OTC: Offshore prospects clouded by rig shortages, royalty concerns

• Deepwater drilling and production was a key focus at the Offshore Technology Conference in Houston last week. Despite growing interest in deepwater technology, the prospects for activity were clouded slightly in the U.S. by concerns over royalty relief and rig supply. [14,934 bytes]
• Benefits From U.S. Offshore Oil And Gas Activity [206,393 bytes]
• OTC was expected to draw more than 50,000 industry participants last week, compared with nearly 41,000 in 1997. At the end of the third day of the conference, attendance was 48,266, up from 43,394 on the same day in 1997. [14,830 bytes]
• Brazil's Near-Term Deepwater Projects [115,809 bytes]
• Antonio Carlos Agostini, Director of E&P, Petroleo Brasileiro SA:
  Considering the size of the country (Brazil), at 6 million sq km (of sedimentary basin), there are a lot of very good opportunitiesellipseThere's a lot of acreage still available for foreign companies in all basins. Nothing has been ruled outellipseincluding the Campos basin. [12,417 bytes]
• Pacific Rim Gas Supply, Demand [65,068 bytes]

Royalty issues were a key topic of discussion at the Offshore Technology Conference in Houston last week.

Of concern was the threat of changes to the U.S. Outer Continental Shelf Deepwater Royalty Relief Act (DRRA), and their possible dampening of drilling activity in the deepwater Gulf of Mexico.

Despite recent increases in deepwater work, shallow water also assumed a prominent position in the conference presentations. Conspicuous by its absence from the discussion was the recent decline in oil prices.

A number of key topics were discussed in keynote addresses, individual presentations, and panel discussions:

• The U.S. Interior Department is considering raising the deepwater royalty rates set following the passage of the OCS DRRA in 1995. The mere discussion of changing royalty rules in midstream can chill Gulf of Mexico investment plans, said one speaker.
• The U.S. Minerals Management Service (MMS) decided recently not to permit royalty relief for nonproducing leases in shallower waters. A lot of the (shallower) prospects on the OCS will not be developed unless there is some type of royalty relief, said one observer.
• A U.S. senator plans to introduce a bill to redistribute funds from federal offshore leasing so that the states that generate large portions of the funds receive a more equitable distribution.
• A surge is expected in shallow-water exploration, driven by advances in seismic technology. The Caspian Sea will see the greatest concentration of this activity surge.
• The offshore service industry is facing problems getting the needed equipment and personnel.

Other conference presentations focused on exploration and development activity in key regions:

• Brazil's state petroleum company Petroleo Brasileiro SA provided an update of negotiations that will lead to the first equity investment by foreign petroleum companies in that country's upstream sector since the creation of the Petrobras monopoly in 1953.
• Gas consumption in the Pacific Rim is poised for a major increase, due in part to a proliferation of independent power projects. Increased E&D work will be necessary to keep up with demand.
• The premiers of Newfoundland-Labrador and Nova Scotia touted the energy potential of offshore Eastern Canada. One estimate pegs undiscovered oil reserves in the area at 5 billion bbl and undiscovered gas at 53 tcf.

Royalty relief

Bernie W. Stewart, president of R&B Falcon Drilling Inc. and vice-chairman of the International Association of Drilling Contractors, told OTC attendees that the U.S. Department of the Interior is "considering changing the economic ground rules by raising the deepwater royalty rates set in place following the 1995 passage of the Deepwater Royalty Relief Act."

DRRA, passed by Congress and signed into law by President Clinton on Nov. 28, 1995, has provided an incentive for operators to begin exploring deep waters in the Gulf of Mexico and is directly responsible for current commitments of $12 billion targeted for rig upgrades and newbuilds.

"The predictability of these costs [and economic considerations] was instrumental in the decision made by oil companies to obligate capital into deep water," Stewart said. Any alteration of the current legislation "threatens the thousands of jobs tied to the contract drilling and related oil field service industries."

Sixty-five new rigs are under construction, most earmarked for deep water. These commitments do not include the huge sums already devoted by service companies and operators for ancillary support.

"Even the discussion of changing the rules midstream has a chilling effect on investment plans in the gulf," Stewart said,

The Congressional Budget Office (CBO) all said that governmental incentives will encourage deepwater development, resulting in a net gain to the federal treasury.

The CBO estimates that increased offshore bidding, spurred by such incentives, could generate another $100 million in federal revenues through 2000. In addition, left unhindered, the emerging market could create more than 6,000 new jobs.

For new leases in the central and western Gulf of Mexico in water deeper than 200 m, DRRA temporarily eliminates royalties on production until a specified amount of production occurs (OGJ, Apr. 1, 1996, p. 45). The amount of production exempt from royalties is 17.5 million boe for leases in water depths of 200-400 m, 52.5 million boe for leases in 400-800 m, and 87.5 million boe for leases in water deeper than 800 m.

