State’s Energy Supply Faces Greater Squeeze : Environmental Concerns, Dwindling Reserves Will Hike Prices, Analysts Say

Off the coast of Santa Barbara sit three oil platforms, part of a 10-year-old, $2-billion investment in California’s energy future. In all that time, they have yet to produce a drop of oil--and it’s anyone’s guess when they will.

In 1979, Chevron Corp. and a consortium of oil companies paid more than $500 million for the rights to develop the Point Arguello field, an undersea reservoir of oil and gas estimated at between 300 million to 500 million barrels. It is one of the most significant finds since the vast North Slope field in Alaska, company officials said.

The companies already have built three platforms, 26 miles of pipelines and sizeable onshore facilities. But regulatory, environmental and community challenges have kept the project on hold, consuming $500,000 a day in interest alone.

In August, the California Coastal Commission handed the project its latest setback, denying a request to use tankers to transport crude to onshore processing plants, arguing that Chevron had not sufficiently explored the use of environmentally safer pipelines.

“We’ve been after this thing for 10 years now, and we may well be another year away from doing it. . . . To say it’s difficult is an understatement,” said Richard J. Harris, general manager of the Western region land department for Chevron.

Conflicting Forces

The project exemplifies two forces in California: those that want to develop the state’s energy supplies and those that want to control that development. As California relies increasingly on dwindling energy reserves both at home and in Alaska, those forces will come more into conflict, exacerbated by the state’s energy isolation from the rest of the country, observers said.

“There is going to be a big contradiction or clash between the economic public good and the environmental public good, and it will be more pronounced in California than anywhere else in the world,” said Fereidun Fesharaki, head of the energy program at the East-West Center in Honolulu, a nonprofit research center funded by the federal government.

For the average consumer, the long-term outlook could mean either limited supply, higher prices, or both.

“We’re going to be worse off than the rest of the country in that respect,” said H. D. Maxwell, president of Unocal Corp.’s oil and gas division.

In many ways, California is a unique and isolated energy market. It is defined on the north and east by mountain ranges and on the west by the Pacific. No major pipelines bring crude or refined products into the state from other parts of the country.

Any outside oil--even from the Gulf of Mexico--must come in by tanker.

Similarly, there are only a couple of major pipelines bringing natural gas into the state, mainly from the Southwest, though several projects have been proposed.

None of which has mattered much recently. California exports oil to other parts of the country. It ranks fourth among the states in oil production, second in production from the outer continental shelf, according to state estimates. It is practically the sole source of refined product for Arizona and Nevada, according to the California Energy Commission.

But the state’s comfortable supply situation may change in the long run. For one thing, California remains increasingly dependent on just two sources of oil: its own fields and those on the North Slope of Alaska.

California can handle short-term disruptions in supply, such as the Exxon Valdez oil spill in March, although such interruptions mean higher prices. “There’s enough elasticity in the world petroleum market and on the spot market that shortages could be made up over a short period of time,” said Charles R. Imbrecht, chairman of the California Energy Commission. The commission has put together a detailed plan to meet such contingencies, ranging all the way up to a major disaster that shuts off the Alaskan spigot entirely.

But in the long term, “I certainly have to say that over the next 20 years, we face the dilemma of having to depend on foreign imports,” he said.

Perhaps the most important factor is the decline of the Alaska reservoir, which provided 43.2% of the 708.8 million barrels of crude received by state refineries in 1988, according to Energy Commission figures. The rest was supplied by state fields, 51.5%, and foreign imports mainly from Indonesia, about 5.2%. In the first half of 1989, Alaska accounted for 46.8% of California refinery crude.

Unusual Decline

Production of oil, natural gas and condensates from Alaska’s Prudhoe Bay fields began to decline in 1988 from a peak of 1.6 million barrels per day, with this year’s production expected to amount to only 1.4 million barrels, said Albert Greenstein, a spokesman for Atlantic Richfield Co. in Los Angeles.

This year’s sharp decline is unusual and partly attributable to warmer weather and the Exxon spill, both of which reduced production. But Greenstein said Arco expects Alaskan production to continue to fall at an average annual rate of 4% to 5%.

State reserves remain promising, both offshore and inland, particularly from the century-old fields in Kern County.

But development of those resources may be restricted by a number of things.

Air quality restrictions are limiting the amount that oil companies can expand plants to generate the steam necessary to extract thick oil from Kern County fields. The restrictions also require the plants to burn more natural gas to generate the steam.

