Nexen (NXY) Update 2010 Budget, Long Lake Oil Sand Project, Offshore West Africa, and Announces Owowo Discovery
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Nexen (NYSE: NXY) continues to see positive results at Long Lake following the successful completion of the turnaround program in September. As we move into 2010, our priorities include the ramp up of Long Lake, sanctioning our discoveries in the North Sea, the continued improvement of our Horn River shale gas returns, the development of our offshore Usan project and ongoing exploration in our core areas.
Long Lake Project Update
At Long Lake, we have achieved a number of major milestones over the past year. Our gasification process is working as designed, creating a low cost fuel source which reduces our need to purchase natural gas for operations. Once the project is fully ramped up, it generates a significant margin advantage over our peers and we maintain this advantage even at current gas prices.
The upgrader is fully operational. We are approaching design yields and we have successfully produced over 1.5 million barrels of the highest quality synthetic crude in North America. Upgrader run times are increasing and in November, improved reliability allowed us to process 95% of our bitumen production.
Now that all components of the upgrader are operating as planned, we are focused on maximizing bitumen throughput. We will achieve this by increasing production volumes from our reservoir and by purchasing bitumen from third-parties to enhance returns.
The reservoir is responding to consistent steaming. Following a turnaround completed in September, the reliability of our water treating systems has improved substantially and currently, steam injection rates are at an all-time high of approximately 100,000 bbls/d. We are injecting steam into over 70 well pairs with 50 on production and the remainder circulating steam in advance of becoming producers. This is the highest number of wells that have received consistent steam to date. Prior to the turnaround, steam limitations only allowed us to inject steam consistently into approximately 35 well pairs.
Bitumen production levels are responding to the increased steam volumes and gross production is averaging approximately 17,000 bbls/d. As we start to circulate steam in more wells, our all-in steam-to-oil ratio (SOR) will remain high and is currently approximately 6 with about 20 wells receiving steam but not yet producing bitumen. The SOR of our producing wells is approximately 4.5 and trending down. With the ongoing installation of electric submersible pumps (ESPs), we are seeing improvements in our SORs. We continue to expect a long term SOR of 3 over the life of the project.
In addition to the continued installation of ESPs, our capital investment program in the coming year includes the drilling of two sustaining well pads in accordance with our full field resource development plan. These pads will be available to come on stream starting in 2012.
"We are still in the SAGD ramp up phase and are pleased with post-turnaround performance," said Marvin Romanow, Nexen's President and Chief Executive Officer. "Steaming reliability has improved and this is leading to higher bitumen production. We are confident that we will ramp up to full rates and demonstrate the significant value this project will deliver to our shareholders."
Owowo Discovery, Offshore West Africa
Earlier this year, we participated in the drilling of an exploration well in the southern portion of Oil Prospecting License (OPL) 223, offshore West Africa, which we are pleased to announce was successful.
The Owowo South B-1 well was drilled in a water depth of 670 metres and is located 20 kilometres northeast of the Usan field, currently under development. The well reached a total depth of 2,227 metres and discovered several oil bearing reservoirs containing light oil according to logs and other analysis.
Under the production sharing contract governing OPL 223, the Nigerian National Petroleum Corporation (NNPC) is concessionaire of the license, which is operated by Total Exploration & Production Nigeria Ltd. Nexen has an 18% interest in the discovery.
"We continue to have success with our exploration program offshore West Africa," said Romanow. "This discovery makes us more optimistic about our other exploration prospects."
2010 Budget
Our strategies are focused on oil sands, shale gas and conventional development and exploration in select basins. In 2010, we plan to advance these strategies by investing $2.5 billion and growing production after royalties by approximately 4 to 6% assuming the midpoint of our guidance.
Highlights of our 2010 budget are as follows:
We have purchased crude oil put options on 60,000 bbls/d of our 2010 production at a strike price of WTI US$50/bbl. Half of these puts settle monthly, with the remainder settling annually. We continue to look for opportunities to purchase more.