DRRA also authorizes the Secretary of the Interior to temporarily eliminate royalties on new production from existing leases if production is found to be uneconomic without the relief. The secretary must then determine the royalty-free volume that would make the new production economically viable, which can be no less than volumes specified for new leases.

Shallow-water relief

Independent Petroleum Association of America officials argued that the federal government should allow "sensible" royalty relief for offshore tracts in shallower waters.

DRRA contained a provision allowing MMS to grant royalty reductions and other incentives to keep marginal leases-including shallow-water tracts-in production.

Ernie Cockrell, chairman and CEO of Cockrell Oil Co., Houston, noted the law has led to a significant increase in the number of deepwater tracts leased and aggregate bonuses received, and it has spurred a surge in employment in the OCS oil and gas industry and supporting services.

But, he said, "On the shelf, a lot of the (shallower) prospects will not be developed unless there is some type of relief on royalties."

He said MMS recently decided not to permit royalty relief for nonproducing leases in shallower waters.

Cockrell said IPAA had proposed that, if a producing well had been drilled on a lease but was not commercial, when the lease is surrendered, MMS should offer the tract at a lower royalty rate in the next sale. The royalty rate would keep dropping each sale until the tract was sold again and developed.

"This type of a program would make a lot of sense. It would be practical and workable," he said.

Other issues

The proposal was part of a five-part package that IPAA said would help independents working offshore. It said about 80 independents are active offshore, and, since 1987, independents have acquired more leases in the Gulf of Mexico than have majors.

IPAA said Congress should open more OCS areas to leasing. It said Congress should establish MMS with legislation (it was created in 1982 by an order of the Interior Secretary) and give MMS more funding for processing lease assignments, drilling permits, and other operational actions.

"Producers are beginning to experience costly delays as a result of a backlog of MMS approvals."

And IPAA said Congress should pass royalty-in-kind legislation so that the federal government would take royalties in oil and gas, rather than cash, and "end years of litigation and dispute over how to comply with a complex royalty valuation system."

Revenue redistribution

A Coastal Impact Assistance proposal, designed to more equitably redistribute revenues generated by the U.S. federal offshore leasing program, may be introduced to Congress as early as July. The bill is being championed by Sen. Mary Landrieu (D-La.) and was put together by the Offshore Continental Shelf Policy Committee, an industry advisory body.

Currently, most of the revenues generated by the federal offshore leasing program help pay for federal programs and reduce the deficit. Boysie Bollinger, vice-chairman of National Ocean Industries Association (NOIA) and chairman of Bollinger Shipyards Inc., said, "It is only fair that a federal government that carries out a program that benefits the federal government in terms of money to the treasury...should also share a modest portion of that revenue with the states that are impacted."

The OCS currently accounts for 15% of U.S. oil production and 25% of its natural gas output. On average, the federal government collects $3 billion in bonuses, rents, and royalties from offshore oil and gas leases each year. The federal offshore leasing program supplies one of the largest sources of U.S. nontax revenues.

However, only a small portion of that revenue returns to the coastal states that generate it.

In 1996, Gulf of Mexico leases provided $2.8 billion to the federal government, yet Louisiana's share was about $23 million, Texas' $20.8 million, Alabama's $10.8 million, and Mississippi's only $546,000.

In contrast, onshore revenues are returned more equitably. In 1996, onshore production provided $800 million, with $500 million returned to the states where production occurred.

According to NOIA, since 1953, the federal government has received $120 billion from the OCS, primarily the Gulf of Mexico. Yet the amount of money returned to all 50 states, mostly for the Land and Water Conversation Fund, was only $24 billion. Of the $24 billion, only $991.3 million, or less than 1%, was earmarked for Louisiana.

The Land and Water Conservation Fund is controlled by the appropriations process.

Concept reintroduced

In 1997, the OCS Policy Committee, consisting of 40-50 members from coastal states, industry, environmental community, local governments, and other federal agencies, appointed a six-member group to address the shortcomings of past revenue-allocation efforts.

The revenue-sharing concept is not new, and some form of impact assistance has been introduced in the Senate or the House more than once. However, no impact assistance bill has ever made it through both houses.

The OCS Policy Committee believes now is the time to introduce the bill, especially with the number of state representatives from coastal states who currently have key leadership roles.

"Off the top of my head, we've got Rep. Livingston of Louisiana chairing the House appropriations committee, Senator Frank Murkowski of Alaska chairing the Senate energy committee, Rep. Don Young, also of Alaska, chairing the House resources committee...And let's not forget Trent Lott of Mississippi serving as Senate Majority Leader," and Newt Gingrich who represents Georgia and serves as Speaker of the House, Bollinger said.

