The Gulf of Mexico deep-water market offers an attractive combination of relatively stable regulatory and political markets, combined with substantial reservoirs. For the services firms, the market promises to be a gold mine, as using recent projects as a benchmark, we expect $30 billion to $40 billion in services spending during the next five years. Offshore drillers such as Transocean (RIG) have the opportunity to share about $15 billion to $20 billion in revenue, while subsea specialists such as FMC Technologies (FTI) and Cameron (CAM) can target about 300 trees and associated subsea systems, which is an estimated $5 billion to $6 billion market. We think Technip (TKP) is particularly attractively positioned, as it has worked on a number of projects in the region, such as Constitution, Greater Chinook and Na Kika. The firm's deep experience in the region means it should be first in line to secure a substantial amount of work for BP's (BP) Kaskida and Tibor discoveries.
Gulf of Mexico Winners
In the short run, we think there are several key considerations to securing deep-water work in the Gulf of Mexico. The attributes are experience, financial stability, and asset availability. We think price is a secondary consideration in a region where the wells being drilled are pushing up against the very limits of today's technology. In our view, Transocean, Technip, and FMC Technologies are poised to secure a substantial portion of the development work on the early-stage discoveries in the Gulf of Mexico during the next few years.
Transocean has more deep-water rigs than anyone else in the Gulf of Mexico. The company's 17 rigs combined with more than 300 rig-years of deep-water experience mean that when a rig is available, Transocean has an edge over its peers. The firm has set several world records in the region, including drilling the deepest gas well ever for BP at more than 35,000 feet, and operating in more than 10,000 feet of water while working for Chevron (CVX). The company has a blue-chip roster of Gulf of Mexico clients, which in addition to BP and Chevron, also includes Eni (E) and Anadarko (APC). The customer base sets up Transocean for future work as it provides drilling services to the owners of 11 of the 16 major early-stage discoveries that we track.
Technip stands to benefit from higher levels of project activity in the Gulf of Mexico. The region is one of the most important deep-water markets in the world. Currently, more than 30 deep-water rigs operate in the region, and in 2007, the deep-water Gulf produced about 900,000 barrels of oil and around 2 billion cubic feet of gas per day. The area includes major discoveries such as BP's Na Kika and Shell's (RDS.A) Perdido developments, as well as Chevron's Jack/St. Malo development effort. Deep-water projects are attractive for large oil and gas companies as political inference is limited, the companies can book valuable reserves, and the long-lead times and immense amount of capital required limit the field of competitors. Improved drilling practices and seismic technology led to better risk-management and better deep-water economics. Unsurprisingly, deep-water oil and gas production in the Gulf of Mexico took off in the mid-1990s and its future looks bright.
FMC Technologies has participated in numerous projects in the Gulf of Mexico, and its alliance with big deep-water spenders such as Shell, BP, and Chevron ensures a continued large presence in the region. FMC's work on BP's Thunder Horse, Chevron's Tahiti, and Shell's Perdido should pay rich benefits in the form of continued orders over the life of the field, as well as additional work for new projects under development. Oil and gas companies see a real need for subsea equipment that can survive in high pressure, high temperature wells for long periods of time, and we think FMC's technology efforts will help provide some solutions.
Key Projects in Production or under Development
A few of the Gulf's most significant projects are BP's Atlantis and Thunder Horse projects, as well as Chevron's Tahiti effort. The BP Atlantis project was discovered in the late 1990s, as rigs confirmed the find by drilling several 18,000 foot wells. The field is situated in water depths of a little more than 6,000 feet deep and recoverable reserves are estimated to stand at 635 million barrels. Much of the initial development work was done by J. Ray McDermott and Heerema Marine, which fabricated and installed topside facilities and the associated pipelines for about $1 billion in contracts. FMC Technologies entered a decade-long agreement with BP to provide subsea trees, manifolds, and connection systems. Production commenced in 2007, and is expected to reach 200,000 barrels per day and 180 million cubic feet per day. Future development efforts include adding seven new wells and the associated production infrastructure to obtain new production from the Atlantis North flank. To date, total development costs are about $2 billion.
BP's Thunder Horse project involved considerably more engineering complexity, and had to deal with the damage fallout from the passing of Hurricane Dennis in 2005. The project took 20 years to transition from its initial lease to first production. Now, the field is expected to operate for about 25 years, and we estimate development costs at about $5 billion. Thunder Horse was discovered by the Transocean Discoverer Enterprise in 1999 and is situated in a water depth of 6,050 feet. Recoverable reserves stand at 1.5 billion barrels. Well conditions were unprecedented, with pressures ranging from 13,000 to 18,000 psi, and temperatures from 88 to 132 degrees Celsius. Development efforts again involved contributions from J. Ray Dermott, Heerema Marine, and FMC Technologies. Thunder Horse production was originally slated to start in late 2005, but the passing of Hurricane Dennis caused a leaky internal ballast valve, which eventually led to the production platform listing 20 to 30 degrees. Thus, first production started in June 2008, and production rates should continue to increase from its current 300,000 boepd as development drilling continues until 2016. (Click to enlarge)
Chevron's Tahiti field contains some of the richest oil accumulations in the Gulf of Mexico, with one well encountering more than 1,000 feet in net pay of hydrocarbon sands. The Transocean Discoverer Deep Seas drilled one of the vertical appraisal wells. First discovered in 2003, the field entered production in 2009, and peak production is expected to be around 125,000 bopd and 70 MMcf/d. The reservoir is estimated to hold about 400 million-500 million barrels. J. Ray Dermott, Technip, and Cameron were involved in the development efforts, which cost Chevron about $3.5 billion.
