Kent H. Wall
Staff Writer
Non-U.S. independent operators are pouring more money into U.S. exploration and development projects, mainly along the Gulf Coast and in the Gulf of Mexico.
Some of the operators are working onshore plays elsewhere in the U.S.
Major reasons given by executives for the flow of non-U.S. capital are the country's ready infrastructure, accessible lease market, and intriguing new plays.
Low taxes and stable government conditions have some effect, but in an age of Soviet glasnost and European unification, other officials discounted those as major considerations.
Non-U.S. companies seem content with expectations of relatively smaller structures and field sizes in the U.S. but are frustrated with permitting required by multiple agencies and open ended legal liability. They fear serious consequences if drilling fluids are regulated as hazardous wastes.
Australian firms are particularly keen on gas field development off Texas and Louisiana, even though their own country's gas reserves have barely been tapped. The reasons are simple-pipelines and open leasing.
Non-U.S. independents especially have boosted upstream spending in the U.S. since 1988 (see table). Many U.S. oil companies have begun to emphasize overseas E&D during the same period. Figures compiled by Salomon Bros. Inc., New York show that Royal Dutch/Shell Group and Ste. Nationale Elf Aquitaine have slashed U.S. outlays since 1988, but most other non-U.S. firms have increased their spending, mainly in the Gulf of Mexico, South Texas, and Four Corners area.
SALOMON SURVEY
The 20 non-U.S. majors and independents extracted from the Salomon Bros. survey collectively plan to increase spending in the U.S. by a larger percentage than all majors and independents surveyed by the firm.
The 15 non-U.S. independents expect to increase E&P spending in the U.S. by 33.1% to $503 million in 1990, while all of the independents surveyed expect a year to year spending increase of 24.7% to $5.201 billion.
Spending expectations for 1990 have risen sharply since 1990 budgets were assembled last December. At that time, Salomon Bros.' overall group expected to spend only 11.7% more this year than last year (OGJ, Jan. 22, p. 22).
Salomon Bros. also points out, however, that 26.3% of all the independents surveyed are underspending their budgets.
It blames lower than forecast oil and gas prices for the shortfall.
A group of 65 majors and independents surveyed expects to increase spending outside North America by 24.7%, nearly double the 12.6% hike projected by 65 operators in December.
The 20 major companies in the July survey plan to spend $13.16 billion on U.S. E&P in 1990, 5.9% more than 1989's $12.423 billion. In December, 19 majors had forecast a 6% spending increase.
Five non-U.S. majors surveyed, however, plan to hike 1990 U.S. expenditures by 10.9%, to $2.792 billion from $2.517 billion in 1989.
Here are accounts of how several non-U.S. companies are approaching operations in the U.S.:
AMPOLEX
One firm that is fairly new to the U.S. E&D market but is finding gas onshore and offshore is Ampolex (Texas) Inc., a unit of Ampol Exploration Ltd., Sydney. Ampolex opened its Denver office in 1985 and bought interests in Powder River basin projects.
"The idea was to put a toe in the water," said Vice Pres. and Gen. Manager Brent D. Emmett. Since then, Ampolex has jumped in with both feet. In 1987, it bought all of the U.S. oil and gas assets of Ranger Oil Ltd. for about $18 million, with which it gained entry into the Paradox and Williston basins.
"That gave us the critical mass to do things more on our own account," Emmett said. "We found the Powder River basin program to be very profitable, and we're quite excited about the Paradox basin."
Overall, Ampolex has spent about $40 million in the U.S. since 1985, including outlays as a result of a 20% interest in a Seagull Energy Corp. gas discovery off Texas last March. That well, in 240 ft of water on North Padre Island East Addition Block A-72, flowed 2 MMcfd through a 12/64 in. choke with 1,806 psi flowing tubing pressure from perforations at 4,872-84 ft.
The U.S. energy industry's educated workforce and downstream access are its main assets, Emmett says. "We are exploring in very mature areas, and you've got a lot of completion and production knowledge, which helps minimize the risks after discovery.
"There is also a very well developed infrastructures good pipeline system and distribution system-where we can sell what we produce."
