $21.27 $12.95 Three year average FD&amp;A including FDC $18.41 $23.12 $20.57 $20.63 $15.74 $13.54 n/a ------------------------------------------------------------------------- ------------------------------------------------------------------------- Historic Company Gross Proved Plus Probable FD&amp;A Costs ------------------------------------------------------------------------- 2009 2008 2007 2006 2005 2004 2003 ------------------------------------------------------------------------- Annual FD&amp;A including FDC $11.59 $17.08 $20.29 $27.79 $16.24 $19.74 $10.74 Three Year Average FD&amp;A including FDC $14.81 $20.04 $19.43 $19.28 $13.73 $12.09 n/a ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES, RESOURCES AND OPERATIONAL INFORMATION </p> <p>All amounts in this news release are stated in Canadian dollars unless otherwise specified. Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. 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 wellhead. Use of BOE in isolation may be misleading. In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom) are based on "company interest reserves" using forecast prices and costs. "Company interest reserves" consist of "company gross reserves" (as defined in National Instrument 51-101 adopted by the Canadian securities regulators ("NI 51-101") plus ARC's royalty interests in reserves. "Company interest reserves" are not a measure defined in NI 51-101 and does not have a standardized meaning under NI 51-101. Accordingly, our company interest reserves may not be comparable to reserves presented or disclosed by other issuers. Our oil and gas reserves statement for the year ended December 31, 2009, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedar.com. In relation to the disclosure of estimates in the Montney Resource Discussion, such estimates for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. </p> <p>This news release contains references to estimates of gas classified as discovered petroleum initially in place in the area west of Dawson in British Columbia which are not, and should not be confused with, oil and gas reserves. "Discovered petroleum initially in place" ("DPIIP") is defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as the quantity of hydrocarbons that are estimated to be in place within a known accumulation. DPIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources and the remainder as at evaluation date is by definition unrecoverable. There is no certainty that it will be economically viable or technically feasible to produce any portion of this DPIIP. </p> <p>ARC has not categorized the resources disclosed as DPIIP into all of the subcategories of discovered resources as projects have not been defined to develop them as at the evaluation date. Such projects, in the case of the Montney resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints, ARC's policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of ARC on gas prices, the results of exploration and development activities of ARC and others in the area and possible infrastructure capacity constraints. </p> <p>ARC's belief that it will establish significant additional reserves over time in the discussion of the Montney Resource Development is a forward looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading "Forward Looking Statements". </p> <p>Additionally, the SEC prohibits disclosure of oil and gas resources, whereas Canadian issuers may disclose resource volumes. Resources are different than, and should not be construed as, reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, resources, see above. </p> <p>NOTICE TO U.S. READERS </p> <p>The oil and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects of United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the "SEC") generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves (as defined in SEC rules). Canadian securities laws require oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only proved reserves (which are defined differently from the SEC rules) but also probable reserves, each as defined in NI 51-101. Accordingly, proved reserves disclosed in this news release may not be comparable to U.S. standards, and in this news release, ARC has disclosed reserves designated as "probable reserves" and "proved plus probable reserves". Probable reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves. The SEC's guidelines strictly prohibit reserves in these categories from being included in filings with the SEC that are required to be prepared in accordance with U.S. disclosure requirements. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above, "company interest") volumes, which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments. Moreover, ARC has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. As a consequence of the foregoing, ARC's reserve estimates and production volumes in this news release may not be comparable to those made by companies utilizing United States reporting and disclosure standards. </p> <p>FORWARD-LOOKING INFORMATION AND STATEMENTS </p> <p>This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the recognition of significant additional reserves under the heading "Montney Resource Discussion", the volumes and estimated value of ARC's oil and gas reserves; the life of ARC's reserves; the volume and product mix of ARC's oil and gas production; future oil and natural gas prices and ARC's commodity risk management programs; the amount of future asset retirement obligations; future results from operations and operating metrics; and future development, exploration, acquisition and development activities (including drilling plans) and related production expectations. </p> <p>The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities consistent with past results; the continued and timely development of infrastructure in areas of new production; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserve and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its plans expenditures. There are a number of assumptions associated with the development of the lands at Dawson and the lands west of Dawson including the quality of the Montney reservoir, continued performance from existing wells, future drilling programs and performance from new wells, the growth of infrastructure, well density per section, recovery factors and development necessarily involves known and unknown risks and uncertainties, including those risks identified in this press release. ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. </p> <p>The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; the potential for variation in the quality of the Montney formation, changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; unanticipated results from ARC's exploration and development activities; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this news release and in ARC's Annual Information Form). </p> <p>The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws. </p> <p>ARC Energy Trust is one of Canada's largest conventional oil and gas royalty trusts with a current enterprise value of approximately $6 billion. The Trust currently has an interest in oil and gas production of approximately 65,000 barrels of oil equivalent per day from seven core areas in western Canada. ARC Energy Trust trades on the TSX under the symbol AET.UN. </p> <pre> &lt;&lt; ARC RESOURCES LTD. John P. Dielwart, Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00015954E %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.arcresources.com or contact: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6417, Toll Free 1-888-272-4900, Suite 2100, 440 - 2nd Avenue S.W., Calgary, AB, T2P 5E </pre>09/02/2010 6:52:55 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1385774http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1381569CALGARY, Feb. 1, 2010 (Canada NewsWire via COMTEX) -- (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 2.73316 to 2.74640. Such increase will be effective on February 15, 2010. <p>The following are the details on the calculation of the exchange ratio: </p> <pre> &lt;&lt; ------------------------------------------------------------------------- 10 day Record weighted Effective date of average date ARC ARC Energy trading of the Exchange Energy Trust price of Increase increase ratio as Trust Opening distrib- AET.UN (prior in in of distrib- exchange ution to the end exchange exchange effective ution ratio per unit of the month) ratio (xx) ratio date ------------------------------------------------------------------------- January February 29, 2010 2.73316 $0.10 $20.6402 0.01324 15, 2010 2.74640 ------------------------------------------------------------------------- (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, Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00015954E %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>01/02/2010 8:24:56 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1381569http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1381496CALGARY, Feb. 1, 2010 (Canada NewsWire via COMTEX) -- (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or "the Trust") announces its 2009 Income Tax Information to be as follows: <pre> &lt;&lt; ARC ENERGY TRUST (AET.UN) 2009 INCOME TAX INFORMATION CANADA REVENUE AGENCY (CRA) ACCOUNT NUMBER T16-4073-86 &gt;&gt; </pre> <p>The following information is intended to assist individual Canadian unitholders ("Unitholders") of the Trust in the preparation of their 2009 T1 Income Tax Return. </p> <p>THE INFORMATION CONTAINED HEREIN IS BASED ON ARC ENERGY TRUST'S UNDERSTANDING OF THE INCOME TAX ACT (CANADA) AND THE REGULATIONS THEREUNDER. UNITHOLDERS SHOULD CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THEIR PARTICULAR CIRCUMSTANCES. </p> <p>Legal Status of the Trust: </p> <p>The Trust is subject to Canadian income tax on a similar basis to that of an individual. The Trust has a December 31 year-end and each year the Trust performs an income tax calculation and allocates its taxable income to unitholders. </p> <p>Taxation of Cash Distributions: </p> <pre> &lt;&lt; Trust Units held within an RRSP, RPP, RRIF, RESP, DPSP or TFSA -------------------------------------------------------------- &gt;&gt; </pre> <p>No amounts are to be reported for income tax purposes in respect of cash distributions received by a Registered Retirement Savings Plan ("RRSP"), Registered Pension Plan ("RPP"), Registered Retirement Income Fund ("RRIF"), Registered Education Savings Plan ("RESP"), Deferred Profit Sharing Plan ("DPSP") or Tax Free Savings Account or any other such registered plans (collectively referred to as "Deferred Plans"). </p> <pre> &lt;&lt; Trust Units held outside of a Deferred Plan ------------------------------------------- &gt;&gt; </pre> <p>For cash distributions received by a Canadian resident individual outside of a Deferred Plan, 97% of the payments are taxable as income, with the remaining 3% being a tax deferred return of capital. The following table outlines the breakdown of cash distributions per unit paid or payable by the Trust with respect to record dates for the period January 30, 2009 to December 31, 2009 for Canadian Income Tax purposes. </p> <pre> &lt;&lt; ------------------------------------------------------------------------- Tax Taxable Deferred Amount Amount Total (Box 26 (Box 42 Cash Other Return of Distri- Record Date Payment Date Income) Capital) bution ------------------------------------------------------------------------- January 30, 2009 February 16, 2009 $0.1164 $0.0036 $0.12 ------------------------------------------------------------------------- February 27, 2009 March 16, 2009 $0.1164 $0.0036 $0.12 ------------------------------------------------------------------------- March 31, 2009 April 15, 2009 $0.1164 $0.0036 $0.12 ------------------------------------------------------------------------- April 30, 2009 May 15, 2009 $0.1164 $0.0036 $0.12 ------------------------------------------------------------------------- May 29, 2009 June 15, 2009 $0.0970 $0.0030 $0.10 ------------------------------------------------------------------------- June 30, 2009 July 15, 2009 $0.0970 $0.0030 $0.10 ------------------------------------------------------------------------- July 31, 2009 August 17, 2009 $0.0970 $0.0030 $0.10 ------------------------------------------------------------------------- August 31, 2009 September 15, 2009 $0.0970 $0.0030 $0.10 ------------------------------------------------------------------------- September 30, 2009 October 15, 2009 $0.0970 $0.0030 $0.10 ------------------------------------------------------------------------- October 30, 2009 November 16, 2009 $0.0970 $0.0030 $0.10 ------------------------------------------------------------------------- November 30, 2009 December 15, 2009 $0.0970 $0.0030 $0.10 ------------------------------------------------------------------------- December 31, 2009 January 15, 2010 $0.0970 $0.0030 $0.10 ------------------------------------------------------------------------- Total $1.2416 $0.0384 $1.28 ------------------------------------------------------------------------- &gt;&gt; </pre> <p>Unitholders who held their Trust Units outside of a Deferred Plan, through a broker or other intermediary and received cash distributions during the period, will receive "T3 Supplementary" slips directly from their broker or intermediary, not from the transfer agent or the Trust. </p> <p>Registered Unitholders of Trust Units who received cash distributions during the period from the transfer agent, Computershare Trust Company of Canada, (and not from a broker or intermediary), will receive "T3 Supplementary" slips directly from Computershare Trust Company of Canada. While Computershare Trust Company of Canada will strive to issue these information slips as soon as possible, the deadline for mailing all T3 Supplementary Information slips as required by Canada Revenue Agency is March 31, 2010. </p> <p>Tax upon the disposition of Royalty Trust Units: </p> <p>The portion of the distributions deemed a return of capital will reduce the Unitholder's adjusted cost base ("ACB") of their units. The ACB of the units is required in the calculation of a capital gain or capital loss (assuming the units are capital property of the Unitholder) upon the disposition or deemed disposition of the Trust units. Unitholders should maintain a record of all distributions that are classified as partially or entirely as a return of capital while holding ARC Energy Trust units. For investors in the $10.00 per unit initial public offering in July 1996, the ACB of units still held as at December 31, 2009, is $3.10 per unit taking into account the return of capital of $6.86 in 1996 through to 2008 and $0.04 in 2009. </p> <pre> &lt;&lt; ARC ENERGY TRUST John P. Dielwart, Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00015954E %CIK: 0001029509 </p> <p>SOURCE: ARC Energy Trust </p> <p>SOURCE: ARC Resources Ltd. </p> <pre>For further information 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>01/02/2010 4:32:55 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1381496http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1375792CALGARY, Jan. 15, 2010 (Canada NewsWire via COMTEX) -- (AET.UN and ARX - TSX) ARC Energy Trust (the "Trust" or "ARC") announces that the cash distribution to be paid on February 15, 2010, in respect of the January 2010 production, for unitholders of record on January 29, 2010, will be $0.10 per trust unit. The ex-distribution date is January 27, 2010. <p>As at January 15, 2010 the Trust's trailing twelve-month cash distributions, including the January 15, 2010 payment, total $1.28 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 $5.7 billion. The Trust currently produces approximately 63,000 barrels of oil equivalent per day from five core areas in western Canada. 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 2009 and beyond; the sources, deployment and allocation of expected capital in 2009; 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, Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00015954E %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>15/01/2010 3:28:09 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1375792http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1370767CALGARY, Jan. 5, 2010 (Canada NewsWire via COMTEX) -- /NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES. ANY FAILURE TO COMPLY WITH THIS RESTRICTION MAY CONSTITUTE A VIOLATION OF U.S. SECURITIES LAW/ <p>(AET.UN and ARX - TSX) ARC Energy Trust (the "Trust") announced today the closing of the previously announced offering of 13 million trust units at a price of $19.40 per trust unit for total gross proceeds of approximately $252 million on a bought deal basis. The syndicate of underwriters was led by RBC Capital Markets and included: CIBC World Markets Inc., BMO Capital Markets, Scotia Capital Inc., TD Securities Inc., FirstEnergy Capital Corp., National Bank Financial Inc., Canaccord Financial Ltd., Peters &amp; Co. Limited, Macquarie Capital Markets Canada Ltd., Raymond James Ltd., Thomas Weisel Partners Canada Inc., and UBS Securities Canada Inc. </p> <p>The Trust intends to use a portion of the net proceeds of this offering to repay bank indebtedness of $180 million that was incurred to fund the purchase of assets in the Ante Creek and other areas of Northern Alberta which was completed on December 21, 2009. The remainder will be initially used to partially repay other outstanding bank indebtedness, thereby freeing up borrowing capacity to fund a portion of the Trust's future capital program. </p> <p>The securities being offered by the Trust have not been, nor will be, registered under the United States Securities Act of 1933, as amended, and may not be offered or sold in the United States or to U.S. persons absent registration or applicable exemption from the registration requirement of such Act. This release does not constitute an offer for sale of trust units in the U.S. and any public offering of trust units in the U.S. will be made by means of a prospectus. </p> <p>ARC ENERGY TRUST </p> <p>John P. Dielwart, </p> <p>Chief Executive Officer </p> <p>%SEDAR: 00015954E %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>05/01/2010 9:12:18 AMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1370767http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1370467CALGARY, Jan. 4, 2010 (Canada NewsWire via COMTEX) -- (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 2.71953 to 2.73316. Such increase will be effective on January 15, 2010. <p>The following are the details on the calculation of the exchange ratio: </p> <pre> &lt;&lt; ------------------------------------------------------------------------- 10 day Record weighted Effective date of average date ARC ARC Energy trading of the Exchange Energy Trust price of Increase increase ratio as Trust Opening distrib- AET.UN (prior in in of distrib- exchange ution to the end exchange exchange effective ution ratio per unit of the month) ratio(xx) ratio date ------------------------------------------------------------------------- December January 31, 2009 2.71953 $0.10 $19.9573 0.01363 15, 2010 2.73316 ------------------------------------------------------------------------- (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, Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00015954E %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>04/01/2010 4:30:38 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1370467http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1369326CALGARY, Dec. 23, 2009 (Canada NewsWire via COMTEX) -- /NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES. ANY FAILURE TO COMPLY WITH THIS RESTRICTION MAY CONSTITUTE A VIOLATION OF U.S. SECURITIES LAW/ <p>(AET.UN and ARX - TSX) ARC Energy Trust (the "Trust") announced the filing of a final short form prospectus in all provinces of Canada relating to the previously announced offering of 13 million trust units at a price of $19.40 per trust unit for total gross proceeds of approximately $252 million. The offering is being made through a syndicate of underwriters led by RBC Capital Markets and includes: CIBC World Markets Inc., BMO Capital Markets, Scotia Capital Inc., TD Securities Inc., FirstEnergy Capital Corp., National Bank Financial Inc., Canaccord Financial Ltd., Peters &amp; Co. Limited, Macquarie Capital Markets Canada Ltd., Raymond James Ltd., Thomas Weisel Partners LLC, and UBS Securities Canada Inc. The Trust intends to use a portion of the net proceeds of this offering to repay bank indebtedness of $180 million which was incurred to fund the purchase of assets in the Ante Creek and other areas of Northern Alberta which was announced on December 14, 2009 and completed on December 21, 2009 and the remainder will be initially used to partially repay other outstanding bank indebtedness, thereby freeing up borrowing capacity to fund a portion of the Trust's future capital program. Closing of the financing is expected to occur on or about January 5, 2010. </p> <p>The securities being offered by the Trust have not been, nor will be, registered under the United States Securities Act of 1933, as amended, and may not be offered or sold in the United States or to U.S. persons absent registration or applicable exemption from the registration requirement of such Act. This release does not constitute an offer for sale of trust units in the U.S. and any public offering of trust units in the U.S. will be made by means of a prospectus. </p> <pre> &lt;&lt; ARC RESOURCES LTD. John P. Dielwart, Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00015954E %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>23/12/2009 7:01:47 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1369326http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1366654CALGARY, Dec. 16, 2009 (Canada NewsWire via COMTEX) -- (AET.UN and ARX - TSX) ARC Energy Trust (the "Trust" or "ARC") announces that the cash distribution to be paid on January 15, 2010, in respect of the December 2009 production, for unitholders of record on December 31, 2009, will be $0.10 per trust unit. The ex-distribution date is December 29, 2009. <p>As at December 16, 2009 the Trust's trailing twelve-month cash distributions, including the December 15, 2009 payment, total $1.33 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 $5.5 billion. The Trust expects 2009 oil and gas production to average 63,000 to 64,000 of barrels of oil equivalent per day from six core areas in western Canada. 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 2009 and beyond; the sources, deployment and allocation of expected capital in 2009; 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, 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>16/12/2009 12:38:55 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1366654http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1360055CALGARY, Nov. 30, 2009 (Canada NewsWire via COMTEX) -- (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 2.70645 to 2.71953. Such increase will be effective on December 15, 2009. <p>The following are the details on the calculation of the exchange ratio: </p> <pre> &lt;&lt; ------------------------------------------------------------------------- 10 day Record weighted Effective date of average date ARC ARC Energy trading of the Exchange Energy Trust price of Increase increase ratio as Trust Opening distrib- AET.UN (prior in in of distrib- exchange ution to the end exchange exchange effective ution ratio per unit of the month) ratio(xx) ratio date ------------------------------------------------------------------------- November December 30, 2009 2.70645 $0.10 $20.6942 0.01308 15, 2009 2.71953 ------------------------------------------------------------------------- (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, 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> 30/11/2009 5:01:00 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1360055http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1359306CALGARY, Nov. 25, 2009 (Canada NewsWire via COMTEX) -- Notification of live webcast event: <pre> &lt;&lt; ARC Energy Trust (TSX:AET.UN) Live webcast presentation Tuesday, December 1, 2009 10:15 AM GMT To listen and view this online event, please visit: http://remotecontrol.jetstreammedia.com/16757 &gt;&gt; </pre> <p>The presentation will be available in an archived version at this link for 30 days following the live presentation. </p> <p>SOURCE: ARC Energy Trust </p> <pre>on the webcast please visit www.firstenergy.com or contact: ARC Energy Trust, Raina Vitanov, Senior Advisor, Investor Relations, IR@arcresources.com, Ph: 1-888-272-4900 </pre> 25/11/2009 10:01:00 AMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1359306http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1355858CALGARY, Nov. 16, 2009 (Canada NewsWire via COMTEX) -- (AET.UN and ARX - TSX) ARC Energy Trust (the "Trust" or "ARC") announces that the cash distribution to be paid on December 15, 2009, in respect of the November 2009 production, for unitholders of record on November 30, 2009, will be $0.10 per trust unit. The ex-distribution date is November 26, 2009. <p>As at November 16, 2009 the Trust's trailing twelve-month cash distributions, including the November 16, 2009 payment, total $1.43 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 $5.7 billion. The Trust expects 2009 oil and gas production to average 63,000 to 64,000 of barrels of oil equivalent per day from six core areas in western Canada. 