Production-Volumes Growing from New Core Assets
Over the last three years, our net production has grown at a robust annual compound rate of over 10%. This growth is expected to continue in 2010 as we ramp up Ettrick, Longhorn and Long Lake. Our capital program in 2010 advances our future growth as we move forward with the development of several major identified projects including Long Lake, Usan, Golden Eagle and Horn River shale gas. Our growth is being fueled by new, low royalty projects which more than offset high royalty production declines in Yemen.
We expect our annual 2010 production to range from 230,000 to 280,000 boe/d before royalties.
In the North Sea, we expect seven to ten days of downtime at Buzzard in the second quarter for the installation of the topsides relating to the fourth platform. This platform will allow us to handle higher levels of hydrogen sulphide over the life of the field and maintain peak production rates until 2014. Based on our production experience to date, we anticipate that start up of the new platform will not be required until 2011. If advanced to 2010, downtime associated with the start up could reduce annual volumes by 10,000 to 15,000 boe/d. This possibility is reflected in our guidance range.
Elsewhere in the North Sea, we anticipate drilling an additional development well at Telford to allow for higher production volumes from our recent Telford success. In the event these activities do not occur in 2010, annual volumes would be reduced by about 5,000 boe/d.
At Long Lake, we successfully completed our turnaround program in September. Our bitumen volumes are increasing and we are moving up the ramp up curve. Our SAGD and upgrading processes are highly integrated. This integration ultimately generates our significant margin advantage while supporting the environmentally responsible water management practices we have implemented. As a result, the pace at which we move up the ramp up curve comes with a degree of variability. This is reflected in our guidance range. While we expect periods of downtime at Long Lake as the project continues to ramp up, we anticipate continuing improvements in operational performance as we move towards full capacity.
In Yemen, production volumes are declining at rates similar to previous years.
Syncrude is planning one coker turnaround in 2010 for routine maintenance.
The timing of potential activities in the North Sea and the ramp up of Long Lake are the biggest contributors to the range of our guidance.
Conventional Development and Exploration-Investing In Our Future Growth
We plan to invest approximately $1.8 billion on conventional development and exploration with two-thirds relating to the development of existing assets and discoveries, and the remainder relating to exploration in our three core basins: the North Sea, offshore West Africa and the deep-water Gulf of Mexico. Our exploration plans include the potential drilling of 15 exploration and appraisal wells targeting a net unrisked resource potential of approximately 600 million boes.
North Sea Development
At Buzzard, the topsides for the fourth platform are scheduled for installation in the second quarter and start up is scheduled for 2011. This platform contains production sweetening facilities designed to handle higher levels of hydrogen sulphide which will allow us to maintain plateau until at least 2014. We also plan to drill five production wells and one injection well.
At Scott/Telford, we plan to follow up our 2009 development success with additional drilling and see further upside in the area with opportunities for quick tiebacks. Additional development drilling is planned at Ettrick along with appraisal drilling at Blackbird, which would be a tie-back to Ettrick.
Elsewhere in the UK North Sea, we are progressing the sanctioning of the Golden Eagle area development. As previously announced, estimates of gross contingent recoverable resource here range between 150 and 275 million boe. We expect development will support standalone facilities due to its size and be economic with oil prices as low as US$40/bbl.
"The Golden Eagle area is the largest discovery in the UK North Sea in the last 10 years after Buzzard," commented Romanow. "The development of Golden Eagle allows us to maintain or grow our North Sea production for the next five to ten years."
Offshore West Africa Development
Development of the Usan field on block OML 138, offshore Nigeria, is progressing well. The field development plan includes a floating production and storage offloading (FPSO) vessel with an oil storage capacity of two million barrels. In 2010, we expect to complete fabrication of the FPSO hull and most of the topsides. In addition, we will continue development drilling and well completion activities. The Usan field is expected to come on-stream in 2012 and will ramp up to a peak production rate of 180,000 bbls/d (36,000 bbls/d net to us). Nexen has a 20% interest in exploration and development on this block and Total E&P Nigeria Limited is the operator.