A second plus for American E&D is its readily available leaseholds, something Emmett terms "fairly hard to come by" in other parts of the world.
"In Australia, for example, minerals are owned by the crown, the federal government. Exploration permits are very large and you can hold them for long periods of time."
TUSKAR GROWTH
A similar opinion was voiced from across the Atlantic. Tuskar Texas Inc., Houston, a unit of Irish concern Tuskar Resources plc, also came to the U.S. 5 years ago but has only recently become active in South Texas. In 1985, said Pres. Ian Cooling, Tuskar invested in California production interests.
"Then came the oil crash," Cooling said. "Our plans were put on hold for economic reasons, so that's why we haven't been very active. We're starting to come back now."
In June, Tuskar acquired Hagen Greenbriar, Houston, an oil and gas company with about 22,000 acres under lease in three areas of Texas. One block is in Gonzales County, where it has drilled a Cretaceous Austin chalk horizontal well, the first of a five well program that Cooling hopes will generate enough cash flow to bankroll the other two areas.
"We have a fairly aggressive drilling program," he said. "We are quite bullish about Texas."
Tuskar also holds 30% of a medium risk drilling project on salt domes west of Houston. A third high risk venture is planned in deep Jurassic Smackover of southern Gonzales County. It also is in negotiations for 11,000 more acres in South Texas.
"The situation onshore in Texas is really good, in comparison with England," Cooling said. "Each country has different problems. You have a unique situation here in that most onshore operators are domestic oriented. They are not familiar with the international market.
"The infrastructure is in place. Planning and getting permits are much easier because everybody knows the business. The industry is much more deep rooted in Texas."
Cooling also finds surface owners in this country much more amenable to having drilling rigs on their property when they also own the minerals. Their financial interest in the outcome is a major reason, although Tuskar rarely pays more than 20% royalty.
"The government gets the royalties in the U.K., not the landowner," Cooling said. "All he gets is surface money which is not worth his trouble. So here you have a landowner who wants you to drill, not just in Texas but in the U.S.
"I have no problem paying the landowner's royalty. I think he deserves it."
GOVERNMENT ROYALTY
The general tax structure and government royalty offshore played a part in most firms' decision to explore in the U.S.
A spokesman for American Petrofina says flatly, "The reason we are here is the low tax regime and stable political environment. That's the No. 1 reason Petrofina decided to come to the U.S. in the first place."
In June, Petrofina Delaware, a unit of Petrofina SA, Brussels, drilled a gas discovery off Louisiana in Mississippi Canyon Block 441 about 53 miles south of New Orleans in 1,427 ft of water. The well flowed almost 18 MMcfd from 144 ft of perforations in what an official said is "a very good reservoir."
Petrofina holds a 30 1/2% interest, operator Enserch Partners Ltd., Dallas, 37 1/2%, and Agip Petroleum Co. Inc. Houston, a unit of Agip SpA: Milan, 32%.
Ampol's Emmett is another official who cites tax incentives as reasons for his company's increased U.S. activity. Most other countries want-and take-a bigger chunk of the revenue pie.
"The U.S. has a more favorable tax regime," Emmett said. "Offshore, for example, we pay our one-sixth to the federal government and that's it. That's very attractive, compared with other offshore development. The Gulf of Mexico is a world class place to explore."
Emmett says state governments' tax measures to encourage onshore E&D and maintain production are yielding the desired effect.
"In some areas we're seeing a reduction in the severance tax for enhanced oil recovery. That has given us incentive to participate in those sorts of projects. I would like to see all severance taxes done away with, but that's a bit unrealistic."
NIPPON
U.S. taxes were not the determining factor-even though they are viewed as an advantage-for Nippon Oil Exploration U.S.A. Ltd., Tokyo, (NOEX) locating its Western Hemisphere headquarters office in Houston, says Executive Consultant Victor S. Pesce.
He is directing Nippon's acquisition and planning efforts and helping start its exploration and production network, in addition to advising NOEX Pres. Hiroyuki Horiuchi.