Distribution proposal

The six-member group proposes that the federal government distribute annual payments equaling 27% of the revenues from OCS production. With OCS production running at $3 billion/year, this would provide impact assistance totaling about $1 billion/year.

"The money would then be put into a pot, and it would be an entitlement fund-not subject to an annual appropriations process," Bollinger said.

One half of the entitlement fund would be based on proximity to offshore production. The closer a state is to production, the greater its allocation.

Thus, "If Florida is twice as far from a producing lease as Texas, then Florida's allocation under the production factor will be half the size (of Texas')," he said.

The other half of the fund would be targeted for states that do not have any production, "although producing coastal states would be eligible as well." Twenty-five percent would be based on shoreline mileage, and the remaining 25% would be based on the population of the coastal states.

"(This) approach ensures that all coastal territories will receive revenues generated by OCS activity, but the majority of those revenues will go to those states and communities adjacent to OCS production and its associated impacts," Bollinger said.

Washington observers note, however, that Landrieu faces an uphill battle in gaining support for her bill on Capitol Hill and with the White House, because federal law requires that legislation that results in reducing federal revenues be offset with new revenues.

Shallow water

Exploration in the shallow-water zones worldwide is poised for a surge in activity, based on companies' experiences in the U.S. Gulf of Mexico, said Norman Neidell, vice president of Zydeco Energy Inc., in a press briefing at OTC.

The potential is driven mainly by technological developments that have yielded better seismic data and a better understanding of the geology, especially beneath and around salt formations.

Citing the Caspian Sea specifically as a likely province, Neidell said that the advent of 2D and 3D imaging has led to an ability to identify hydrocarbons and porosities in hard sands.

Steve Mitchell, vice-president for data acquisition for Fairfield Industries, said the advances in technology have provided more data that are then recorded and transmitted faster.

Rig challenges

A panel discussion at the conference explored the problems the offshore industry faces in getting the needed money, machines, and manpower.

Matthew Simmons, president of Simmons & Co. International, Houston, said that attracting money is the least of the three problems discussed.

David Lesar, president and CEO of Halliburton Co., Dallas, said, "From a service company standpoint, our resources are stretched."

Paul Lloyd Jr., chairman of R&B Falcon Corp., Houston, said the current tight rig market is not delaying any production now but might be delaying some exploration.

He said operators should remember a key point about rigs under construction. "Most of the newbuilds are for deep: water, so they're really being built for a new market." And he said rigs often are being built for specific drilling programs.

Jack Golden, director of BP Exploration U.K., observed that the current rig fleet can't be compared with the rig counts of old. "When you factor in productivity improvements, operators have effectively doubled the number of rigs."

And Lesar said oil companies also are operating much more efficiently than they were 5-10 years ago. "Companies are doing their homework much better in their offices before sending a rig out to the site."

The panel disagreed on where the new frontiers for the industry would be. One said Russia, another said countries that are allowing competition with their national oil companies, and another said deepwater Latin America.

Despite oil price, rig, manpower, and other restraints, said Golden, the major oil companies will be able to increase their production 5%/year for the next decade.

Brazilian E&P outlays

Petrobras estimates that partnerships it is negotiating with foreign companies will result in exploration and production outlays in and off Brazil totaling more than $4.5 billion during the next 3 years.

Petrobras E&P Director Antonio Carlos Agostini, who provided the estimates at an OTC press conference last week, broke the spending out as $1 billion for exploration and $3.5 billion for development.

This excludes the company's own near-term capital spending on development and production in the deepwater Campos basin that is earmarked for boosting Brazil's oil production to about 1.5 million b/d of oil by the turn of the century from the current level of about 1 million b/d (see table, this page).

In response to the passage last year of Brazil's new petroleum law ending Petrobras's monopoly on petroleum activity in the country, the state company-still vocally resisting any notion of privatization despite an initial public offering of shares that is slated to be completed this year-has embarked on a campaign of soliciting foreign investment in its upstream sector.

Petrobras is finalizing negotiations on participation in 42 exploration, development, and production projects with 24 companies as potential operators and with 11 companies as potential nonoperators. Separately, the state company is near the end of negotiations with 23 companies on participation in 31 projects to resuscitate production in marginal oil fields. Initially, more than 100 companies were involved in these negotiations.

Award of these partnership contracts awaits the official grant of concessions to Petrobras and foreign companies by the newly formed National Petroleum Agency (ANP), as well as approval of the final rules governing the fiscal regime for the oil industry in Brazil. The deadline for ANP's grant is Aug. 6.

Despite reports of friction between ANP and the Petrobras leadership that some government officials in Brazil have said could presage the ouster of Petrobras's management and board (OGJ, Apr. 13, 1998, p. 25), Agostini affirmed that relations between the two are "running smoothly."