On the exploration front, we plan to drill a number of exciting opportunities in the North Sea including the North Uist prospect, west of the Shetland Islands, and the Brand prospect, our first well in Norway. Both of these prospects have higher target sizes than our typical North Sea targets. In addition, we plan to drill up to eight other exploration and appraisal wells. This includes Bluebell, a possible southern extension of the Buzzard field, and the Deacon and Bugle exploration wells, which take advantage of our regional success with stratigraphic traps.
In the Gulf of Mexico, we are currently drilling an appraisal well at Knotty Head and results are expected in the second quarter. The well is being drilled by our first contracted deep-water rig, the Ensco 8501. A second deep-water rig, the Ensco 8502, is scheduled to arrive in mid-2010. Access to these two deep-water rigs allows us to move forward with our exploration program and we expect to drill up to four exploration wells in 2010. High impact prospects that could be drilled include Kakuna, Angel Fire and Solitude, and a non-operated prospect, Catalina.
In Colombia, we plan to participate in the El Guadual exploration well and offshore West Africa, further exploration drilling may take place as early as 2010 following the recent success at Owowo.
"We are adding value by advancing our discoveries and building on our drilling success in the UK," said Romanow. "We have added experienced people to our talent pool and access to new deep-water rigs in the Gulf of Mexico will allow us to keep progressing our large inventory of exciting prospects."
Oil Sands-Keeping the Upgrader Full at Long Lake is a Priority
We plan to invest $400 million in oil sands in 2010 which includes $100 million at Syncrude. In the coming year, our capital program at Long Lake Phase 1 will focus on the drilling of sustaining well pads and the continued installation of ESPs in our SAGD wells.
With respect to future phases of Long Lake, we plan to continue engineering work on Phase 2 with timing of sanctioning dependent on multiple factors including the ramp up of Phase 1, receiving clarity on proposed climate change regulations, finalizing cost estimates and seeing more confidence in a sustained economic recovery.
Horn River Shale Gas-Continued Focus on Improving Returns
We have approximately 88,000 acres in the Dilly Creek area of the Horn River basin in northeast British Columbia with a 100% working interest. We estimate our lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of contingent recoverable resource which could double our existing company-wide total proved reserves.
With our recent drilling and completion program, we realized substantial cost savings and productivity improvements and are producing at rates in line with regional producers. We took advantage of improved equipment utilization, drilled longer wells, initiated more fracs per well and maintained an industry-leading frac pace of 26 fracs in 15 days while achieving a 100% success rate on our frac program.
In 2010, we plan to invest about $200 million on the drilling and completion of an eight-well pad and on processing facilities. Compared to our earlier programs, this pad will have longer horizontal wells with more fracs and higher frac densities (18 fracs per well). We expect to achieve shale gas volumes from this program of approximately 50 mmcf/d in early 2011. This program sets up a potential capital investment plan consisting of an 18-well pad which could commence drilling in 2010.
"Larger programs, increased well productivities and higher recovery factors result in lower unit costs and are the catalysts to driving higher Horn River returns," said Romanow. "I am pleased with our progress and our success is setting industry benchmarks."
Ongoing Strategic Review of our Portfolio
We regularly review the assets in our portfolio to ensure that they are aligned with our strategies and can compete for investment funding against other opportunities. We have identified a number of non-core assets for possible disposal, including parts of our marketing business, our heavy oil assets in Western Canada and our interest in the Canexus chemicals business. We expect that the disposition of non-core assets could generate over $1 billion in the next 12 to 24 months with timing dependent on market conditions.