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 2009 and beyond; the sources, deployment and allocation of expected capital in 2009; 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> <p>ARC RESOURCES LTD. </p> <p>John P. Dielwart, </p> <p>Chief Executive Officer </p> <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> 16/11/2009 11:40:00 AMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1355858http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1352142CALGARY, Nov. 5, 2009 (Canada NewsWire via COMTEX) -- (AET.UN and ARX - TSX) ARC Energy Trust (the "Trust" or "ARC") announced today that its Board of Directors has approved a budget for 2010 that includes a $575 million capital expenditure program and plans for substantial growth in production each of the next three years. <p>John Dielwart, ARC's Chief Executive Officer, said, "Strong production from 2009 provides a platform for a period of growth beginning in 2010 and continuing for several years beyond. Commissioning of the new Dawson gas plant early in the second quarter of 2010 should propel ARC exit volumes to greater than 73,000 boe per day and work has already begun on the Phase 2 gas plant for proposed commissioning in early 2011. On the oil side, we will be expanding our horizontal drilling programs at Pembina, Ante Creek and Goodlands as we follow-up on successful results achieved to date." </p> <p>"Our focus on risk managed value creation has served our investors well. Our approach to running the business has not changed with this budget. More capital has been dedicated to expansion, as we believe that moving into a period of measured growth is the best way to create value from our Montney assets. In addition, a meaningful exploration component is included in this budget to address the 'what's next' component of our strategy," added Mr. Dielwart. </p> <pre> &lt;&lt; Highlights of the 2010 Budget - The capital budget has been set at $575 million with key initiatives being: - Significant near-term growth from our Montney assets - Diversified investment in our base assets, primarily directed to the application of horizontal drilling and multi-stage fracture completion technology on our oil properties - Funding of exploration initiatives intended to identify areas for future growth - Advancement of our CO(2) enhanced oil recovery projects - Over 40 per cent of the expenditures ($250 million) will be spent to increase production from the Montney assets in northeast British Columbia through the commissioning of a 60 mmcf per day gas plant early in the second quarter of 2010. Included in this number are funds for the drilling of the operated and non-operated horizontal wells required to maintain production at approximately 115 mmcf per day once the new plant comes onstream. We also have funds allocated to the design and construction of the Dawson Phase 2 gas plant and for the drilling of the horizontal wells required to fill the plant when it starts-up early in 2011. - A total of 66 horizontal wells, requiring an expenditure of $104 million will be targeted at the further development of our oil resource plays at Pembina, Garrington, Ante Creek, Goodlands and southeast Saskatchewan - Nine per cent of the budget will be directed towards exploration opportunities with the goal of providing future growth engines for the entity - Seven per cent of the budget will continue and expand on the inventory of enhanced oil recovery projects from Weyburn, Saskatchewan to Redwater, Alberta - A production target for 2010 of 68,000 to 70,000 boe per day comprising approximately 44 per cent crude oil and NGLs and 56 per cent natural gas with an exit rate of over 73,000 boe per day representing the replacement of approximately 11,000 boe per day of decline and growth of 10,000 boe per day relative to our 2009 exit rate - Operating costs in 2010 are predicted to be $10.30 per boe, which is two per cent lower than 2009 estimated costs &gt;&gt; </pre> <p>Capital Program </p> <p>The $575 million capital program for 2010 is a $210 million increase over estimated 2009 capital expenditures of $365 million. Strengthening cash flow forecasts for 2010 make it possible to re-address a significant number of deferred opportunities from 2009. The primary focus of the 2010 budget will be to balance expenditures for growth in the Montney gas assets with spending on horizontal drilling opportunities on our oil properties. </p> <p>Based on 2010 budget projections, ARC will drill approximately 203 gross wells (187 net) on its operated properties. Approximately half will be vertical wells and half will be horizontal wells with 96 wells targeting oil and 107 wells targeting natural gas. On ARC's non-operated properties we anticipate our partners will drill 91 gross wells (18 net) with ARC's share of expenditures being approximately $53 million. </p> <pre> &lt;&lt; 2010 Capital ($millions) Operated Core (Op + wells Districts Non-Op) (gross) Gas/Oil Comment ------------------------------------------------------------------------- NEBC/NWAB 293 51 Gas/Oil Dawson and other areas NORTHAB 43 8 Oil Primarily Ante Creek REDWATER 27 12 Oil Includes EOR PEMBINA 54 32 Oil Includes 17 Hz wells CENTRAL 42 19 Gas/Oil Includes 9 Hz wells SEAB/SWSK 19 50 Gas Primarily Shallow gas SESK/MB 67 31 Oil Includes 24 Hz wells and EOR CORPORATE 30 - - Total 575 203 &gt;&gt; </pre> <p>ARC expects to allocate over 50 per cent of the capital budget to the northeast British Columbia - northwest Alberta region. At Dawson, in northeast British Columbia, we plan to spend $217 million to commission our first 60 mmcf per day gas plant, for design and preliminary construction for a second 60 mmcf per day plant and the drilling of 32 horizontal and three vertical wells. This activity is designed to increase operated production from 55 mmcf per day in 2009 to a stabilized rate of 105 mmcf per day upon completion of the gas plant. When the new plant is operational, it will displace approximately 10 mmcf per day of production currently processed at a third-party operated plant due to facility constraints. </p> <p>In 2010 we will also focus on exploration, delineation and technological development within the West Montney assets as we further advance our understanding of the significant resources that we believe we have in the area. On the West Montney lands, $47 million has been budgeted for further delineation drilling on the ARC operated lands and for continued development of a partner operated Montney project at Sunrise that will contribute a stable 10 mmcf per day net to ARC in 2010. Additionally, ARC expects to have 60 mmcf per day of production on the operated lands at Sunrise in early 2012. We have also allocated $20 million towards Montney development and exploration on the Alberta side of the border at Pouce Coupe, Progress and Valhalla. </p> <p>Another property where ARC is deploying horizontal drilling and completion technology is Ante Creek in northern Alberta where $35 million has been allocated to drill six horizontal and two vertical wells as a follow-up to a successful 2009 drilling program. Other areas in northern Alberta with targeted development include Swan Hills, Prestville, Chinchaga and the non-operated House Mountain Unit. </p> <p>At Redwater, in central Alberta, we plan to spend $16 million drilling four vertical and six horizontal Leduc, Mannville and Viking wells. Approximately $4 million, net of external funding, will be allocated to continuing our CO(2) Enhanced Oil Recovery ("EOR") pilot. We expect to spend $7 million, net of external funding, on the Heartland Area Redwater Project ("HARP") CO(2) sequestration project. </p> <p>An emphasis on the development of oil resource plays has lead to the allocation of $54 million to Pembina in central Alberta. ARC plans to drill 32 Cardium locations on operated lands with over half of these being horizontal, multi-frac completions. There are also plans to fund the early stage planning and development of a CO(2) enhanced oil recovery pilot in the ARC operated North Pembina Cardium Unit No.1. </p> <p>Throughout ARC's other core areas, numerous development activities will take place. In Central Alberta, ARC will devote approximately $26 million to drill approximately 10 horizontal oil wells and $2.7 million to drill 15 natural gas from coal wells. In southeast Alberta and southwest Saskatchewan, a $19 million program to drill approximately 50 gross shallow gas wells will be conducted. In southeast Saskatchewan and southwest Manitoba, ARC plans to spend $67 million drilling horizontal oil wells and exploring for new opportunities. ARC expects to drill approximately 31 wells on operated properties including, Lougheed, Skinner Lake, Oungre, Weirhill, Parkman, Elmore and Goodlands. </p> <p>The non-operated budget capital for 2010 is included in the previous numbers and will be dominated by activity in Weyburn, Midale and Instow, Saskatchewan as well as the Montney program in the Sunrise area of northeast British Columbia. </p> <p>Corporate capital of $30 million comprises leasehold development costs associated with ARC's new office premises at Jamieson Place and other capitalized costs related to general and administrative expenses. ARC expects to relocate to the new premises in the second quarter of 2010. </p> <p>The budgeted capital expenditures for 2010, by type are: </p> <pre> &lt;&lt; 2008 2009 2010 ($ millions) (Actual) (Estimate)(1) (Budget) ------------------------------------------------------------------------- Development 232 174 351 Development - Facilities 13 75 49 Maintenance 21 12 23 Optimization 12 9 14 Land &amp; Seismic 139 11 7 Unconventional gas 22 20 8 Enhanced Oil Recovery 51 28 40 Exploration 45 14 48 Other 14 22 35 -------------------------------------- Total 549 365 575 -------------------------------------- (1) ARC announced an increase to its 2009 estimated budget in the third quarter financial release dated November 5, 2009 from $350 million to $365 million. 