Nexen has provided a capital program review as part of its fourth quarter and annual financial results.
Capital Program Review
We invested $702 million in the UK last year. This included approximately $250 million at Buzzard and added 29 million boe of proved reserves. Successful drilling and production performance resulted in increases in both reservoir size and overall recovery factor which led to these proved reserve adds. These additions were offset by negative economic revisions of 10 mmboe due to low year-end prices.
"Buzzard has been a great project for us and is generating exceptional value for shareholders," said Romanow. "Since we first acquired this asset, we have successfully increased our proved plus probable reserves by 101 million boe or 49%, and extended our production plateau by over three years. The facility is consistently operating above original design expectations and even at US$40/bbl Brent, we generate over $1 billion of annual pre-tax cash flow."
In 2009, Buzzard will continue to be a significant contributor to our cash flow and production volumes. Throughout the year, we will continue construction of the fourth platform containing production sweetening facilities designed to handle higher levels of hydrogen sulphide. During the third quarter, we plan to install the jackets for this platform and complete tie-in operations, pending installation of the topsides. This will result in about one month of downtime which coincides with a six week planned slowdown of the Forties pipeline.
Our Ettrick development in the North Sea is progressing towards first oil in the next few months. In 2008, we invested approximately $260 million and to date we have recognized 20 million boe of proved plus probable reserves here. This is after 12 million boe of negative proved revisions that we incurred in 2008. These revisions relate to low year-end oil prices and disappointing drilling results that lowered our reserve estimates. The Ettrick development consists of a leased floating production, storage and offloading vessel (FPSO) designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas. We expect Ettrick to add approximately 10,000 boe/d to our 2009 production volumes. We also have a discovery at Blackbird which could be a future tie-back to Ettrick. We have no proven reserves booked for Blackbird. In 2009, we plan to drill an appraisal well here. We operate both Ettrick and Blackbird, with an 80% working interest in each.
We recently drilled a successful appraisal well at Rochelle on Block 15/27 in the North Sea. The well encountered 77 feet of net pay, was drill stem tested and flowed at an average restricted rate of 41 mmcf/d of gas and 2,300 bbls/d of oil condensate from a 72/64-inch fixed choke. We are evaluating future appraisal and fast track development options and have a 44% non-operated working interest in this well.
Elsewhere, we are assessing future appraisal and development alternatives for the growing Golden Eagle area. This area includes exciting discoveries at Golden Eagle, Pink and most recently, Hobby where initial results indicate a significant column of high-quality net pay which is at the high end of our pre-drill expectations. We are planning to drill multiple sidetracks to determine the extent of both this discovery and Golden Eagle. Hobby is located on Block 20/1N approximately 1.5 km west of the Golden Eagle discovery. We have a 34% interest in both Hobby and Golden Eagle, 46% interest in Pink and operate all three. We have identified additional prospects in the area and have plans for further exploratory and appraisal drilling this year.
"Our strategy in the UK is working well and we have had exciting success with our exploration and exploitation program," commented Romanow. "We have a number of satellite discoveries that are in the same areas as our large operations at Buzzard, Scott/Telford and Ettrick. This infrastructure provides opportunities for quick cost effective tie-backs."
Yemen remains a significant asset for us and continues to generate cash flow in excess of capital requirements. In 2008, we invested $101 million and added 12 million boe of proved reserves. We will continue to maximize the value of these assets over their remaining contract terms and expect 2009 annual production of between 40,000 and 45,000 boe/d, before royalties.
Development of the Usan field, offshore West Africa, is underway with first production expected in 2012. In 2008, our capital investment at Usan on block OML 138 focused on detailed engineering, procurement and the initial fabrication of equipment. The development of Usan includes a FPSO with the ability to process 180,000 bbls/d and store up to two million barrels of oil. In 2009, we are scheduled to start fabrication of the FPSO hull and topside facilities, begin development drilling, and complete detailed engineering and procurement. We are also evaluating plans for further exploration on this block. We have a 20% interest in exploration and development along with Total E&P Nigeria Limited (20% and Operator), Chevron Petroleum Nigeria Limited (30%) and Esso Exploration and Production Nigeria (Offshore East) Limited (30%).