Agostini also took issue with earlier claims by some foreign companies that the state company would seek to reserve the best acreage under these concession awards for itself.

Citing the law in which ANP would set aside for Petrobras certain acreage in which the state company has already invested funds for E&P, Agostini said, "Considering the size of the country, at 6 million sq km (of sedimentary basin), there are a lot of very good opportunitiesellipseThere's a lot of acreage still available for foreign companies in all basins. Nothing has been ruled outellipseincluding the Campos basin."

Indeed, Brazilian press reports have cited preliminary agreements with groups led by Exxon Corp. and Texaco Inc. to develop, respectively, in partnership with Petrobras, Albacore Leste and RJS 366 deepwater fields in the Campos basin. Petrobras would not confirm those tentative accords.

Agostini also noted that, given the state of current discussions with the government, Petrobras "will have no problem getting funding for our projects."

Pacific Rim gas

Pacific Rim countries are posed to increase gas developments markedly, driven by the development of domestic markets for independent power production (IPP). Gas consumption in the region will increase to about 26.4 tcf in 2010 from 8.3 tcf in 1996, said Satoshi Tono of Japan National Oil Corp.

Regional gas supply is expected to lag demand in the coming years. In 2010, production will be 30-58 bcfd, said Tono, vs. 22 bcfd in 1996 (see graph, this page).

"This high energy demand suggests that expedition of exploration, development, and utilization of natural gas in this region has a great significance, in terms of expanding the supply capacity as well as maintaining a balanced energy market structure."

Until recently, E&P activities in the region tended to focus on crude oil, "setting aside natural gas, to some extent," said Tono.

There have been some major gas discoveries in the western Pacific Rim recently (Tono defines the region as Southeast Asia, Australia, New Zealand, and Papua New Guinea). The most notable discoveries are in the Northwest Palawan, Natuna, Mahakam, and Wiriagar basins, and in the East and South China Seas.

These, and new gas discoveries, will be developed for one of three types of ventures: LNG export projects, long-distance pipelines, or IPP schemes.

LNG export projects in the region are abundant, the most notable being Indonesian state firm Pertamina's Bontang and Arun plants. There also are two LNG plants in Malaysia, one in Brunei, and one in Australia. Additional LNG plants are being planned for development of gas from Indonesia's Tangguh (Wiriagar deep) and Natuna D fields.

Political instability and the long distance between gas reserves and markets have limited development of a pipeline network in the region, said Tono. There are only two multinational lines in service: a 730-km, 57 bcf/year line between Malaysia and Singapore and a 770-km, 117 bcf/year line between Hainan Island and Hong Kong (laid before Hong Kong's turnover to China). Two lines are under construction between Myanmar and Thailand-Yadana, by Total, and Yetagun, by Premier Oil Pacific Ltd.

"The possibility of the Northeast Asian pipeline network (East Siberia pipeline network) and the Trans-Asian pipeline network, which in the past had been only speculation, now appears to be taking shape.

"A number of IPP projects are under way or under consideration in Indonesia, Malaysia, Viet Nam, India, and Pakistan," he added.

"Natural gas has come to be regarded as one important resource for these new ventures. There are many small to medium-sized gas fields that have been discovered but have not been developed due to the lack of market availability and/or effective methods of natural gas utilization."

Eastern Canada

Newfoundland and Labrador Premier Brian Tobin and Nova Scotia Premier Russell MacLellan agreed on the energy potential of offshore Eastern Canada.

Tobin said there have been 17 discoveries on the northeast Grand Banks with reserves of 1.6 billion bbl of oil, 4 tcf of gas, and 237 million bbl of gas liquids.

"Estimates indicate approximately 5 billion bbl of oil and upwards to 53 tcf of gas are yet to be discovered."

Tobin said production from Hibernia field will increase to 100,000 b/d by yearend, and development drilling will begin next year in Terra Nova field. First oil is expected by late 2000 at a cost of $7.50/bbl (U.S.).

He said the province will produce up to 400,000 b/d of light oil-a third of Canada's total output-by 2004.

MacLellan said the Sable Island gas field development off Nova Scotia is on budget and on schedule. "Gas will be flowing to Eastern Canadian and New England markets by late next year."

He said the province soon will release a generic royalty policy that "is profit-sensitive and provides for low front-end royalties as a way of reducing industry's capital exposure."

The premiers said they would begin negotiations in a few weeks to resolve a dispute over their common offshore boundary that bisects the Laurentian basin. MacLellan said, "There's a tremendous play in the Laurentian subbasin. Some people say it has the same opportunities as the Sable Island area."

Copyright 1998 Oil & Gas Journal. All Rights Reserved.