2008 2009 2010 Operated Wells Drilled (gross) (Actual) (Estimate) (Budget) ------------------------------------------------------------------------- Natural gas wells 139 112 107 Oil wells 93 35 96 -------------------------------------- Total 232 147 203 -------------------------------------- Capital Budget by Area: 2008 2009 2010 ($ millions) (Actual) (Estimate) (Budget) ------------------------------------------------------------------------- Northeast British Columbia &amp; Northwest Alberta 230 199 293 Northern Alberta 58 32 43 Pembina 38 24 54 Central Alberta 37 25 42 Southeast Alberta &amp; Southwest Saskatchewan 22 12 19 Southeast Saskatchewan &amp; Manitoba 113 46 67 Redwater 36 13 27 Corporate 15 14 30 -------------------------------------- Total 549 365 575 -------------------------------------- Alberta Total 209 122 233 Saskatchewan and Manitoba Total 129 55 72 British Columbia Total 211 188 270 &gt;&gt; </pre> <p>The allocation of capital expenditures for exploration and development activities by area and the number and types of wells to be drilled is dependent upon results achieved and is subject to review and modifications by management on an ongoing basis throughout the year. </p> <p>Impact of Royalty Changes </p> <p>Effective January 2009, the Alberta Government's New Royalty Framework ("NRF") took effect and resulted in royalty rates that are more sensitive to both price and production levels. In addition, both the Alberta and British Columbia Governments implemented royalty incentive programs during 2009 in response to the economic downturn. The incentive programs for both provinces include drilling credit programs and royalty relief programs for new wells coming on production through 2011. </p> <p>Throughout the first nine months of 2009, the Trust's total corporate royalty rate was 16 per cent as compared to 18 per cent in 2008 as a result of the changes to the royalty programs whereby lower commodity prices throughout 2009 resulted in a lower corporate royalty rate. ARC expects to benefit from the royalty incentive programs in 2010 and 2011 as it executes a capital program that includes significant development plans in British Columbia. The Trust expects that the 2010 total corporate royalty rate will be in the 15 to 21 per cent range depending upon commodity prices and the level of incentives realized, as illustrated in the following table. </p> <pre> &lt;&lt; Corporate Royalty Rate - 2010 Estimated ------------------------------------------------------------------------- Edmonton posted oil (Cdn$/bbl)(1) $ 50.00 $ 60.00 $ 70.00 $ 80.00 $ 90.00 AECO natural gas (Cdn$/GJ)(1) $ 5.00 $ 6.00 $ 7.00 $ 8.00 $ 9.00 Total Corporate Royalty Rate(2)(3) 15% 16% 18% 20% 21% (1) Canadian dollar denominated prices before quality differentials. (2) Estimated corporate royalty rates based on guidelines that are subject to change. (3) Corporate royalty rate includes Crown, Freehold and Gross Override royalties for all jurisdictions in which the Trust operates. &gt;&gt; </pre> <p>Production Volumes </p> <p>Targeted annual production volumes for 2010 are expected to be approximately 68,000 to 70,000 boe per day, which includes an estimate of downtime for unplanned outages. Production is expected to grow to approximately 70,000 boe per day in the second quarter with the commissioning of the new Dawson gas plant and continue to grow through the remainder of the year to an exit rate of approximately 73,000 boe per day. This new production level will provide a strong platform for continued growth in 2011 as we work towards the construction of the Dawson Phase 2 gas plant. </p> <p>The anticipated 2010 volumes do not reflect any potential acquisitions or dispositions. Through the normal course of business, minor acquisitions and dispositions are expected to occur that could impact the forecasted volumes. </p> <p>The low operating cost of the Montney production additions, will contribute to a two per cent decrease in per boe operating costs from the 2009 estimated value of $10.50 per boe to approximately $10.30 per boe. In total we predict $260 million of total operating costs for 2010. </p> <p>General and Administrative ("G&amp;A") Expense </p> <p>ARC expects total G&amp;A expenses including the Whole Unit Plan expenses to be approximately $72 million or $2.85 per boe in 2010, an increase from the $2.10 expected for 2009. The increase in G&amp;A is due in part to higher lease payments as ARC has taken on additional office space under a new long-term lease that takes effect in April 2010 in anticipation of future growth. In addition, compensation costs are expected to increase as the Trust executes one of the largest capital budgets in its history and positions itself for future growth. With the planned conversion to a corporation on or before January 1, 2011, the Trust also expects to incur certain one-time, conversion-related expenses in 2010. </p> <p>ARC's 2010 budgeted G&amp;A includes estimated payments of $11.1 million and $11.5 million for cash payments under the Whole Unit Plan in the first half and second half of 2010, respectively. If ARC's three year total return is not in the top quartile of its peers as of vesting dates, the cash payments may be less than those budgeted. The estimated cash Whole Unit Plan payments in 2010 are higher than 2009 levels as payments are tied to ARC's unit price, which was substantially lower in early 2009 as a result of the economic downturn. In addition the 2010 G&amp;A budget includes a non-cash G&amp;A recovery of $1.8 million relating to the Whole Unit Plan. </p> <p>Following is a summary of estimated 2010 cash and non-cash G&amp;A expenses: </p> <pre> &lt;&lt; ($ millions, except per boe amounts) 2008 2009 2010 Actual Estimate Budget ------------------------------------------------------------------------- Cash G&amp;A expenses (before LTIP) $ 38.8 $ 40.6 $ 51.3 Cash LTIP expense $ 21.3 $ 12.7 $ 22.6 Total Cash G&amp;A $ 60.1 $ 53.3 $ 73.9 Non-Cash LTIP expense $ 1.1 $ (4.6) $ 1.8 Total G&amp;A expense $ 61.2 $ 48.7 $ 72.1 Cash G&amp;A expense (before LTIP) per boe $ 1.63 $ 1.75 $ 2.00 Cash LTIP expense per boe $ 0.90 $ 0.55 $ 0.90 Non-Cash LTIP expense per boe $ 0.05 $ (0.20) $ (0.05) Total G&amp;A expense per boe $ 2.57 $ 2.10 $ 2.85 &gt;&gt; </pre> <p>Risk Management </p> <p>As part of its overall strategy to protect cash flow ARC uses a variety of instruments to hedge crude oil, natural gas, foreign exchange rates, electrical power costs and interest rates. </p> <p>For 2010, the Trust has in place protection on both crude oil and natural gas on volumes extending to the fourth quarter with greater volumes on the earlier periods of the year. ARC continues to watch for opportunities to meaningfully protect the 2010 capital budget and will take positions in natural gas and or crude oil at levels that will provide significant certainty on rates of return. The following table provides a summary of ARC positions as of October 29 and assumes a foreign exchange rate of 0.9346 $US/$C (1.07 $C/$US). </p> <pre> &lt;&lt; ------------------------------------------------------------------------- Q4 2009 Q1 2010 Q2 2010 ------------------------------------------------------------------------- Crude Oil C$/bbl bbl/day C$/bbl bbl/day C$/bbl bbl/day ------------------------------------------------------------------------- Sold Call 82.68 7,000 95.85 7,000 97.63 6,000 Bought Put 67.30 9,500 75.31 7,000 76.33 6,000 Sold Put 42.60 2,500 NA - NA - ------------------------------------------------------------------------- Natural Gas CDN$/GJ GJ/day CDN$/GJ GJ/day CDN$/GJ GJ/day ------------------------------------------------------------------------- Sold Call 5.52 93,370 6.80 5,000 6.80 5,000 Bought Put 4.84 93,370 6.80 5,000 6.80 5,000 Sold Put 4.50 20,000 NA - NA - ------------------------------------------------------------------------- ------------------------------------------------------------------------- Q3 2010 Q4 2010 ------------------------------------------------------------------------- Crude Oil US$/bbl bbl/day US$/bbl bbl/day ------------------------------------------------------------------------- Sold Call 97.63 6,000 97.63 6,000 Bought Put 76.33 6,000 76.33 6,000 Sold Put NA - NA - ------------------------------------------------------------------------- Natural Gas CDN$/GJ GJ/day CDN$/GJ GJ/day ------------------------------------------------------------------------- Sold Call 6.80 5,000 6.80 5,000 Bought Put 6.80 5,000 6.80 5,000 Sold Put NA - NA - ------------------------------------------------------------------------- (1) The prices and volumes noted above represent averages for several contracts. 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 for indicative purposes only. In addition to positions shown here, ARC has entered into additional basis positions, power positions, and an energy equivalent swap for the fourth quarter of 2009. (2) Please refer to the Trust's website at www.arcenergytrust.com under "Hedging Program" within the "Investor Relations" section for details on the Trust's current hedging position. &gt;&gt; </pre> <p>Funding of the 2010 Capital Program </p> <p>The $575 million capital budget was based on the expectation that commodity prices would average approximately Cdn$80 per barrel for oil and Cdn$5.50 per mcf for gas and the continuation of the $0.10 monthly distribution. The Trust will pursue cost effective means of financing its 2010 capital program through a combination of cash flow, existing credit facilities, DRIP proceeds and potential minor asset dispositions. The exact split will be dependent on commodity prices, operational performance and possible acquisitions and dispositions. Management will review the 2010 capital program on a regular basis in the context of prevailing economic conditions and make adjustments as deemed necessary to the program, subject to review by the Trust's Board of Directors. The monthly $0.10 distribution is primarily dependent upon commodity prices and prevailing economic conditions and will be reviewed regularly by the Board of Directors. </p> <p>Reclamation Fund </p> <p>As at September 30, 2009, the Trust's reclamation funds stood at $31.8 million. The Trust's budget currently incorporates a contribution of $10.9 million to the funds in 2010 to provide for the eventual abandonment of the Trust's oil and gas properties. For the 2010 fiscal period the Trust plans on withdrawing approximately $7.1 million from the reclamation fund to spend on ongoing reclamations and well abandonments. </p> <pre> &lt;&lt; Detailed Guidance - 2008 2009 2010 Production (Actual) (Estimate) (Budget) ------------------------------------------------------------------------- Oil (bbls/d) 28,513 27,500 27,100 - 28,000 NGLs (bbls/d) 3,861 3,500 3,067 - 3,200 Gas (mmcf/d) 196.5 195 227 - 233 Total (boe/d) 65,126 63,500 68,000 - 70,000 2008 2009 2010 Costs and Expenses ($/boe) (Actual) (Estimate) (Budget) ------------------------------------------------------------------------- Operating costs 10.13 10.50 10.30 Transportation costs 0.80 0.90 1.00 G&amp;A expenses 2.48 2.10 2.85 Interest 1.39 1.30 1.40 Weighted average units outstanding including units held for exchangeable shares (millions) 216 238 240 &gt;&gt; </pre> <p>The 2010 Guidance provides unitholders with information on Management's expectations for results of operations, excluding any acquisitions for 2010. Readers are cautioned that the 2010 Guidance may not be appropriate for other purposes. </p> <p>This press release contains forward-looking statements as to the Trust's internal projections, expectations or beliefs relating to future events or future performance, including the Trust's Detailed Guidance for 2010 and the amount and type of 2010 budgeted capital expenditures set forth herein. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expects", "projects", "plans", "anticipates" and similar expressions. These statements represent management's expectations or beliefs concerning, among other things, future capital expenditures and future operating results and various components thereof or the economic performance of ARC Energy Trust ("ARC" or "the Trust"). The projections, estimates and beliefs contained in such forward-looking statements are based on management's assumptions relating to the production performance of ARC's oil and gas assets, the cost and competition for services throughout the oil and gas industry in 2010, the results of exploration and development activities during 2010, the market price for oil and gas, expectations regarding the availability of capital, estimates as to the size of reserves and resources, and the continuation of the current regulatory and tax regime in Canada, and necessarily involve known and unknown risks and uncertainties inherent in exploration and development activities, geological, technical, drilling and processing problems and other risks and uncertainties, including the business risks discussed in management's discussion and analysis and ARC's annual information form, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted. The Trust does not undertake to update any forward looking information in this document whether as to new information, future events or otherwise except as required by securities rules and regulations. </p> <p>ARC Energy Trust is one of Canada's largest conventional oil and gas royalty trusts with an enterprise value of approximately $5.4 billion. The Trust currently produces approximately 63,000 to 64,000 barrels of oil equivalent per day from five core areas in western Canada. ARC Energy Trust trades on the TSX under the symbol AET.UN. </p> <p>Note: Barrels of oil equivalent (BOEs) may be misleading, particularly if used in isolation. In accordance with NI 51-101, a BOE conversion ratio for natural gas of 6 Mcf:1bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. </p> <pre> &lt;&lt; ARC RESOURCES LTD. John P. Dielwart, Chief Executive Officer &gt;&gt; </pre> <p>%SEDAR: 00001245E %CIK: 0001029509 </p> <p>SOURCE: ARC Energy Trust </p> <p>SOURCE: ARC Resources Ltd. </p> <pre>Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6417, Toll Free 1-888-272-4900, ARC Resources Ltd., 2100, 440 - 2nd Avenue S.W., Calgary, AB, T2P 5E9, www.arcenergytrust.com </pre> 05/11/2009 7:28:00 PMhttp://www.arcresources.net/en-ca/news/permalink.htm?newsreleaseref=news_1352142http://www.arcresources.net/en-ca/news/article.htm?newsreleaseref=news_1352141CALGARY, Nov. 5, 2009 (Canada NewsWire via COMTEX) -- (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or "the Trust") announces the results for the third quarter ended September 30, 2009. <pre> &lt;&lt; ------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30 September 30 2009 2008 2009 2008 ------------------------------------------------------------------------- FINANCIAL (Cdn$ millions, except per unit and per boe amounts) Revenue before royalties 239.2 485.7 699.6 1,405.6 Per unit(1) 1.01 2.24 2.98 6.53 Per boe 41.39 82.06 40.12 78.84 Cash flow from operating activities(2) 125.6 251.4 354.2 734.8 Per unit(1) 0.53 1.16 1.51 3.41 Per boe 21.73 42.48 20.31 41.22 Net income 68.9 311.7 157.3 450.3 Per unit(3) 0.29 1.46 0.68 2.12 Distributions 70.6 171.3 227.6 442.8 Per unit(1) 0.30 0.80 0.98 2.08 Per cent of cash flow from operating activities(2) 56 68 64 60 Net debt outstanding(4) 705.4 773.2 705.4 773.2 OPERATING Production Crude oil (bbl/d) 26,921 28,509 27,541 28,372 Natural gas (mmcf/d) 193.1 192.0 195.7 197.0 Natural gas liquids (bbl/d) 3,717 3,822 3,720 3,862 Total (boe/d) 62,824 64,325 63,881 65,063 Average prices Crude oil ($/bbl) 67.74 114.2 58.77 107.20 Natural gas ($/mcf) 3.25 8.68 4.05 8.94 Natural gas liquids ($/bbl) 38.92 82.87 38.89 77.92 Oil equivalent ($/boe) 41.31 81.42 40.00 78.44 Operating netback ($/boe) Commodity and other revenue (before hedging)(5) 41.39 82.06 40.11 78.84 Transportation costs (0.83) (0.80) (0.88) (0.77) Royalties (6.53) (15.00) (5.86) (14.18) Operating costs (9.68) (10.19) (10.28) (10.14) Netback (before hedging) 24.35 56.07 23.09 53.75 ------------------------------------------------------------------------- TRUST UNITS (millions) Units outstanding, end of period(6) 238.1 217.4 238.1 217.4 Weighted average trust units(7) 237.7 216.6 234.5 215.2 ------------------------------------------------------------------------- TRUST UNIT TRADING STATISTICS (Cdn$, except volumes) based on intra-day trading High 20.20 33.30 20.90 33.95 Low 15.48 22.33 11.73 20.00 Close 20.20 23.10 20.20 23.10 Average daily volume (thousands) 1,038 841 1,088 790 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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 2009 would be $124.8 million ($0.52 per unit) and $361.9 million ($1.54 per unit) year-to-date. Distributions as a percentage of Cash Flow would be 57 per cent for the third quarter of 2009 (63 per cent year-to-date). (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) For the third quarter of 2009, includes 0.9 million (1.1 million in 2008) exchangeable shares exchangeable into 2.679 trust units (2.431 in 2008) each for an aggregate 2.5 million (2.7 million in 2008) trust units. (7) Includes trust units issuable for outstanding exchangeable shares at period end. ACCOMPLISHMENTS/FINANCIAL UPDATE -------------------------------- - Production volumes for the quarter were 62,824 boe per day, a decline of two per cent compared to the second quarter. The Trust continues to expect full year average production between 63,000 and 64,000 boe per day. - Operating costs decreased to $9.68 per boe in the quarter compared to $10.19 per boe in the third quarter of 2008. Total operating costs decreased $4.3 million, or seven per cent in the third quarter of 2009 as compared to the third quarter of 2008. The decrease in costs is primarily attributed to lower power costs in 2009 as well as cost savings and efficiencies achieved by the operations team. The Trust estimates that full year 2009 operating costs will be approximately $243 million or approximately $10.50 per boe based on annual production of between 63,000 and 64,000 boe per day. - Cash flow from operating activities was $125.6 million, or $0.53 per unit, a significant decline from the $251.4 million ($1.16 per unit) achieved in the comparable quarter in 2008. This decline was due to a 49 per cent decrease in commodity prices in the third quarter of 2009 compared to the same period in 2008. Crude oil prices strengthened during the third quarter compared to the first half of 2009 as the economy showed some positive signs of recovery. Natural gas prices continued to soften throughout the third quarter reaching a low of $1.94 per mcf, however they did begin to recover early in the fourth quarter. After payment of distributions the Trust was able to fund 55 per cent of the third quarter capital program with cash flow from operating activities (72 per cent when including the quarterly proceeds from the distributions re-investment program ("DRIP")) with the remaining portion being funded through proceeds from property dispositions that were completed in the quarter. - The Trust executed a $96.2 million capital expenditure program in the third quarter of 2009 that included: drilling 11 oil wells in the Ante Creek, Pembina and Goodlands areas, drilling six natural gas wells in the Dawson area, and spending $11 million on the new gas plant at Dawson. Of the wells drilled in the third quarter, two natural gas wells and seven oil wells were completed; as well 10 wells were completed that were drilled in previous quarters. Included in the third quarter capital expenditures is a crown land acquisition in Pembina for $2.4 million where the Trust is planning to drill nine horizontal oil wells into the Cardium zone during the fourth quarter and into 2010. During the quarter, the Trust closed a disposition of non-core assets in southeast Saskatchewan for proceeds of $33.5 million that were used to fund a portion of the third quarter capital expenditures. Full year capital expenditures are now expected to be approximately $365 million, an increase of $15 million over second quarter guidance as the Trust has chosen to increase capital spending in Alberta and British Columbia to take advantage of royalty incentives announced by those provinces. - At September 30, 2009 the Trust had a net debt balance of $705.4 million, approximately $680 million of unused credit available and a net debt to annualized year-to-date cash flow from operating activities of 1.5 times. At this time, the Trust is well positioned to finance the remainder of the 2009 capital program and the projected 2010 capital program. - ARC plans to convert to a Corporation on January 1, 2011. The Board of Directors has approved the overall strategy and currently the detailed implementation steps are being defined. - The Trust's board of directors has approved a $575 million capital program for 2010 that will encompass considerable growth. The program will include over $250 million slated for the first of many stages of production growth and continued expansion of the Montney assets in Northeast British Columbia with the remainder focused on ARC base development areas, exploration opportunities and enhanced oil recovery projects. ARC plans to drill 203 gross wells on operated properties and plans to participate in an additional 91 wells on partner operated properties. The Trust plans to finance the 2010 capital program through a combination of cash flow, existing credit facilities, DRIP proceeds and potential minor assets disposition proceeds. Additional details can be found in the November 5, 2009 news release titled "ARC Energy Trust Announces a $575 million Capital Budget for 2010" and filed on www.sedar.com. - Montney Resource Play Development Production from the Dawson area was on budget at an average rate of 53.3 mmcf per day throughout the third quarter. The decreased production rates when compared to the second quarter of 2009 were as a result of the planned turnaround of a third party gas plant that shut-in production for the full Dawson field periodically during the month of September. During the third quarter of 2009, the Trust spent $41.7 million on development activities in the Dawson area including drilling four horizontal wells and two vertical wells that were drilled and completed during the quarter. ARC tested eight Dawson horizontal wells during the quarter at rates between seven and 11 mmcf per day of natural gas at a flowing pressure of 1,600 to 2,000 pounds per square inch. At this time, the Trust has 23 wells drilled in the Dawson gas field that are in various stages of completion. In the completed and waiting on tie-in category are 18 wells (11 horizontal and seven vertical), while the remaining five wells (all horizontal) are yet to be completed. In addition to these Dawson wells, ARC has drilled five vertical wells and two horizontal wells in the Sunrise-Sunset area, none of which are tied-in. In the Montney West lands, ARC drilled a well at Sunset to hold land that was due to expire in the fourth quarter of 2009 allowing ARC to pursue future drilling opportunities on this land. ARC is participating in a small development project on partner operated lands at Sunrise. Current plans call for the drilling of four horizontal wells, construction of pipelines and a gathering system and the expansion of a third party operated gas plant. At quarter end, two horizontal wells had been drilled that will be completed in the fourth quarter. Assuming that the drilling and construction go as planned, production from this area should be approximately 10 mmcf per day net to ARC's 50 per cent working interest by the beginning of 2010. Due to regulatory delays in receiving final approvals, we now believe the Dawson Phase 1, 60 mmcf per day gas plant start-up will be early in the second quarter of 2010. Year-to-date $29.8 million has been spent on the gas plant. The British Columbia Oil and Gas Commission ("OGC") has granted conditional approvals, prior to final permit approval, for: site grading (which is completed), pounding pilings (completed pounding 1,350 pilings), mobilizing mechanical contractor's trailers and equipment to site (in progress) and setting major equipment skids (modules are being transported to site). Once final permit approval is received from the OGC all on-site construction will begin. - Enhanced Oil Recovery Initiatives During the third quarter, the Trust spent $7.5 million on enhanced oil recovery ("EOR") initiatives and received $2.8 million in funding from the Alberta Government for the Redwater pilot project for net spending of $4.7 million during the quarter. Work on the Redwater CO(2) pilot project continues and both the CO(2) injection and oil production facilities are operating. Results to date are encouraging but the Trust anticipates that it will take until the first quarter of 2010 to determine to what extent the pilot has been successful in mobilizing incremental volumes of oil. While the pilot project may indicate enhanced recovery, the outlook for crude oil prices and the cost and availability of CO(2) will be determining factors in the Trust's ability to achieve commercial viability for a full scale EOR scheme at Redwater. 