One of the sessions at this year's Offshore Technology Conference highlighted the Ursa tension-leg platform, operated by Shell Deepwater Production Inc. The platform stands in 3,800 ft of water on Mississippi Canyon Block 809, about 130 miles southeast of New Orleans. Ursa is Shell's fourth TLP in the deepwater Gulf of Mexico. Photo courtesy of Shell Deepwater Development Systems Inc.
The tone at this year's Offshore Technology Conference was one of confidence, albeit a somewhat tentative confidence. The source of this returning optimism is two-fold: the recent rebound in oil prices and faith in the industry's ability to meet ever-greater demands with technology and improved business procedures.
- A tentative confidence is returning to the petroleum industry, following the recent rebound in oil prices. This confidence is predicated on the industry's ability to develop and enhance the technology it uses to find and produce oil in increasingly remote and harsh environments. Such technologies were highlighted at this year's Offshore Technology Conference, where attendance totaled 42,500 at presstime. [23,112 bytes]
- Historical and Projected Drilling Expenditures [105,692 bytes]
- Costs for a deep-drilling land rig [58,465 bytes]
The price collapse of the past year and a half has had an apparent sobering effect on the industry. In one session at last week's OTC, for example, a panel discussion centered on the fact that the events of recent years have made it clear that it is time for the energy industry to reinvent itself based on a new market paradigm.
In this new operating environment, the roles of various industry segments are changing, and consolidation among companies is changing the face of those segments. Independents are combining to form "mega-independents" and majors are joining forces to become "super-majors."
The Independent Petroleum Association of America discussed the status of the independent producer in the modern petroleum industry. IPAA stressed that independents are playing an increasingly important role in the offshore sector, alone and in combination with majors and each other.
Other sessions focused on how technology will be used to achieve industry goals. One such discussion was about the potential use of floating production, storage, and offloading (FPSO) systems in the U.S. Gulf of Mexico. A number of issues must be resolved before the U.S. regulatory bodies allow FPSOs to be installed in the gulf, but signs are encouraging that this resolution process is beginning. The U.S. Minerals Management Service has let a contract for an environmental impact assessment on FPSO use in the gulf's federal waters.
In another presentation, the Gas Research Institute concluded that technology will ensure that growing U.S. natural gas demand will be met. This will be done through a combination of increased offshore drilling and technological improvements, says GRI.
A changing environmentA panel discussing the role of the energy industry in the next millennium agreed that the energy industry in general, and petroleum in particular, is in need of a complete culture change in order to thrive in a business increasingly characterized by low prices, high technology, increasing consolidation, and growing emphasis on environmental and social awareness.
The oil industry adopted its present structure in the late 1970s and early 1980s, said Robin West, chairman of Petroleum Finance Co. That structure is one in which national oil companies play an enormous role.
Today, national oil companies (NOCs) own 90% of the world's oil and gas reserves and are responsible for 70% of oil and gas production. But NOCs need access to technology, management skills, capital, and markets, says West. Thus, over time, producing areas have been, and will continue to be, opened to outside investors. This means that, in the future, national oil companies will own most of the world's oil, but international oil companies will produce it. Such a situation would be "insupportable," said West, and it will drive a fundamental change in the industry's structure.
Simultaneous with this trend, technological advances continue to cut the cost of finding and producing oil and gas. And this is happening at a time when supplies of petroleum exceed demand and are expected to continue to do so.
Luis Giusti, former president of Petroleos de Venezuela SA and senior advisor and consultant with the Center for Strategic and International Studies, Washington, D.C., said, "It looks like we've crossed into a threshold where oil is being increasingly commoditized."
Giusti pointed out that the oil industry has historically been subjected to artificial supply management.
"I think (producers) have proven that there's no way they can have a stable supply-management system in the long run," he said. "Not even OPEC countries are going to do it. We may see some measure of supply management in the future," said Giusti, "but we should prepare for a different kind of world."
In this new world, as Tony Hayward, group vice-president of BP Amoco Exploration, sees it, supply will be permanently high and prices permanently low-a commodity market, in other words. This will last as long as the world uses fossil fuels, Hayward predicts.
Max Lukens, chairman, CEO, and president of Baker Hughes Inc., observed that, during the past 25 years, this business has been graded on a volumetric basis. But Wall Street isn't very interested in volumes, he says. This is what has driven the recent cost-cutting frenzy, including the consolidation trend.
Industry's response, thus far, to these myriad factors hasn't been effective, West argues, because companies haven't truly adjusted their strategies: "Companies need new strategic directives in new times."
In their new roles, says West, service companies will manage technical and operating risks, the international firms will manage financial and political risks, and NOCs will manage national interest in resources.
As an example of this new model, Hayward cited the development of Venezuela's Daci?n field by Lasmo plc, which outsourced much of the work to Schlumberger. Lasmo managed the financial and commercial issues for Venezuela, and Schlumberger did all of the work on the ground, he said. "More and more of these kinds of things are going to be carried by the service companies."