Long Lake Project Update
At Long Lake, we have achieved a number of major milestones over the past year. Our gasification process is working as designed, creating a low cost fuel source which reduces our need to purchase natural gas for operations. Once the project is fully ramped up, it generates a significant margin advantage over our peers and we maintain this advantage even at current gas prices.
The upgrader is fully operational. We are approaching design yields and we have successfully produced over 1.5 million barrels of the highest quality synthetic crude in North America. Upgrader run times are increasing and in November, improved reliability allowed us to process 95% of our bitumen production.
Now that all components of the upgrader are operating as planned, we are focused on maximizing bitumen throughput. We will achieve this by increasing production volumes from our reservoir and by purchasing bitumen from third-parties to enhance returns.
The reservoir is responding to consistent steaming. Following a turnaround completed in September, the reliability of our water treating systems has improved substantially and currently, steam injection rates are at an all-time high of approximately 100,000 bbls/d. We are injecting steam into over 70 well pairs with 50 on production and the remainder circulating steam in advance of becoming producers. This is the highest number of wells that have received consistent steam to date. Prior to the turnaround, steam limitations only allowed us to inject steam consistently into approximately 35 well pairs.
Bitumen production levels are responding to the increased steam volumes and gross production is averaging approximately 17,000 bbls/d. As we start to circulate steam in more wells, our all-in steam-to-oil ratio (SOR) will remain high and is currently approximately 6 with about 20 wells receiving steam but not yet producing bitumen. The SOR of our producing wells is approximately 4.5 and trending down. With the ongoing installation of electric submersible pumps (ESPs), we are seeing improvements in our SORs. We continue to expect a long term SOR of 3 over the life of the project.
In addition to the continued installation of ESPs, our capital investment program in the coming year includes the drilling of two sustaining well pads in accordance with our full field resource development plan. These pads will be available to come on stream starting in 2012.
"We are still in the SAGD ramp up phase and are pleased with post-turnaround performance," said Marvin Romanow, Nexen's President and Chief Executive Officer. "Steaming reliability has improved and this is leading to higher bitumen production. We are confident that we will ramp up to full rates and demonstrate the significant value this project will deliver to our shareholders."
Owowo Discovery, Offshore West Africa
Earlier this year, we participated in the drilling of an exploration well in the southern portion of Oil Prospecting License (OPL) 223, offshore West Africa, which we are pleased to announce was successful.
The Owowo South B-1 well was drilled in a water depth of 670 metres and is located 20 kilometres northeast of the Usan field, currently under development. The well reached a total depth of 2,227 metres and discovered several oil bearing reservoirs containing light oil according to logs and other analysis.
Under the production sharing contract governing OPL 223, the Nigerian National Petroleum Corporation (NNPC) is concessionaire of the license, which is operated by Total Exploration & Production Nigeria Ltd. Nexen has an 18% interest in the discovery.
"We continue to have success with our exploration program offshore West Africa," said Romanow. "This discovery makes us more optimistic about our other exploration prospects."
2010 Budget
Our strategies are focused on oil sands, shale gas and conventional development and exploration in select basins. In 2010, we plan to advance these strategies by investing $2.5 billion and growing production after royalties by approximately 4 to 6% assuming the midpoint of our guidance.
Highlights of our 2010 budget are as follows:
- Production after royalties has grown over the last three years at an annual compound rate of over 10% with further growth of approximately 4 to 6% expected in 2010 assuming the midpoint of our guidance. At the high end of our guidance range, volumes would grow over 15%;
- Capital investment plans of $2.5 billion solidify growth beyond 2010 as we develop Usan, Golden Eagle, Long Lake and Horn River shale gas;
- Production volumes expected to range from 200,000 to 250,000 boe/d (230,000 to 280,000 boe/d before royalties);
- Capital program funded with cash flow assuming WTI averages around US$70/bbl; free cash flow of approximately $600 million at current strip prices;
- 15 exploration and appraisal wells planned, testing approximately 600 million boes of net unrisked resource potential.
