SAGD involves drilling two parallel horizontal wells, generally between 2,300 and 3,300 feet long, with about 16 feet of vertical separation. Steam is injected into the shallower well, where it heats the bitumen that then flows by gravity to the deeper producing well. The OrCrude™ technology, using conventional distillation, solvent de-asphalting and thermal cracking, separates the produced bitumen into partially upgraded sour crude oil and liquid asphaltenes. By coupling the OrCrude™ process with commercially available hydrocracking and gasification technologies, sour crude is upgraded to light (39° API) premium synthetic sweet crude oil, and the asphaltenes are converted to a low-energy, synthetic fuel gas. This gas is available as a low-cost fuel for generating steam and as a source of hydrogen for the hydrocracking process. The gas is also burned in a cogeneration plant to produce electricity for on-site use and sold to the provincial electricity grid. The energy conversion efficiency for our Long Lake upgrader is about 90% compared to 75% for a typical bitumen-fed coker, which we expect will provide us with an approximate $10/bbl operating cost advantage.

Our Strategic Advantage
Our integrated SAGD and upgrading process addresses three main economic hurdles of SAGD bitumen production: 1) the high cost of natural gas; 2) the cost and availability of diluent; and 3) the realized price of bitumen. With synthetic gas from the asphaltenes as fuel, we need to purchase very little additional natural gas. With the upgrading facilities on site, expensive diluent is not required to transport the bitumen to market. By upgrading the bitumen into a highly desirable refinery feedstock or diluent supply, the end product commands light-sweet crude oil premium pricing.

Project Milestones and Costs
The Long Lake Project received regulatory approval in 2003 and Nexen board approval in 2004. Field construction of the SAGD and upgrader facilities began in 2004. In 2006, we substantially completed module and site construction of the SAGD facilities and in 2007, we began injecting steam into the well pads. We continued to steam the SAGD well pairs and began turning wells over to SAGD production in 2008. In 2008, we produced 3,900 bbls/d of bitumen before royalties (3,900 after royalties) and are currently producing approximately 20,000 bbls/d (13,000 net to us) as of January 2009. The first several months of steam injection largely involves heating the reservoir, followed by a ramp up of bitumen production to peak rates over 12 to 24 months. The reservoir behavior is meeting our expectations. At the start of production, steam-to-oil ratios are high but will decline as bitumen production ramps up to our target rates. We expect the steam-to-oil ratio to average approximately 3.0 over the long-term.

We completed construction of the upgrader in 2008 and began commissioning for commercial operations. Production of premium synthetic crude oil from the upgrader began in late January 2009. We expect that it will take approximately 12 to 18 months to reach the upgrader design capacity. As the upgrader ramps up to full capacity, we expect that there will be periods of downtime as we work through the early stages of operation. This periodic downtime is normal following initial facility start-up and consistent with industry experience. During the bitumen ramp up period, we are purchasing third-party bitumen to take advantage of excess upgrading capacity. Production capacity for the first phase of Long Lake is approximately 60,000 bbls/d (39,000 net at a 65% working interest) of premium synthetic crude. We expect to maintain production over the project’s life, estimated at 40 years, by periodically drilling additional SAGD well pairs.

Long Lake’s total capital costs increased since project sanctioning due to design enhancements and industry cost pressures. As a result, the final cost of Long Lake increased from $3.8 billion to $6.4 billion ($3.2 billion net to us before acquiring an additional 15% interest in January 2009). Despite capital cost increases, we still expect to achieve positive economic returns which benefit from a significant operating cost advantage. Combined SAGD, cogeneration and upgrading operating costs are expected to average about $22/bbl, substantially lower than coking or other upgrading processes as a result of the reduced need to purchase natural gas. We expect ongoing capital to average between $5/bbl and $10/bbl depending on well spacing, well length and recovery factor. The full-cycle capital costs of producing and upgrading bitumen using this technology are comparable to those for surface mining and coking upgrading on a barrel-of-daily production basis.