2003 MESSAGE TO UNITHOLDERS | 2003 FINANCIAL AND OPERATING STATS • MESSAGE TO UNITHOLDERS ARC Energy Trust (“ARC” or “the Trust”) had an extremely eventful year in 2003. A combination of strong commodity prices, the largest acquisition ever completed by ARC (Star Oil and Gas Ltd. (“Star”)) and excellent drilling results contributed to a record year for the Trust. ARC attained historic highs in its unit price; record production, revenue and cash flow; and significantly strengthened its balance sheet during the year with a year-end debt to cash flow ratio of 0.7 times. Most importantly, 2003 marked the completion of a strategic transformation of the Trust. Since 2001, the Trust has evolved from a primarily acquisition company to one with a large inventory of internal development opportunities capable of sustaining production for an extended period of time without acquisitions. When ARC acquired Startech Energy Inc. (“Startech”) in 2001, our inventory of development opportunities expanded dramatically. More importantly, the staff who joined ARC from Startech significantly strengthened our technical team, especially in the areas of geology and geophysics. This allowed us to pursue new opportunities for the development of our asset base and to make larger value adding acquisitions for the Trust. As a result, 2002 was a year in which we significantly expanded our drilling activities, particularly in Ante Creek where we developed a tight Triassic Montney oil reservoir with great success. Heading into 2003, the Trust’s capital budget for internal development projects was set at a record $115 million that was expected to maintain production at a level just below that achieved in 2002. Early in 2003, Star became available for acquisition and ARC pursued this very unique opportunity. Star was a gas focused company with an intriguing combination of mature and very immature properties with significant further development potential. Given the size of Star (approximately 22,000 boe/d of production), a limited number of companies had the size and financial capacity to pursue the opportunity. As a result, competition was restricted and ARC’s technical expertise in Star’s two main operating areas gave us a unique advantage in evaluating the assets. A key property gained in the acquisition was Dawson in northeast British Columbia. Dawson has an estimated 800 billion cubic feet of original gas-in-place in the tight Triassic Montney formation underlying lands in which ARC now owns virtually a 100 per cent interest. ARC’s knowledge and experience in Ante Creek (also a tight Montney formation) was crucial to our assessment of the potential of the Dawson property. Although it is still highly uncertain what the ultimate recovery of the large natural gas resource in Dawson will be, ARC and its independent evaluator have only recognized a 14 per cent proved reserve recovery for the property. We are confident that the ultimate recovery will significantly exceed this level following ongoing development of the field. The other key Star property was the Hatton area (which includes Horsham and Crane Lake) in southwest Saskatchewan. Prior to the Star acquisition, ARC’s main natural gas producing areas were Brooks and Jenner in southeast Alberta through which ARC had developed significant shallow gas operating expertise. Hatton is a similar operating area east of Jenner in Saskatchewan. The drilling density on the Hatton area lands is roughly half of that of other operators in the area. ARC identified up to 1,000 potential infill drilling locations on Star’s Hatton area lands, only a small component of which were included in our evaluation at the time of the acquisition. It is our expectation that most, if not all, of these wells will ultimately be drilled and will add significant value over time. A wild card in the Star acquisition is the Prestville property in northwest Alberta. Star drilled a discovery well into a new Slave Point light oil reservoir just prior to completion of the acquisition. Follow-up drilling in 2003 by ARC has resulted in partial delineation of a very prolific reservoir with three wells. These wells are capable of producing 600 to 800 barrels per day of oil each with minimal pressure drawdown, which indicates much higher production rates could be achieved under normal operating pressures. In excess of 10 per cent of our 2004 budget will be directed to more fully delineating and understanding this potentially significant new property. The combination of Star’s undeveloped properties and existing opportunities on ARC’s pre-Star lands has resulted in the largest inventory of development opportunities in the Trust’s history. Also of significance is the fact that Star had an excellent technical team which, combined with ARC’s existing staff, will allow us to pursue these opportunities. Post-completion of the Star acquisition, ARC’s 2003 capital expenditures