"The tax structure was not a driving force for us being here," Pesce said. "A lot of it has to do with the overall political structure of the country and its need for oil. Other places don't have the stability of government, but they may have more reserve potential."
Pesce cited four major factors, in Nippon's view, that still make the U.S. attractive-its need for hydrocarbons, a good political system, easy transportation, and still viable energy reserves.
NOEX parent Nippon Oil Co. Ltd. had been involved the past 2-4 years in a pair of joint ventures operated by Chevron U.S.A. Inc. and Texaco U.S.A. in the Rocky Mountains, West Texas' Permian basin, Alaska, the Gulf of Mexico, onshore and offshore California, and other parts of the U.S.
By early 1990, the venture's prospects were essentially drilled up, Pesce said. The parent company wanted to continue in the U.S., but it didn't want to be a passive partner. It wanted to be an involved company.
After forming NOEX, Nippon opened the Houston office. Its main objectives are to start its own E&D program, assess acquisitions, and continue to invest in farmouts.
"Our primary intent is to explore in the Gulf of Mexico, going to lease sales with our own prospects," Pesce said.
NOEX plans to stay in shallow water for now even though it realizes reserve potential is much smaller than deepwater gulf leases.
"We are limiting our Gulf of Mexico exploration to 600 ft depths or less, at least in the near future. That may change. The infrastructure is there. Technology is there," Pesce said. "We can get on production a little quicker, and pipelines are not too far away."
BHP PETROLEUM
A large Australian firm that has been active in the U.S. since 1975, BHP Petroleum (Americas) Inc., Houston, has stepped up its offshore and onshore E&D since acquiring Energy Resources Group and Monsanto Oil Co. in 1985.
It is especially active in the Gulf of Mexico, on the Texas Gulf Coast, in West Texas, North Louisiana, Oklahoma, southern Kansas, and in the Green River basin of Central Wyoming and Northwest Colorado, said inland Vice Pres. Ed Jones.
BHP also has invested $1.5 million in a 10 well coalbed methane pilot program in New Mexico's San Juan basin. It plans to drill another 15 wells at a cost of about $2 million by yearend.
In its earlier years, BHP spent most of its E&D budget onshore, Jones said, but that trend changed last year. "Now it's probably at least two-thirds offshore and one-third onshore, roughly."
BHP drilled 14 offshore wells in the fiscal year ended May 31 and plans to drill about 20 exploratory wells in the Gulf Coast region this fiscal year.
Overall, Jones figures it has spent "$200 million plus" on U.S. exploration and $215 million on development since 1985.
The company's expectations for reserves are quite a bit lower for U.S. wells, but he agrees with others that the "combination of prospectivity, political stability, and fiscal regime" offset the lower recovery. BHP expects about 100 bcf, or about 10 million bbl of oil equivalent, on average from each of its Gulf Coast wells.
"We are looking for generally bigger wells elsewhere," Jones said. "Our targets outside the U.S. are maybe tenfold larger."
U.S. seismic data availability reduces risks geologically even though reserves are smaller.
Although the U.S. tax regime is generally good, Jones points out what he feels is a disadvantage for smaller operators-fixed surcharges on top of onshore royalties of nearly 20%.
"One thing we have noticed as a company is the fact that marginal projects are sometimes killed because of severance taxes. But that's not a big concern with us."
Of concern to BHP, however, is the statutory definition of hazardous waste, in light of the cost and legal problems in disposing of it.
"We certainly hope to retain the exemption made in laws classifying hazardous waste for substances such as drilling mud," Jones said. "if that were classified as hazardous waste, it would be a killer for the U.S. oil industry."
Jones also criticized U.S. regulatory snags, such as having to deal with as many as 300 taxing entities vs. only one or two in other countries. And in parts of California, more than 20 permits are required for each well. So many duplications and permits increase costs.
Australians also have difficulty with constant changes in environmental regulations. "That adds to the complexity and uncertainty," Jones said. "Another thing people in Australia have trouble understanding is the litigious society you have here, the unlimited liability."
ARAN ENERGY
One official critical of the economic scheme in the U.S. is Aran Energy Corp. Pres. Archie R. Thompson.