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 November 4, 2009 and should be read in conjunction with the unaudited Consolidated Financial Statements for the period ended September 30, 2009, the MD&amp;A and the unaudited Consolidated Financial Statements ended June 30, 2009, the MD&amp;A and the unaudited Consolidated Financial Statements ended March 31, 2009 and the audited Consolidated Financial Statements and MD&amp;A as at and for the year ended December 31, 2008 as well as the Trust's Annual Information Form that is filed on SEDAR at www.sedar.com. </p> <p>The MD&amp;A contains Non-GAAP measures and forward-looking statements and readers are cautioned that the MD&amp;A should be read in conjunction with the Trust's disclosure under "Non-GAAP Measures" and "Forward-Looking Statements" included at the end of this MD&amp;A. </p> <p>ARC's Business </p> <p>ARC Energy Trust ("ARC") or ("the Trust") is an actively managed oil and natural gas entity formed to provide investors with indirect ownership in cash generating energy assets, that currently consist of oil and natural gas assets. The cash flow from operating activities is based on the production and sale of crude oil, natural gas liquids and natural gas. </p> <p>ARC is one of the top 20 producers of conventional oil and natural gas in western Canada. As at September 30, 2009, ARC held interests in excess of 18,650 wells with approximately 5,700 wells operated by ARC and the remainder principally operated 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, 2009 was $5.5 billion as shown on Table 23. </p> <p>ARC's Objective </p> <p>ARC's objective is to be one of the top performing oil and gas companies in Canada as measured by quality of assets, management expertise and investor returns. The focus is on risk managed value creation. Table 1 shows the Trust's ability to maintain stable production and reserves per unit while distributing a portion of the cash flows back to unitholders. The decrease in 2009 production per unit reflects the impact of issuing 15.5 million trust units in the first quarter that raised $240 million used to partially fund capital expenditures in the Dawson area. ARC is constructing a 60 mmcf per day capacity gas plant with an expectation that production per unit will increase in 2010 upon startup of this plant. </p> <pre> &lt;&lt; Table 1 ------------------------------------------------------------------------- Full year Full year Per Trust Unit Q3 2009 YTD 2009 2008 2007 ------------------------------------------------------------------------- Normalized production per unit(1)(2) 0.27 0.28 0.29 0.30 Normalized reserves per unit(1)(3) N/A N/A 1.42 1.35 Distributions per unit 0.30 0.98 $2.67 $2.40 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Normalized indicates that all periods 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 per unit values. (2) Production per unit represents daily average production (boe) per thousand trust units and is calculated based on daily average production divided by the normalized weighted average trust units outstanding including trust units issuable for exchangeable shares. (3) Reserves per unit are calculated based on proved plus probable reserves (boe) at period end divided by period end trust units outstanding including trust units issuable for exchangeable shares. &gt;&gt; </pre> <p>Currently the Trust distributes $0.10 per unit per month. 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, 2009, the Trust has distributed $3.5 billion or $24.68 per unit. </p> <p>ARC's business plan has resulted in significant operational success as seen in Table 2 where the Trust's trailing five year annualized return per unit was 14.3 per cent. However, commodity prices and the current economic downturn are significant factors impacting the profitability of ARC and capital appreciation of our trust units in the market place. The impact of these external factors has led to a negative return for the trailing one year despite the successful execution of ARC's business plan and operational successes. </p> <pre> &lt;&lt; Table 2 ------------------------------------------------------------------------- Total Returns(1) ($ per unit except for Trailing Trailing Trailing per cent) One Year Three Year Five Year ------------------------------------------------------------------------- Distributions per unit $ 1.57 $ 6.65 $ 10.89 Capital appreciation per unit $ (2.90) $ (7.01) $ 3.35 Total return per unit (4.3)% 0.6% 95.3% Annualized total return per unit (4.3)% 0.2% 14.3% S&amp;P/TSX Capped Energy Trust Index (12.0)% (2.4)% 9.4% ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Calculated as at September 30, 2009. &gt;&gt; </pre> <p>2009 Third Quarter Financial and Operational Results </p> <p>Following is a discussion of ARC's 2009 guidance and third quarter financial and operating results. </p> <p>2009 Guidance and Financial Highlights </p> <p>Table 3 is a summary of the Trust's 2009 Guidance and a review of 2009 actual results compared to guidance: </p> <pre> &lt;&lt; Table 3 ------------------------------------------------------------------------- Revised 2009 2009 Guidance Actual YTD % Change ------------------------------------------------------------------------- Production (boe/d) 63,000-64,000 63,881 - ------------------------------------------------------------------------- Expenses ($/boe): Operating costs(1) 10.50 10.28 (2) Transportation(2) 0.90 0.88 (2) G&amp;A expenses (cash &amp; non-cash)(3) 2.10 2.20 5 Interest 1.30 1.14 (12) Capital expenditures ($ millions)(4) 365 242.3 - Annual weighted average trust units and trust units issuable (millions) 238 235 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) The Trust has revised full year 2009 operating costs from the original estimate of $10.70 per boe to be approximately $10.50 per boe or $243 million based on annual production of between 63,000 and 64,000 boe per day. This decrease is to reflect lower electricity costs recorded throughout the third quarter and overall costs savings being achieved by the operations team. (2) Full year transportation expense has been revised downward to $0.90 per boe from $1.00 per boe based on reduced estimates for oil trucking requirements throughout the third and fourth quarters. (3) G&amp;A guidance amount of $2.10 per boe includes $1.75 per boe for cash G&amp;A costs, $0.55 per boe for cash Whole Unit Plan costs and a recovery of $0.20 per boe for non-cash portion of the Whole Unit Plan. (4) Full year capital expenditures are now expected to be approximately $365 million, an increase of $15 million over second quarter guidance as the Trust has chosen to increase capital spending in Alberta and British Columbia to take advantage of royalty incentives announced by those provinces. &gt;&gt; </pre> <p>The 2009 Guidance provides unitholders with information on Management's expectations for results of operations, excluding any acquisitions or dispositions for 2009. Readers are cautioned that the 2009 Guidance may not be appropriate for other purposes. </p> <p>Table 4 is a review of the financial highlights and operating results for the third quarter and the first nine months of 2009. </p> <pre> &lt;&lt; Table 4 ------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30 September 30 ------------------------------------------------------------------------- (Cdn $ millions, except % % per unit and volume data) 2009 2008 Change 2009 2008 Change ------------------------------------------------------------------------- Cash flow from operating activities 125.6 251.4 (50) 354.2 734.8 (52) Cash flow from operating activities per unit(1) 0.53 1.16 (54) 1.51 3.41 (56) Net income 68.9 311.7 (78) 157.3 450.3 (65) Net income per unit(2) 0.29 1.46 (80) 0.68 2.12 (68) Distributions per unit(3) 0.30 0.80 (63) 0.98 2.08 (53) Distributions as a per cent of cash flow from operating activities 56 68 (18) 64 60 7 Average daily production (boe/d)(4) 62,824 64,325 (2) 63,881 65,063 (2) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Per unit amounts are based on weighted average trust units outstanding plus trust units issuable for exchangeable shares at period 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 boe in isolation may be misleading. &gt;&gt; </pre> <p>Net Income </p> <p>Net income in the third quarter of 2009 was $68.9 million ($0.29 per unit), a decrease of $242.8 million from $311.7 million ($1.46 per unit) in the third quarter of 2008. The net income recorded in the third quarter of 2008 reflected certain non-cash gains, as detailed below, resulting in record net income when combined with the strong commodity prices received for the quarter. Net income for the third quarter of 2009 reflects the decreased commodity price environment in the current year and includes certain non-cash items that also served to increase the net income during the period. </p> <p>In the third quarter of 2008, the Trust recorded a $187.5 million unrealized non-cash gain on risk management contracts ($140.6 million net of future income taxes). As well, the Trust recorded a $15.5 million non-cash foreign exchange loss on its U.S. denominated debt as a result of the movement in the Canadian dollar relative to the U.S. dollar ($13.6 million net of future income taxes). </p> <p>In the third quarter of 2009, the Trust recorded a $34.9 million non-cash foreign exchange gain on U.S. denominated debt ($30.5 million net of future income taxes) and a $0.7 million unrealized non-cash loss on risk management contracts ($0.5 million net of future income taxes). </p> <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 comparison of distributions to net income as a measure of long-term sustainability. Distributions have been reduced from $0.24 per unit per month in October 2008 to the current rate of $0.10 per unit per month. </p> <pre> &lt;&lt; Table 5 ------------------------------------------------------------------------- Net income and Distributions Third ($ millions except quarter Full year Full year per cent) 2009 YTD 2009 2008 2007 ------------------------------------------------------------------------- Net income 68.9 157.3 533.0 495.3 Distributions 70.6 227.6 570.0 498.0 ------------------------------------------------------------------------- Excess (Shortfall) (1.7) (70.3) (37.0) (2.7) Excess (Shortfall) as per cent of net income (2%) (45%) (7%) (1%) ------------------------------------------------------------------------- Cash flow from operating activities 125.6 354.2 944.4 704.9 Distributions as a per cent of cash flow from operating activities 56% 64% 60% 71% Average distribution per unit per month $0.10 $0.11 $0.22 $0.20 ------------------------------------------------------------------------- ------------------------------------------------------------------------- &gt;&gt; </pre> <p>Cash Flow from Operating Activities </p> <p>Cash flow from operating activities decreased by 50 per cent in the third quarter of 2009 to $125.6 million from $251.4 million in the third quarter of 2008. Decreases in crown royalties and cash losses on risk management contracts were more than offset by the 49 per cent ($40.11 per boe) decrease in commodity prices relative to the third quarter of 2008 as well as a two per cent decrease in volumes during the period. The decrease in third quarter 2009 cash flow from operating activities compared with the third quarter of 2008 is detailed in Table 6. </p> <pre> &lt;&lt; Table 6 ------------------------------------------------------------------------- ($ per ($ millions) trust unit) (% Change) ------------------------------------------------------------------------- Q3 2008 Cash flow from Operating Activities 251.4 1.16 - ------------------------------------------------------------------------- Volume variance (11.3) (0.05) (4.5) Price variance (235.2) (1.10) (93.6) Cash (losses) and gains on risk management contracts 41.0 0.19 16.3 Royalties 51.1 0.24 20.3 Expenses: Transportation - - - Operating(1) 5.5 0.03 2.2 Cash G&amp;A (7.3) (0.03) (2.9) Interest 1.4 0.01 0.6 Taxes (0.2) - (0.1) Realized foreign exchange loss 0.8 - 0.3 Weighted average trust units - (0.05) - Non-cash and other items(2) 28.4 0.13 11.3 ------------------------------------------------------------------------- Q3 2009 Cash flow from Operating Activities 125.6 0.53 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Excludes