Amid this changing business scenario, oil companies are experiencing increasing pressure to manage what has become known as the "triple bottom line": financial, environmental, and social performance.
John Elkington, chairman of U.K. consulting firm SustainAbility, said "Sustainable development and the triple bottom line are increasingly the way your companies are going to be judged."
The panelists agreed that what all this means is that the oil industry must reinvent itself. The movement to do so is in its infancy, with European companies such as BP Amoco plc taking the lead. BP Amoco has done this by entering business segments such as solar and wind power and by instituting initiatives related to climate-change legislation, such as internal emissions trading.
In addition to environmental performance, another "clear differentiator" of the leading energy companies in this new operating environment will be the ability to effectively manage their portfolios, says Hayward. Oil companies have not been very good at this so far, he says. West stressed, however, that, if managed correctly, a portfolio can include a variety of projects that perform differently under different market conditions, thus mitigating risk.
In the end, says Lukens, the oil industry will organize itself around the price of oil, whatever it is: "We will adjust our costs, our utilization and capacity, our productivity."
Hayward agrees: "We have to find a way of living in a low-price (environment)," he said, adding that he is confident that the industry will rise to the challenge.
"It is the industry that drives the world. It is the engine of the world's growth and will continue to be for severalellipsedecades to come."
Independents offshoreBen Dillon, IPAA's vice-president of public resources, told OTC, "Independents have become and will remain very important in one of America's greatest frontiers, the offshore... where they-acting on their own or in partnership with each other and with the majors-are key players in some of the high-profile projects, like the subsalt play in the deep water.
"Therefore, it is essential that independents are afforded every encouragement to go out and do what they do best-explore (for) and produce oil and gas," said Dillon.
Recent MMS statistics would appear to support IPAA's assertion of the critical role that independents play offshore. As of Aug. 21, 1998, noted Dillon, independents owned 57% of offshore acreage in less than 400 m of water and 60% of acreage in more than 400 m.
The pervasiveness of independents offshore also was evident at Gulf of Mexico Lease Sale 172, when 90% of the companies bidding were independents (OGJ, Mar. 22, 1999, p. 40).
The IPAA offshore committee held a meeting in March with a ranking MMS official to discuss what could be done during certain times of crisis, such as the recent oil price collapse. Among the topics discussed were royalty incentives, regulatory burdens, environmental policies, and access to Outer Continental Shelf (OCS) areas.
Highest on the priority list for IPAA were royalty incentives. "The Deepwater Royalty Relief Act grants relief automatically for new deepwater tracts," explained Dillon. "But relief for producers on the shelf is limited to those tracts that have become uneconomic, usually at the end of the reservoir's life." And the application process for this relief is very "burdensome and complex," and usually ends with no relief, he said.
At that meeting, the IPAA committee presented at least three new proposals for royalty incentives for MMS consideration. The first is based on netback or cash-flow stabilization, which would offer fluctuating incentives for both oil and gas.
The second proposed program calls for offset of a company's capital expenditure. "This one has a lot of attraction on Capital Hill," explained Dillon. During times of low oil prices, the proposed program would allow companies to offset up to 20% of their expenditures against their royalty payments. The attraction in Washington is due to the program's ability to allow money to flow back into development, keeping wells on line, noted Dillon.
The third proposal is based on the onshore federal well program supported by the Bureau of Land Management, which allows royalty relief for wells producing less than 15 b/d of oil. In the IPAA model, however, the definition of an onshore stripper well has been increased to 20 b/d of oil. The committee also is working with MMS on a workable definition of a marginal offshore well, starting the debate at 200 b/d of oil and 1.2 MMcfd of gas.
Among the regulatory burdens discussed at the meeting with MMS are proposed changes to the agency's the OCS lease form. Dillon said that IPAA views the form's changes as "radical," contending that the new form would create a lot of uncertainty through provisions such as making a lessee subject to any future regulations. Also, the form includes many of the controversial royalty provisions that are still under debate. IPAA is pleased that MMS is holding workshops to discuss returning the form to existing policy, said Dillon.
On the topic of access to OCS public lands, IPAA feels that U.S. energy policy would be furthered through better access to public lands-in particular, in the eastern Gulf of Mexico. Dillon noted that 86% of the U.S. offshore is off-limits. "With today's technology, producers can tap into these areas with minimal threat to the environment," said Dillon.
FPSOs in Gulf of MexicoUnresolved aspects abound for the installation of FPSOs in the federal portion of the Gulf of Mexico. As A.J. Verret, of Texaco Inc. and the Deepstar consortium, remarked in his presentation at OTC, the process is moving at "glacial speed."
Even with over 70 ship-shaped floating installations worldwide-including one in the Mexican sector of the gulf region (see related story, p. 22), some significant issues still being assessed include: mooring and fluid transfer to the FPSO from subsea production equipment; marine and production system interfaces; offloading safety procedures; verification and classification; and hazards analysis.