We have purchased crude oil put options on 60,000 bbls/d of our 2010 production at a strike price of WTI US$50/bbl. Half of these puts settle monthly, with the remainder settling annually. We continue to look for opportunities to purchase more.
Production-Volumes Growing from New Core Assets
Over the last three years, our net production has grown at a robust annual compound rate of over 10%. This growth is expected to continue in 2010 as we ramp up Ettrick, Longhorn and Long Lake. Our capital program in 2010 advances our future growth as we move forward with the development of several major identified projects including Long Lake, Usan, Golden Eagle and Horn River shale gas. Our growth is being fueled by new, low royalty projects which more than offset high royalty production declines in Yemen.
We expect our annual 2010 production to range from 230,000 to 280,000 boe/d before royalties.
In the North Sea, we expect seven to ten days of downtime at Buzzard in the second quarter for the installation of the topsides relating to the fourth platform. This platform will allow us to handle higher levels of hydrogen sulphide over the life of the field and maintain peak production rates until 2014. Based on our production experience to date, we anticipate that start up of the new platform will not be required until 2011. If advanced to 2010, downtime associated with the start up could reduce annual volumes by 10,000 to 15,000 boe/d. This possibility is reflected in our guidance range.
Elsewhere in the North Sea, we anticipate drilling an additional development well at Telford to allow for higher production volumes from our recent Telford success. In the event these activities do not occur in 2010, annual volumes would be reduced by about 5,000 boe/d.
At Long Lake, we successfully completed our turnaround program in September. Our bitumen volumes are increasing and we are moving up the ramp up curve. Our SAGD and upgrading processes are highly integrated. This integration ultimately generates our significant margin advantage while supporting the environmentally responsible water management practices we have implemented. As a result, the pace at which we move up the ramp up curve comes with a degree of variability. This is reflected in our guidance range. While we expect periods of downtime at Long Lake as the project continues to ramp up, we anticipate continuing improvements in operational performance as we move towards full capacity.
In Yemen, production volumes are declining at rates similar to previous years.
Syncrude is planning one coker turnaround in 2010 for routine maintenance.
The timing of potential activities in the North Sea and the ramp up of Long Lake are the biggest contributors to the range of our guidance.
Conventional Development and Exploration-Investing In Our Future Growth
We plan to invest approximately $1.8 billion on conventional development and exploration with two-thirds relating to the development of existing assets and discoveries, and the remainder relating to exploration in our three core basins: the North Sea, offshore West Africa and the deep-water Gulf of Mexico. Our exploration plans include the potential drilling of 15 exploration and appraisal wells targeting a net unrisked resource potential of approximately 600 million boes.
North Sea Development
At Buzzard, the topsides for the fourth platform are scheduled for installation in the second quarter and start up is scheduled for 2011. This platform contains production sweetening facilities designed to handle higher levels of hydrogen sulphide which will allow us to maintain plateau until at least 2014. We also plan to drill five production wells and one injection well.
At Scott/Telford, we plan to follow up our 2009 development success with additional drilling and see further upside in the area with opportunities for quick tiebacks. Additional development drilling is planned at Ettrick along with appraisal drilling at Blackbird, which would be a tie-back to Ettrick.
Elsewhere in the UK North Sea, we are progressing the sanctioning of the Golden Eagle area development. As previously announced, estimates of gross contingent recoverable resource here range between 150 and 275 million boe. We expect development will support standalone facilities due to its size and be economic with oil prices as low as US$40/bbl.
"The Golden Eagle area is the largest discovery in the UK North Sea in the last 10 years after Buzzard," commented Romanow. "The development of Golden Eagle allows us to maintain or grow our North Sea production for the next five to ten years."