non-cash portion of Whole Unit Plan expense recorded in operating costs. (2) Includes the changes in non-cash working capital and expenditures on site restoration and reclamation. &gt;&gt; </pre> <p>Year-to-date cash flow from operating activities decreased by 52 per cent in 2009 to $354.2 million from $734.8 million in the comparable nine month period of 2008. The 49 per cent decrease in year-to-date commodity prices relative to the same period of 2008 more than offset decreases in crown royalties and cash losses on risk management contracts. The decrease in year- to-date 2009 cash flow from operating activities compared with the first nine months of 2008 is detailed in Table 6a. </p> <pre> &lt;&lt; Table 6a ------------------------------------------------------------------------- ($ per ($ millions) trust unit) (% Change) ------------------------------------------------------------------------- YTD 2008 Cash flow from Operating Activities 734.8 3.41 - ------------------------------------------------------------------------- Volume variance (30.6) (0.14) (4.2) Price variance (675.4) (3.12) (91.9) Cash (losses) and gains on risk management contracts 129.6 0.60 17.6 Royalties 150.6 0.70 20.5 Expenses: Transportation (1.5) (0.01) (0.2) Operating(1) 1.0 - 0.1 Cash G&amp;A 0.1 - - Interest 5.1 0.02 0.7 Taxes (0.2) - - Realized foreign exchange loss 1.3 0.01 0.2 Weighted average trust units - (0.14) - Non-cash and other items(2) 39.4 0.18 5.4 ------------------------------------------------------------------------- YTD 2009 Cash flow from Operating Activities 354.2 1.51 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Excludes non-cash portion of Whole Unit Plan expense recorded in operating costs. (2) Includes the changes in non-cash working capital and expenditures on site restoration and reclamation. &gt;&gt; </pre> <p>2009 Cash Flow from Operating Activities Sensitivity </p> <p>Table 7 illustrates sensitivities to pre-hedged operating income items with operational changes and changes to the business environment and the resulting impact on cash flows from operating activities in total and per trust unit: </p> <pre> &lt;&lt; Table 7 ------------------------------------------------------------------------- Impact on Annual Cash flow from operating activities(2) Business Environment Assumption Change $/Unit ------------------------------------------------------------------------- Oil price (US$WTI/bbl)(1) $ 60.00 $ 1.00 $ 0.04 Natural gas price (Cdn$AECO/mcf)(1) $ 4.35 $ 0.10 $ 0.02 Cdn$/US$ exchange rate(3) 1.15 $ 0.01 $ 0.03 Interest rate on debt % 3.90 % 1.0 $ 0.02 Operational Liquids production volume (bbl/d) 31,500 % 1.0 $ 0.02 Gas production volumes (mmcf/d) 189.0 % 1.0 $ 0.01 Operating expenses per boe $ 10.50 % 1.0 $ 0.01 Cash G&amp;A and LTIP expenses per boe $ 2.30 % 10.0 $ 0.02 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Analysis does not include the effect of hedging contracts. (2) Assumes constant working capital. (3) Includes impact of foreign exchange on crude oil prices which are presented in U.S. dollars. This amount does not include a foreign exchange impact relating to natural gas prices as they are presented in Canadian dollars in this sensitivity. &gt;&gt; </pre> <p>Production </p> <p>Production volumes averaged 62,824 boe per day in the third quarter of 2009 compared to 64,325 boe per day in the same period of 2008 as detailed in Table 8. The decrease in third quarter 2009 production is a result of turnarounds at the Dawson property as well as natural production declines as a result of the decreased capital spending in 2009. </p> <pre> &lt;&lt; Table 8 ------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30 September 30 ------------------------------------------------------------------------- % % Production 2009 2008 Change 2009 2008 Change ------------------------------------------------------------------------- Light &amp; medium crude oil (bbl/d) 25,930 27,211 (5) 26,561 27,073 (2) Heavy oil (bbl/d) 991 1,298 (24) 981 1,299 (24) Natural gas (mmcf/d) 193.1 192.0 1 195.7 197.0 (1) NGL (bbl/d) 3,717 3,822 (3) 3,720 3,862 (4) ------------------------------------------------------------------------- Total production (boe/d)(1) 62,824 64,325 (2) 63,881 65,063 (2) % Natural gas production 51 50 51 50 % Crude oil and liquids production 49 50 49 50 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Reported production for a period may include minor adjustments from previous production periods. &gt;&gt; </pre> <p>Light and medium crude oil production decreased to 25,930 boe per day compared to 27,211 boe per day in 2008, while heavy oil production declined by 307 boe per day. When compared to the second quarter of 2009, the total crude oil production is relatively flat, as a result of a successful drilling program at Goodlands, Pembina and Ante Creek that helped to offset natural decline. Natural gas production was 193.1 mmcf per day in the third quarter of 2009, an increase of one per cent from the 192 mmcf per day produced in the third quarter of 2008 but down 3.5 per cent from the second quarter of 2009. The decrease in production over the second quarter of 2009 is due primarily to the planned turnaround completed at a third party facility that shut-in production at Dawson periodically throughout the month of September as well as other turnarounds in the Northern Alberta district that occurred during the month of July. </p> <p>The Trust's objective is to maintain annual production through the drilling of wells and other development activities to the full extent possible while giving considerations to capital spending constraints. In fulfilling this objective, there may be fluctuations in production depending on the timing of new wells coming on-stream. During the third quarter of 2009, the Trust drilled 17 gross wells (16 net wells) on operated properties; 11 gross oil wells, and six gross natural gas wells with a 100 per cent success rate. Of the wells drilled during the third quarter, two gas wells and seven oil wells were completed. Five of the oil wells completed were brought on production during the quarter. </p> <p>The Trust expects that 2009 full year production will average approximately 63,000 to 64,000 boe per day and that a total of 146 gross wells (120 net) will be drilled by ARC on operated properties with participation in an additional 54 gross wells to be drilled on the Trust's non-operated properties. The Trust estimates that the revised 2009 drilling program will add sufficient production from new wells to offset the majority of production declines on existing properties, however, overall production is expected to decrease by 1,000 to 2,000 boe per day relative to 2008 production levels. The planned capital expenditures for 2009 have been increased to approximately $365 million to take advantage of royalty incentives announced by the provinces of Alberta and British Columbia. </p> <p>Table 9 summarizes the Trust's production by core area: </p> <pre> &lt;&lt; Table 9 ------------------------------------------------------------------------- Three Months Ended September 30, 2009 Production Total Oil Gas NGL Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d) ------------------------------------------------------------------------- Central AB 7,218 1,370 28.4 1,106 N.E. BC &amp; N.W. AB 13,517 703 72.8 673 Northern AB 8,551 3,891 23.1 806 Pembina &amp; Redwater 13,609 9,298 19.9 992 S.E. AB &amp; S.W. Sask. 8,951 1,053 47.3 12 S.E. Sask. &amp; MB 10,978 10,605 1.5 127 ------------------------------------------------------------------------- Total 62,824 26,920 193.0 3,716 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 N.E. BC &amp; N.W. AB 12,241 749 65.6 556 Northern AB 9,464 4,363 24.6 997 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 64,235 28,510 192.0 3,822 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Provincial references: AB is Alberta, BC is British Columbia, Sask. is Saskatchewan, MB is Manitoba, N.E. is northeast, N.W. is northwest, S.E. is southeast and S.W. is southwest. &gt;&gt; </pre> <p>Table 9a summarizes the Trust's production by core area for the nine months of 2009: </p> <pre> &lt;&lt; Table 9a ------------------------------------------------------------------------- Nine Months Ended September 30, 2009 Production Total Oil Gas NGL Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d) ------------------------------------------------------------------------- Central AB 7,089 1,281 28.2 1,108 N.E. BC &amp; N.W. AB 13,868 722 74.9 673 Northern AB 9,005 4,072 24.6 837 Pembina &amp; Redwater 13,540 9,374 19.2 962 S.E. AB &amp; S.W. Sask. 8,923 1,016 47.4 13 S.E. Sask. &amp; MB 11,456 11,076 1.5 127 ------------------------------------------------------------------------- Total 63,881 27,541 195.8 3,720 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 N.E. BC &amp; N.W. AB 12,492 811 66.4 601 Northern AB 10,058 4,662 26.7 952 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 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Provincial references: AB is Alberta, BC is British Columbia, Sask. is Saskatchewan, MB is Manitoba, N.E. is northeast, N.W. is northwest, S.E. is southeast and S.W. is southwest. &gt;&gt; </pre> <p>Revenue </p> <p>Revenue decreased to $239.2 million in the third quarter of 2009, $246.5 million lower than 2008 revenues of $485.7 million. The decrease in realized oil prices accounted for a $121.9 million decrease in revenues with only $9.9 million of the decrease attributable to lower oil volumes. Natural gas revenue decreased by $95.6 million which was almost entirely attributable to decreased realized prices as volumes were flat over the same period in 2008. </p> <p>A breakdown of revenue is outlined in Table 10: </p> <pre> &lt;&lt; Table 10 ------------------------------------------------------------------------- Revenue Three Months Ended Nine Months Ended September 30 September 30 % % ($ millions) 2009 2008 Change 2009 2008 Change ------------------------------------------------------------------------- Oil revenue 167.7 299.5 (44) 441.8 833.3 (47) Natural gas revenue 57.7 153.3 (62) 216.3 482.6 (55) NGL revenue 13.3 29.1 (54) 39.5 82.4 (52) ------------------------------------------------------------------------- Total commodity revenue 238.7 481.9 (50) 697.6 1,398.3 (50) Other revenue 0.5 3.8 (87) 2.0 7.3 (73) ------------------------------------------------------------------------- Total revenue 239.2 485.7 (51) 699.6 1,405.6 (50) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Commodity Prices Prior to Hedging Table 11 ------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30 September 30 ------------------------------------------------------------------------- % % 2009 2008 Change 2009 2008 Change ------------------------------------------------------------------------- Average Benchmark Prices AECO gas ($/mcf)(1) 3.03 9.27 (67) 4.10 8.58 (52) WTI oil (US$/bbl)(2) 68.29 118.18 (42) 57.13 113.39 (50) Cdn$ / US$ exchange rate 1.10 1.04 6 1.16 1.02 14 WTI oil (Cdn$/bbl) 74.90 121.77 (38) 66.08 114.99 (43) ------------------------------------------------------------------------- ARC Realized Prices Prior to Hedging Oil ($/bbl) 67.74 114.20 (41) 58.77 107.20 (45) Natural gas ($/mcf) 3.25 8.68 (63) 4.05 8.94 (55) NGL ($/bbl) 38.92 82.87 (53) 38.89 77.91 (50) ------------------------------------------------------------------------- Total commodity revenue before hedging ($/boe) 41.31 81.42 (49) 40.00 78.44 (49) Other revenue ($/boe) 0.08 0.64 (88) 0.11 0.40 (73) ------------------------------------------------------------------------- Total revenue before hedging ($/boe) 41.39 82.06 (50) 40.11 78.84 (49) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Represents the AECO monthly posting. (2) WTI represents posting price of West Texas Intermediate oil. &gt;&gt; </pre> <p>Oil prices continued to recover in the third quarter of 2009 with US$WTI prices averaging $68.29 as compared to $51.46 for the first half of 2009. Despite this recovery, prices in the third quarter of 2009 were down 42 per cent compared to the same period of 2008 as detailed in Table 11. This large decrease was partially offset by the weakening