Aran, a unit of Aran Energy plc, Dublin, is a relative newcomer to the U.S. scene, having opened its North American headquarters office in Houston last November.
The company got a foothold in the U.S. when it acquired some leases as part of an acquisition in Europe about 2 years ago. Thompson says it plans to expand its U.S. presence, which includes holdings off Louisiana and onshore Texas and Louisiana. It also has some producing leases in South Texas, Wyoming, and Colorado.
Aran was active in the March 1988 and March 1989 Gulf of Mexico lease sales and has bought interests in 12 blocks in the Gulf of Mexico ranging 12.5 to 100%. It will operate three of those projects.
"Right now, our focus is on the Gulf Coast," Thompson said. "So far, we have acquired only exploration plays. We haven't been involved in significant production. Hopefully, after 2 years we can evaluate where we are and see where we're going. We are pleased with what we have purchased up to now."
One criticism of the U.S. market from the Irish firm is its lack of a general energy policy. "Overall, a national energy strategy probably doesn't exist," Thompson said. "It's catch as catch can. It's more of a regional strategy than national."
Although Aran pays the U.S. government an average of less than 20% royalties on its offshore leases, Thompson is less than enthusiastic about the overall fiscal system. "When you are taking the risk, and find oil and gas, then have to pay off the top to someone who hasn't invested anything that makes it harder. In relative economics, the U.S. just doesn't stack up any more."
NAVAJO PROJECT
A joint venture exploration project operated by Chuska Energy Co., San Antonio, in the Paradox and San Juan basins of Utah, New Mexico, and Arizona has attracted investments from six Brisbane firms.
They are Magellan Petroleum Australia Ltd., Amadeus Oil NL, Australian Hydrocarbons NL, Bligh Oil & Minerals NL, Crusader Ltd., and Jundavik Petroleum Inc.
The Australian companies entered the joint venture in 1988 and have invested about $20 million, said Roy M. Hopkins, Magellan's managing director. Magellan has accounted for about one fourth of that amount. The project is entirely within the Navajo Indian reservation.
Magellan became interested in the U.S. in early 1988 and agreed to enter the Four Corners project in mid-1988. This decision, Hopkins said, was based on these main factors: low E&D costs coupled with shorter lead times to place discoveries on production, good tax conditions, and the "uniqueness of the play."
Of the uniqueness factor, he said, "The very prospective Navajo land had not been subjected to any sustained exploration for 20 years or so and, therefore, was considered to be attractive for evaluation using modern exploration equipment."
The venture has shot about 1,000 line miles of seismic surveys in the first 50,000 acre block near Aneth oil and gas field in the Paradox basin. Data have shown numerous reef buildups, Hopkins said, which are prolific oil producers in that area. Exploratory drilling of the reef prospects has begun.
The cost of a dry hole in the Paradox basin can be 1/10 the cost of one in the Amadeus basin of Central Australia, Magellan's main operating area. And with pipelines nearby, lead times for development in the Four Corners area are relatively short. "Development of oil and gas reserves in the remote and poorly serviced Amadeus has taken years," Hopkins said.
Magellan also finds U.S. tax laws more favorable for oil companies. The Australian regime, he said, has no incentives to offset negative factors such as low prospectivity and high capital and operating costs.
GREAT WESTERN
One firm, Great Western Resources Inc., is based in Houston with all of its assets and management in the U.S., but all shareholders are in the U.K. Founded in 1982, GWR paid $144 million in December 1986 for the U.S. oil, gas, and coal assets of Bow Valley Industries Ltd. after a series of smaller acquisitions.
"The focus of the company's exploration program since November 1987 has been in the Gulf of Mexico," said corporate development Vice Pres. Michael E. Humphries.
GWR has drilled 18 wells, including 16 discoveries, off Louisiana in East Cameron and South Marsh Island areas. It is operator of six of the seven blocks in which it owns interests.
The company has so far spent about $56 million on its offshore operations and has net production of 40-45 MMcfd.
Humphries said that figure will surge to 50 MMcfd in late 1990.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.