In the fourth quarter of 2008, Nigerian authorities approved the acquisition of interests in offshore block OPL 223. We have a 20% funding interest and 18% beneficial interest in this block. Our partners are Total E&P Nigeria Limited (18% and Operator), ChevronTexaco Nigeria Deepwater F Limited (27%), Esso Exploration and Production (Upstream) Limited (27%) and Nigerian Petroleum Development Company Limited (10% carried interest). During 2009, we plan to advance evaluation of the prospects on this block.
Other International also includes our producing assets in Colombia and our exploration program in the Norwegian North Sea.
Development of Longhorn continues to progress with first production expected in mid 2009. This development comprises four sub-sea wells tied in to the ENI operated Corral Platform, previously known as the Crystal Platform. We expect peak production rates in excess of 200 mmcf/d gross (50 mmcf/d net to us) by year end. In 2008, we invested $87 million developing Longhorn and to date have recognized 13 million boe of proved plus probable reserves here. We have a 25% non-operated working interest in Longhorn and ENI is the operator.
In 2008, our exploration program primarily focused on the deep-water. In the Eastern Gulf of Mexico, we drilled the Fredericksburg exploration well. Target sands were reached but we did not encounter commercial hydrocarbons. This was the third prospect to be drilled in the area following earlier successes at Vicksburg and Shiloh. We remain optimistic about the potential of this emerging play and expect to drill up to two exploration wells and one appraisal well in the area in 2009. In addition, we have a feasibility study underway to assess development options for Vicksburg. We have a 25% interest in Vicksburg and a 20% interest in Shiloh with Shell operating both.
At our Cote de Mer prospect, located on the Louisiana coast, exploratory drilling was interrupted by hurricanes Gustav and Ike. Following successful pipe recovery operations, the well was sidetracked to a depth of 21,700 feet, and penetrated the target zone. We continue to be encouraged by the logging data received to date, and are attempting to drill the remaining 600 feet of the target interval. We have a 37.5% working interest in this prospect.
In 2008, we invested $164 million to add production volumes from the Green Canyon 6 area and to recomplete wells on our producing properties.
As conventional basins in Canada mature, we are focusing our investment on unconventional resource plays such as shale gas and CBM. In northeast British Columbia, we have a material land position of approximately 126,000 acres with a 100% working interest in an emerging Devonian shale gas play. This play has the potential to be one of the most significant shale gas plays in North America. Our landholdings include approximately 88,000 acres in the Dilly Creek area of the Horn River basin. In 2008, we invested approximately $180 million to drill, complete and test wells, and build infrastructure. One horizontal well was completed and tied in last winter and is producing at rates in line with our expectations and competitor wells. We expect to complete and tie-in two wells later this winter. We continue to construct all season roads to provide year-round access to our lands. In 2009, we plan to enhance our understanding of optimal drilling and fracing techniques for this play with an investment plan that includes drilling and testing multiple wells from a single pad. We expect three of these wells to be drilled and completed by mid year and on production before winter. The remaining wells will be drilled later subject to favorable economic and financial conditions. As previously announced, we estimate our Dilly Creek lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resource. Further appraisal activity is required before we can finalize these estimates, establish commerciality and book reserves.
"We are encouraged by the manner in which Horn River development is progressing," said Romanow. "By working together with our peers on the construction of roads, pipelines and processing facilities, we are achieving economies of scale and reducing our environmental footprint."
In 2008, we invested approximately $115 million in exploration and development activities on our CBM lands and recognized 10 million boe of proved reserves. To date, we have recognized approximately 40 million boe of proved plus probable CBM reserves. We expect our CBM reserves to grow over the coming years as additional wells are drilled, development work progresses and more production history is obtained. Our CBM production continues to increase as existing wells dewater and we bring new ones on stream. In 2008, our production increased 65% and we exited the year producing approximately 50 mmcf/d. Performance is in line with expectations and underscores the increasing value of our CBM assets.
Elsewhere in Canada, we increased our proved reserves by 3 million boe but these additions were offset by negative economic revisions of 27 million boe largely relating to our conventional heavy oil properties. These economic revisions were determined in accordance with SEC rules that require the use of year-end commodity prices and operating costs even though we believe year-end operating costs do not reflect the current economic downturn and low commodity price environment.