of the Canadian dollar compared to the U.S. dollar; however, some widening of the price differentials further eroded the Trust's realized oil price. The Trust's oil production consists predominantly of light and medium crude oil while heavy oil accounts for less than five per cent of the Trust's crude oil production. The realized price for the Trust's oil, before hedging, was $67.74 per boe, a 41 per cent reduction over the third quarter 2008 realized price of $114.20 per boe. </p> <p>Natural gas prices softened throughout the third quarter of 2009. Alberta AECO Hub natural gas prices, which are commonly used as an industry reference, averaged $3.03 per mcf in the third quarter of 2009 compared to $9.27 per mcf in the same period of 2008. ARC's realized gas price, before hedging, decreased by 63 per cent to $3.25 per mcf compared to $8.68 per mcf in the third quarter of 2008. ARC's realized gas price is based on prices received at the various markets in which the Trust sells its natural gas. ARC's natural gas sales portfolio consists of gas sales priced at the AECO monthly index, the AECO daily spot market, eastern and mid-west United States markets and a portion to aggregators. Natural gas prices have started to recover in the fourth quarter of 2009 with posted prices in the month of October registering over $5 per mcf. In addition, the forward curve for natural gas prices has strengthened to reflect 2010 prices of over $6 per mcf. Management is pursuing strategic initiatives to capitalize on strong forward prices, where possible in order to protect the economics of the 2010 capital program. </p> <p>Prior to hedging activities, ARC's total realized commodity price was $41.31 per boe in the third quarter of 2009, a 49 per cent decrease from the $81.42 per boe received prior to hedging in the third quarter of 2008. </p> <p>Risk Management and Hedging Activities </p> <p>ARC maintains 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. </p> <p>Gain or loss on risk management contracts comprise realized and unrealized gains or losses on risk management contracts that do not meet the accounting definition requirements of an effective hedge, even though the Trust considers all risk management contracts to be effective economic hedges. Accordingly, gains and losses on such contracts are shown as a separate category in the statement of income. </p> <p>Lower natural gas prices in the third quarter of 2009 resulted in realized cash gains of $10.4 million on natural gas risk management contracts as the Trust's contracted prices were higher than market prices during the quarter. Realized cash losses of $3.6 million were recorded on the Trust's crude oil risk management contracts as a result of premiums paid during the third quarter of 2009 and small losses recorded on the Trust's fixed price swap contracts where the market oil price rose above the contracted price. </p> <p>ARC's third quarter 2009 results include an unrealized total mark-to- market loss of $0.7 million with a net unrealized mark-to-market loss position of $4.8 million as at September 30, 2009. The net loss position is mostly attributed to losses on the Trust's power and natural gas contracts and offset by gains on the Trust's crude oil contracts. The mark-to-market values represent the market price to buy-out the Trust's contracts as of September 30, 2009 and may differ from what will eventually be realized. </p> <p>In the third quarter of 2008, the Trust recorded a significant unrealized gain on risk management contracts as commodity prices, and in particular oil prices, declined significantly at the end of the quarter when compared to the previous reporting period. The realized cash losses in the third quarter of 2008 were mostly attributable to crude oil contracts where the market prices were in excess of ARC's contracted price. </p> <p>Table 12 summarizes the total gain (loss) on risk management contracts for the third quarter of 2009 as compared to the same period in 2008: </p> <pre> &lt;&lt; Table 12 ------------------------------------------------------------------------- Risk Management Crude Foreign Q3 Q3 Contracts Oil &amp; Natural Curr- Inter- 2009 2008 ($ millions) Liquids Gas ency Power(3) est Total Total ------------------------------------------------------------------------- Realized cash (loss) gain on contracts(1) (3.6) 10.4 0.2 (0.3) - 6.7 (34.3) Unrealized (loss) gain on contracts(2) 12.1 (11.4) - (1.4) - (0.7) 187.5 ------------------------------------------------------------------------- Total (loss) gain on risk management contracts 8.5 (1.0) 0.2 (1.7) - 6.0 153.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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) Amounts presented in Table 12 exclude a $0.3 million realized loss and an unrealized loss of $0.4 million for the Trust's power contracts that have been designated as effective hedges for accounting purposes. Realized gains and losses on these contracts are recorded in operating costs and unrealized gains and losses are recorded in the Consolidated Statement of Comprehensive Income and Accumulated Other Comprehensive Income. &gt;&gt; </pre> <p>Table 12a summarizes the total gain (loss) on risk management contracts for the first nine months of 2009 as compared to the same period in 2008: </p> <pre> &lt;&lt; Table 12a ------------------------------------------------------------------------- Risk Management Crude Foreign YTD YTD Contracts Oil &amp; Natural Curr- Inter- 2009 2008 ($ millions) Liquids Gas ency Power(3) est Total Total ------------------------------------------------------------------------- Realized cash (loss) gain on contracts(1) (10.5) 26.6 1.0 (0.8) 4.8 21.1 (108.5) Unrealized (loss) gain on contracts(2) 7.2 (4.9) - (4.8) (5.4) (7.9) 26.0 ------------------------------------------------------------------------- Total (loss) gain on risk management contracts (3.3) 21.7 1.0 (5.6) (0.6) 13.2 (82.5) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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) Amounts presented in Table 12a exclude a $1.1 million realized loss and an unrealized loss of $3.6 million for the Trust's power contracts that have been designated as effective hedges for accounting purposes. Realized gains and losses on these contracts are recorded in operating costs and unrealized gains and losses are recorded in the Consolidated Statement of Comprehensive Income and Accumulated Other Comprehensive Income. &gt;&gt; </pre> <p>The Trust currently limits the amount of forecast production that can be hedged to a maximum 50 per cent with the remaining 50 per cent of production being sold at market prices. The following table is an indicative summary of the Trust's positions for crude oil and natural gas as at September 30, 2009. </p> <pre> &lt;&lt; Table 13 ------------------------------------------------------------------------- Hedge Positions As at September 30, 2009(1)(2) Q4 2009 Q1 2010 ------------------------------------------------------------------------- Crude Oil US$/bbl bbl/day US$/bbl bbl/day ------------------------------------------------------------------------- Sold Call 83.02 7,000 96.50 5,000 Bought Put 67.61 9,500 75.05 5,000 Sold Put 42.89 2,500 - - ------------------------------------------------------------------------- Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day ------------------------------------------------------------------------- Sold Call 5.52 93,370 6.80 5,000 Bought Put 4.84 93,370 6.80 5,000 Sold Put 4.50 20,000 - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Hedge Positions As at September 30, 2009(1)(2) Q2 2010(3) Q3-Q4 2010 ------------------------------------------------------------------------- Crude Oil US$/bbl bbl/day US$/bbl bbl/day ------------------------------------------------------------------------- Sold Call 96.50 4,000 96.50 4,000 Bought Put 75.05 4,000 75.05 4,000 Sold Put - - - - ------------------------------------------------------------------------- Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day ------------------------------------------------------------------------- Sold Call 6.80 5,000 6.80 5,000 Bought Put 6.80 5,000 6.80 5,000 Sold Put - - - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- (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. (2) In addition to positions shown here, ARC has entered into additional basis positions until October 2012, an energy equivalent swap until December 31, 2009. Please refer to note 8 in the Notes to the Consolidated Financial Statements for full details of the Trust's risk management positions as of September 30, 2009. (3) The natural gas contract listed for 2010 is a fixed price swap starting in 2010 and ending in December 2013. During the quarter, the Trust took advantage of favorable forward curve pricing for natural gas and entered into a long-term contract for a small portion of future forecast production. &gt;&gt; </pre> <p>Table 13 should be interpreted as follows using the fourth quarter 2009 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. </p> <pre> &lt;&lt; - If the market price is below $42.89, ARC will receive $67.61 less the difference between $42.89 and the market price on 2,500 bbl per day. For example if the market price is $42.85, the Trust will receive $67.57 on 2,500 bbl per day. - If the market price is between $42.89 and $67.61, ARC will receive $67.61 on 9,500 bbl per day. - If the market price is between $67.61 and $83.02, ARC will receive the market price on 9,500 per day. - If the market price exceeds $83.02, ARC will receive $83.02 on 7,000 per day. &gt;&gt; </pre> <p>Operating Netbacks </p> <p>The Trust's operating netback, before realized hedging gains and losses, decreased 57 per cent to $24.35 per boe in the third quarter of 2009 compared to $56.07 per boe in the same period of 2008. The decrease in netbacks is due most significantly to the reduced commodity prices and the corresponding reduction in royalties in the period. </p> <p>The Trust's third quarter 2009 netback, after realized hedging gains and losses, was $25.47 per boe, a 49 per cent decrease from the same period in 2008. The 2009 netback includes net gains recorded on the Trust's crude oil and natural gas risk management contracts during the quarter of $1.12 per boe compared to a net loss of $5.79 per boe recorded for the same period in 2008. </p> <p>The components of operating netbacks are summarized in Table 14 and 14a: </p> <pre> &lt;&lt; Table 14 ------------------------------------------------------------------------- Crude Heavy Q3 2009 Q3 2008 Netbacks Oil Oil Gas NGL Total Total ($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe) ------------------------------------------------------------------------- Weighted average sales price 67.98 61.54 3.25 38.92 41.31 81.42 Other revenue - - - - 0.08 0.64 ------------------------------------------------------------------------- Total revenue 67.98 61.54 3.25 38.92 41.39 82.06 Royalties (10.71) (7.52) (0.40) (12.65) (6.53) (15.00) Transportation (0.14) (0.64) (0.25) - (0.83) (0.80) Operating costs(1) (13.58) (9.79) (1.18) (9.37) (9.68) (10.19) ------------------------------------------------------------------------- Netback prior to hedging 43.55 43.59 1.42 16.90 24.35 56.07 Realized gain (loss) on risk management contracts(2) (1.63) - 0.58 - 1.12 (5.79) ------------------------------------------------------------------------- Netback after hedging 41.92 43.59 2.00 16.90 25.47 50.28 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Table 14a ------------------------------------------------------------------------- YTD YTD Crude Heavy 2009 2008 Netbacks Oil Oil Gas NGL Total Total ($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe) ------------------------------------------------------------------------- Weighted average sales price 58.99 52.59 4.05 38.89 40.00 78.44 Other revenue - - - - 0.11 0.40 ------------------------------------------------------------------------- Total revenue 58.99 52.59 4.05 38.89 40.11 78.84 Royalties (8.73) (4.73) (0.47) (12.33) (5.86) (14.18) Transportation (0.15) (1.12) (0.26) - (0.88) (0.77) Operating costs(1) (13.11) (12.52) (1.34) (8.45) (10