Offshore West Africa Development
Development of the Usan field on block OML 138, offshore Nigeria, is progressing well. The field development plan includes a floating production and storage offloading (FPSO) vessel with an oil storage capacity of two million barrels. In 2010, we expect to complete fabrication of the FPSO hull and most of the topsides. In addition, we will continue development drilling and well completion activities. The Usan field is expected to come on-stream in 2012 and will ramp up to a peak production rate of 180,000 bbls/d (36,000 bbls/d net to us). Nexen has a 20% interest in exploration and development on this block and Total E&P Nigeria Limited is the operator.
On the exploration front, we plan to drill a number of exciting opportunities in the North Sea including the North Uist prospect, west of the Shetland Islands, and the Brand prospect, our first well in Norway. Both of these prospects have higher target sizes than our typical North Sea targets. In addition, we plan to drill up to eight other exploration and appraisal wells. This includes Bluebell, a possible southern extension of the Buzzard field, and the Deacon and Bugle exploration wells, which take advantage of our regional success with stratigraphic traps.
In the Gulf of Mexico, we are currently drilling an appraisal well at Knotty Head and results are expected in the second quarter. The well is being drilled by our first contracted deep-water rig, the Ensco 8501. A second deep-water rig, the Ensco 8502, is scheduled to arrive in mid-2010. Access to these two deep-water rigs allows us to move forward with our exploration program and we expect to drill up to four exploration wells in 2010. High impact prospects that could be drilled include Kakuna, Angel Fire and Solitude, and a non-operated prospect, Catalina.
In Colombia, we plan to participate in the El Guadual exploration well and offshore West Africa, further exploration drilling may take place as early as 2010 following the recent success at Owowo.
"We are adding value by advancing our discoveries and building on our drilling success in the UK," said Romanow. "We have added experienced people to our talent pool and access to new deep-water rigs in the Gulf of Mexico will allow us to keep progressing our large inventory of exciting prospects."
Oil Sands-Keeping the Upgrader Full at Long Lake is a Priority
We plan to invest $400 million in oil sands in 2010 which includes $100 million at Syncrude. In the coming year, our capital program at Long Lake Phase 1 will focus on the drilling of sustaining well pads and the continued installation of ESPs in our SAGD wells.
With respect to future phases of Long Lake, we plan to continue engineering work on Phase 2 with timing of sanctioning dependent on multiple factors including the ramp up of Phase 1, receiving clarity on proposed climate change regulations, finalizing cost estimates and seeing more confidence in a sustained economic recovery.
Horn River Shale Gas-Continued Focus on Improving Returns
We have approximately 88,000 acres in the Dilly Creek area of the Horn River basin in northeast British Columbia with a 100% working interest. We estimate our lands contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of contingent recoverable resource which could double our existing company-wide total proved reserves.
With our recent drilling and completion program, we realized substantial cost savings and productivity improvements and are producing at rates in line with regional producers. We took advantage of improved equipment utilization, drilled longer wells, initiated more fracs per well and maintained an industry-leading frac pace of 26 fracs in 15 days while achieving a 100% success rate on our frac program.
In 2010, we plan to invest about $200 million on the drilling and completion of an eight-well pad and on processing facilities. Compared to our earlier programs, this pad will have longer horizontal wells with more fracs and higher frac densities (18 fracs per well). We expect to achieve shale gas volumes from this program of approximately 50 mmcf/d in early 2011. This program sets up a potential capital investment plan consisting of an 18-well pad which could commence drilling in 2010.
"Larger programs, increased well productivities and higher recovery factors result in lower unit costs and are the catalysts to driving higher Horn River returns," said Romanow. "I am pleased with our progress and our success is setting industry benchmarks."
Ongoing Strategic Review of our Portfolio
We regularly review the assets in our portfolio to ensure that they are aligned with our strategies and can compete for investment funding against other opportunities. We have identified a number of non-core assets for possible disposal, including parts of our marketing business, our heavy oil assets in Western Canada and our interest in the Canexus chemicals business. We expect that the disposition of non-core assets could generate over $1 billion in the next 12 to 24 months with timing dependent on market conditions.
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