"With conventional basins declining in Canada, we have allocated approximately 80% of our Canadian capital investment, excluding oil sands, to our unconventional resource plays such as shale gas and CBM," commented Romanow. "Our strategy is to move early and we have built material land positions that would be difficult to replicate today. We believe the resource potential on our lands is significant. For example, shale gas alone could potentially double our proved reserves."
Insitu Oil Sands -- Long Lake
In 2008, we invested a total of $1.0 billion to develop our insitu oil sands resource. This included approximately $847 million on the first phase of Long Lake, $425 million of which related to the upgrader. At Long Lake, we added 19 million bbls of proved bitumen reserves based on further core-hole delineation of the lease. We also added 216 million bbls of probable bitumen reserves associated with delineation work relating to Phase 2 which we believe has substantial long-term value given the margin advantage our technology provides.
In late January 2009, we completed the acquisition of an additional 15% interest in the Long Lake project and the joint venture lands from OPTI Canada Inc. for $735 million. We also became sole operator of the resource and upgrader. We expect this will create operational efficiencies and reduce the cost of managing Long Lake. We now own 65% of the Long Lake project and joint venture lands. With the completion of this acquisition, our total company proved reserves have increased by approximately 9%. These additions will be booked in 2009.
"We are delighted with this transaction," stated Romanow. "We were able to increase our interest in a world-class asset that we know and understand well, and we were able to do this at less than sunk cost. This acquisition is a great example of how we are able to use our strong financial position to take advantage of opportunities to generate shareholder value."
We recently reached a significant milestone at Long Lake when we produced first Premium Synthetic Crude (PSC(TM)) from the upgrader. The main process units in the upgrader have been successfully started up and are operating. Syngas from the upgrader is being used in SAGD operations and this has significantly reduced the need for purchased natural gas. Currently, we are producing between 10,000 and 15,000 bbls/d gross of upgraded on-spec product. The upgrader is expected to ramp up to full design rates of approximately 60,000 bbls/d (39,000 bbls/d net to us) over the next 12 to 18 months. 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 production. This periodic downtime is normal and consistent with industry experience.
"We are very pleased to have Long Lake on stream," said Romanow. "The production of first synthetic crude proves our technology works. The upgrader is consistently operating at expected start-up rates, producing on-spec premium synthetic crude oil and generating syngas which we are using in our integrated operations for SAGD and hydrogen production. As production volumes ramp up, we will begin to see our $10/bbl cost advantage materialize. This is a world-class facility that we expect will provide steady and predictable production and cash flow for the next 40 years."
On the bitumen front, the reservoir is performing well but our overall ramp up has been affected by a variety of surface issues that have limited the amount of steam we have been able to inject into the reservoir over the past few months. Since steam injection rates directly impact bitumen production rates, when our ability to generate steam is limited, our bitumen production is lower. Most recently, our SAGD production stalled as a result of power disruptions, extreme cold weather and water treating issues. As we recover from power disruptions and cold weather, our production rates have increased. We are currently producing 20,000 bbls/d gross, the highest we have seen to date. With respect to water treating issues, we are working on solutions to get more heat into the front end of the water treating process to supplement the heat returns from the reservoir. Given steaming constraints, we have been forced to allocate our steam and accordingly we have 32 of the 81 well pairs on production. On average, these well pairs are producing at approximately 75% of their design rates after 11 months of SAGD operation. This is inline with expectations, as we expected a ramp up period of 12 to 18 months. The average steam to oil ratio (SOR) for these wells is currently less than 4.0. As we increase our steam capacity, we will bring on all remaining wells.
Phase 1 of Long Lake will develop approximately 10% of our oil sands inventory. The sanctioning of Phase 2 will depend on multiple factors including the initial performance of Phase 1, receiving regulatory approval for Phase 2 SAGD operations, receiving clarity on proposed climate change regulations, finalizing cost estimates and an improved economic environment. We therefore do not expect to sanction Phase 2 until mid 2010 at the earliest. In 2009, we plan to advance detailed engineering on the SAGD and upgrader facilities for Phase 2 of Long Lake and conduct core hole drilling to further delineate our leases.
At Syncrude, we invested $55 million in 2008 and converted 8 million boe of probable reserves to proved reserves. In 2009, we have one coker turnaround scheduled in the second quarter and expect annual production of between 20,000 and 25,000 bbls/d before royalties.
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