Manning during hurricanes, off loading in advance of a hurricane, and critical operational contingencies are also being investigated.
Some progress has been made. Both MMS and the U.S. Coast Guard signed a memorandum of understanding on Dec. 16, 1998, to deal with the question of which agency has authority over what aspect of an FPSO installation, but some parts remain under the jurisdiction of both agencies.
Coast Guard Lt. Cmdr. W.H. Daughdrill contends that simultaneous submittal to both agencies will not be required, and that one agency will be authorized to receive the proposal first. But the process is still being delineated.
Daughdrill emphasized the Coast Guard's position that FPSOs will have to adhere to the Oil Pollution Act of 1990 requirements for tank vessels. He explained that this generally means that all FPSOs constructed or converted after June 30, 1990, must comply with double-hull requirements. But he also cautioned that his comments should not be taken as meaning that the Coast Guard requires a double-hull vessel in all instances.
Daughdrill's comment was made in response to a remark that the double-hull requirement, as specified by the regulation, only applies to vessels in transit.
Daughdrill said the Coast Guard considers: FPSOs to be vessels, not facilities; stored oil to be bulk cargo; and offloading to a shuttle tanker to be lightering.
Currently, there are four designated lightering zones and three lightering-prohibited zones in the U.S. Gulf of Mexico.
Another aspect of the process that is moving forward is an impact statement for a generic FPSO in the Gulf of Mexico. Funded by the Deepstar consortium, the statement is expected to be completed in late 2000.
MMS awarded the contract for preparation of an environmental impact statement (EIS) to Ecology & Environmental Inc. and its subcontractors. Funds for the $997,060 contract will be provided by 14 members of the Deepstar consortium. The contract calls for finishing the EIS in 18 months, with release of the final statement during September-October 2000.
Gas drilling advancesA recent study by the Gas Research Institute concludes that U.S. natural gas demand will be met through a combination of increased offshore drilling, improvements in drilling success rates, and well-productivity improvements. "Technologies are critical to drilling economics, and advances in drilling technology are allowing drillers to work much smarter," said John Cochener, principal analyst of resource evaluation for GRI. GRI predicts ultradeepwater drilling will grow from 3% of total offshore activity in 2000 to 24% in 2015. Furthermore, GRI projects a 2% annual increase in U.S. gas consumption over the next 2 decades. Contrary to current thinking among analysts, however, GRI feels the U.S. rig fleet will cover future needs for some time. "Producers will meet the expected growth in (natural gas) consumption with drilling levels and expenditures that remain well below historic highs," Cochener said. Cochener noted that drilling costs account for about 33% of the total cost of finding and developing new onshore natural gas resources and about 40% of the cost of new offshore resources. In addition, GRI predicts total onshore and offshore drilling expenditures will increase slowly during the 17-year projection period, growing from $16.4 billion in 1997 to $24.4 billion in 2015 (see chart, p. 23). The GRI study identified five major trends that shape the cost of drilling:
- Drilling activity drives drilling costs. The level of drilling activity accounts for about 70% of changes in drilling costs. Thus, drilling costs can be expected to rise as activity increases. This is particularly true during short-term cyclical spikes in activity.
- Increases in oil and gas prices translate directly into higher drilling costs. Rising oil and gas prices spur drilling of additional marginal wells. These wells drive up drilling costs because they are deeper or located in more difficult environments, making them more expensive to drill. Higher oil prices also lead to increases in drilling costs because energy costs are a major component of total drilling costs.
- A declining rig population creates a tighter market for available rigs, triggering upward pressure on day rates. The U.S. onshore rig population has been declining since 1981. Until rig day rates increase sufficiently to justify significant new investment in rig construction, the market will continue to become tighter for rigs.
- A tight rig market is needed over a sustained period to achieve day rates that justify investments in new equipment. At yearend 1998, U.S. onshore rig rates were well below the break-even point needed to justify new rig construction (see table, p. 23). In a tight market for rigs, day rates are likely to increase until they reach levels that trigger new equipment investments. Between late 1996 and early 1998, certain offshore rig rates increased briefly to levels required to justify the limited new construction now under way. Much of the rate increase was attributable to new deep and ultradeepwater prospects requiring new or upgraded drillships to develop remote resources.
- Advances in drilling technologies have improved-and will continue to improve-drilling efficiencies, resulting in lower overall costs. These gains mean rates will reflect the benefits and costs of advanced technology, in most cases. New technologies, however, could produce higher day rates for certain rigs that provide offsetting benefits by requiring fewer drilling days.
Contributing to this article were: Anne Rhodes, Associate Managing Editor-News; Steven Poruban, Staff Writer; Warren True, Pipeline/Gas Processing Editor; Dean Gaddy, Drilling Editor; and Guntis Moritis, Production Editor.
Copyright 1999 Oil & Gas Journal. All Rights Reserved.