grew to $156 million while our budget for 2004 has been set at a record $175 million excluding acquisitions. The 2004 capital expenditures are forecast to result in production levels at or above those achieved in 2003 being maintained throughout 2004. Significant further development opportunities have already been identified for 2005 on our existing lands. It is with this outlook for the next two years that the strategic transformation to an internal development focused trust supplemented by strategic, opportunistic acquisitions has been achieved. This makes ARC one of only a few trusts in the sector with this capability. National Instrument 51-101 Effective September 30, 2003, The Alberta Securities Commission implemented new reserve reporting guidelines for all publicly traded oil and gas producers. The new guidelines known as National Instrument 51-101 (“NI 51-101”) standardize disclosure requirements for all reporting issuers involved in upstream oil and gas activities. The goal of NI 51-101 is to increase public and investor confidence in the reserves information reported by public companies and to harmonize the reporting format. The new reporting format will allow investors to more readily understand the assets of the company and facilitate comparisons to other companies. Under the new guidelines, reserves reporting is more specific and subject to more strictly defined reserves definitions for proved and probable categories. One of the most notable changes under NI 51-101 is the redefinition of probable reserves to now reflect risk such that the “proved plus probable” category is now characterized as the “best estimate” of reserves and in ARC’s view is essentially equivalent to prior years’ “established” reserves. Despite the more stringent requirements of NI 51-101, ARC achieved positive reserve revisions of 4.2 per cent and 6.2 per cent in the proved and proved plus probable reserve cases, respectively. In doing so, ARC recorded the seventh consecutive year in which the Trust has recorded positive reserve revisions; we remain the only trust to achieve this feat. Finding, Development and Acquisition Costs ("FD&A") The cost structure for all oil and gas companies operating in Canada has been rising steadily for the past number of years. Most significantly, FD&A costs for 2003 are expected to be at the highest level ever for our industry. ARC has been able to buck this trend. After completing the largest acquisition in our history, as well as executing the largest development capital budget in our history, ARC’s all in FD&A costs for 2003 were $8.50 per barrel of oil equivalent (“boe”) for proved plus probable reserves using historic definitions for FD&A costs, which is eight per cent lower than our FD&A costs of $9.27 per boe in 2002. All oil and gas reporting issuers in Canada must now report their reserves using the new NI 51-101 guidelines under which the method for calculating finding and development costs ("FD&A") has changed compared to prior years. The new F&D calculation includes all future development capital required to bring the proved undeveloped and probable reserves to production. For a trust, FD&A is a more relevant measure, therefore ARC has chosen to report FD&A costs. ARC’s annual FD&A costs are $10.54/boe for 2003 on a proved plus probable basis, down slightly from $10.79/boe in 2002 on an established basis. The calculation takes into account the reserves added through development activity (additions and revisions) and acquisitions, as well as the capital for these activities and all future development capital. At the time of writing this report, numerous companies had not yet reported their year-end reserves and FD&A costs. However, indications are that ARC’s costs will be among the lowest in the industry. Balance Sheet Strength The Trust’s capital expenditures in 2003 were a record $716 million which include $156 million in development expenditures and $560 million in net acquisitions. The development capital expenditures were funded 68 per cent ($107 million) out of cash flow and the balance with debt. The Trust also issued $640 million in new equity net of issuance costs that was used to fund the net acquisitions and reduce debt. As a result, the Trust’s year-end debt was reduced to $262 million ($348 million at year-end 2002), which represented nine per cent of total capitalization (19 per cent in 2002) and a debt to cash flow ratio of 0.7 times (1.6 times in 2002). Therefore, despite the largest capital program in the Trust’s history, we were able to significantly strengthen our balance sheet during 2003. As a result, the Trust is well positioned to pursue opportunities which may arise in 2004. John P. Dielwart President and Chief Executive Officer • How do our 2003 numbers measure up?  Click here to find out. View another year: 2007 | 2006 | 2005 | 2004 | 2003 | 2002 | 2001 | 2000 | 1999 | 1998 | 1997 | 1996