All three projects highlight the size and quality of the reserves available in the deep-water Gulf of Mexico. Exploiting these reserves is now possible due to the advances in drilling, subsea, and seismic technology that have developed during the past few decades. Development costs are not cheap, and the services companies routinely earn lucrative margins by providing their technology and expertise to help find and exploit the large discoveries. Still, even with the large economic rents being extracted by the services firms and drillers, exploration activity and the number of discoveries in the Gulf have materially increased over the past few years. As well, lag time between first leasing the prospect and first production has decreased from about 15 years in 1988 to about 5 years in 1999. Gulf of Mexico leases run for about 8-10 years, and we'd expect the lag time to increase for the 1999-2009 time period, as companies move toward developing projects in deep waters of 4,500 feet or more. The deeper efforts require that new solutions be developed to solve the temperature and pressure requirements of the offshore wells, which can exceed 300 degrees Celsius and 35,000 pounds per square inch.
In one scenario, the Minerals Management Service (MMS) forecasts that, by 2015, deep-water production could reach about 1.8 million barrels of oil, and around 7 billion cubic feet of gas per day. BP's recent discoveries called Kaskida and Tiber could certainly play larger roles in the future Gulf of Mexico production. Tiber is estimated to contain as much as 4 billion barrels of oil in reserves, and the initial record-breaking well was drilled by Transocean's Deepwater Horizon. The find is similar to BP's Kaskida discovery, which was first drilled in 2006, and contains approximately 800 feet in net pay of hydrocarbon-bearing sands. Industry estimates place Kaskida reserves at around 3 billion barrels. We expect BP to drill additional appraisal wells, and first production to possibly take place in 2015. Based on development budgets for recent Gulf of Mexico efforts, the investment needed for both reservoirs, in our view, will be in the range of $8 billion to $12 billion. We think FMC, Technip, Transocean, and Acergy (ACGY) are all candidates for contract awards.
To support Tiber and Kaskida, as well as a long list of major prospects, will require many more deep-water rigs in the Gulf. The deep-water rig fleet in the Gulf of Mexico has grown to 32 rigs late last year from about 22 active rigs in the middle of 1996. Day rates for a drillship have grown to $500,000 a day from $125,000 a day over the same time frame, which reflects the relative scarcity of quality rigs that can drill the challenging and record-breaking wells needed to fully exploit the region's large discoveries. The MMS expects another 15 deep-water rigs to be added to the Gulf of Mexico fleet during the next few years, bringing the total number of active deep-water rigs to around 50. Despite the rig additions, we do not expect deep-water day rates to decline, but remain stable over the next few years. The rigs have already been contracted for projects, and won't be available to put pressure on spot-market day rates.
Capital Spending Scenarios|
A silver lining during a brutal 2009 for the oil and gas companies was lower services costs. We estimate that services pricing for many products declined 30%-40% in 2009. This should help the high development costs in the Gulf of Mexico be more palatable. As a result, we estimate newbuild projects in the Gulf require about $60 barrel to be sanctioned.
In our base-case scenario, we estimate that the above list of projects, if all proved commercial, could total around $30 billion-$40 billion of development work over the next five years. We expect the deep-water rig and services markets to remain tight. Therefore, rig day rates should remain around $500,000 a day. E&C contractors such as Acergy and Technip should be able to earn good risk-adjusted pricing for the challenging construction and installation efforts. In addition, services companies such as Schlumberger should be able to command premium prices for developing and applying new technologies to solve the unprecedented well challenges in a few of these reservoirs.
However, in a low-case scenario where natural gas is priced at $5 per mcf, and oil is $50 per barrel, we believe deep-water investment would slow to about $25 billion. A few of the deep-water projects would be deemed uneconomic, which would likely push down rig day rates and services prices. We think Gulf of Mexico day rates for rigs would fall about 20% from current levels to around $400,000 a day. Services companies and E&C contractors would likely lose a substantial portion of the risk-premium they had been commanding, leading to substantially lower profitability.
In a best-case scenario, where oil is priced at $150 per barrel and gas at $15 per mcf, we think development costs would increase to about $60 billion. We would see more projects sanctioned, and demand for rigs and services would soar. We think the long lead times required to bring new rigs to market will create a profitable supply-demand imbalance for the drillers. We'd expect to see day rates for the most advanced ultra-deep-water rigs top $700,000 a day. In this case, Transocean would benefit as the owner of the world's largest deep-water fleet. In addition, demand for FMC's subsea technologies would also substantially increase, as we think the majority of new deep-water projects will elect to deploy subsea production infrastructure due to the attractive economics.
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