But natural gas needed by these so-called enhanced oil recovery projects is limited by available pipeline capacity. A number of competing pipelines are now vying for approvals and customers to bring such gas into Kern County from Canada, the Southwest and the Rocky Mountains, but none has been built.

Plans to develop offshore oil reserves have been stymied in the wake of the disastrous Valdez spill. Eleven new offshore platforms and six man-made islands are proposed or under construction in state and federal waters offshore, to be added to the current 29, according to the Coastal Commission.

But in July, Congress passed two versions of a one-year moratorium on drilling off most areas of the U.S. coast. A moratorium would postpone until at least October, 1990, any pre-lease activity on proposed lease sales off the California coast.

Report Due Soon

The moratorium could affect the proposed sales of three major lease areas: Lease Sale 91 off Northern California, scheduled this month; Lease Sale 95 off Southern California, scheduled for April, 1990, and Lease Sale 119 off Central California, proposed for March, 1991.

Earlier, President Bush indefinitely postponed the leasing of 91 and 95 while a task force studied environmental issues. The task force is scheduled to make its report by Jan. 1.

Meanwhile, the California Coastal Commission has voted its objections to the three lease sales, citing what it considers unacceptable risks of oil spills, air pollution, visual blight and conflicts with the fishing and tourism industries.

In any case, the commission estimates that total production in the Santa Barbara Channel and the Santa Maria Basin, the most productive areas of the outer continental shelf off Southern California, could peak in 1999 at 247,600 barrels of oil per day.

No one disputes the need for environmental care, particularly given California’s smog problems and the destruction from the Exxon oil spill. But that doesn’t lessen the frustration of executives such as Maxwell. “I’m not implying that we shouldn’t do these things, but the result will be a lower supply of California crude and a greater dependence on imported crude,” he said.

Of course, environmentalists and others argue that the simple solution is to reduce demand. “I think the issue here is one of looking at both the demand side as well as the supply side issues,” said David Goldstein, senior staff scientist with the Natural Resources Defense Council’s San Francisco office. “If there’s a restriction on refinery construction, that means either you’ve got to build more refineries (somewhere else), or reduce demand to the capability of existing ones . . . and from an economic viewpoint, it’s easier to reduce demand than to increase supply.”

So far, however, demand for refined products in California continues to increase, rising to 565.8 million barrels in 1988 from 502.1 million in 1984, the Energy Commission reported. Yet it’s been nearly 20 years since the last refinery was built in California.

Squeezed margins prompted refiners here and around the country to close marginally efficient refineries in the early 1980s--removing about 13% of the state’s refining capacity, according to one estimate. California ranked second in refining capacity among the states in 1988, accounting for about 16% of total capacity, according to state figures.

Tighter state and federal emissions regulations and increasing demand for higher grades of gasoline meant that refineries needed more crude to produce the same volume of gasoline. Refiners were able to keep up by increasing plant efficiency and “debottlenecking” operations.

But as prices fell and demand increased, refineries found the need to run at much higher rates, many over 90% for much of this summer.

Still, there is little incentive to build new refineries. It would cost about $2 billion to build a new 235,000-barrel-per-day refinery in California--and that’s provided a refiner could get the necessary permits, hardly a sure thing in an era of increased environmental awareness.

If there were to be a major disruption in the supply of gasoline or refined product, they would have to be imported by tanker--there are no major pipelines to bring such products into the state.

That could take weeks to arrange. Among other things, gasolines would have to meet California’s strict emissions standards.

All of which could mean a sharp spike in prices, as evidenced by the fallout from the Exxon Valdez spill.

Risk Increases

The tightness of the market was again demonstrated by a fire last month at a Shell Oil Co. refinery in the San Francisco Bay Area, which caused prices for future gasoline contracts to jump more than a penny a gallon in one day.

The surprising thing about the Shell fire was not that it occurred, but that it hadn’t occurred sooner or in a bigger way, observers said. “Obviously, with mechanical equipment, there is some greater risk whenever the equipment is pushed harder,” said Robert Cunningham, a vice president with the Dallas consulting firm of Turner, Mason & Co. “If you drive your automobile across country at high speed, rather than just across Los Angeles, you have a greater chance of mechanical breakdown, particularly if you’re doing it for hours in a row,” he said.

“You add those things up, and it adds up to tighter product availability and higher prices, and the only thing that can overcome the (problem) is the incentive to make the investment to make the product available--which again means higher prices . . . or building capacity overseas,” said Dennis Lamb, a manager of planning at Unocal. “We’re virtually being forced offshore,” he said.

“There is a fundamental contradiction in California’s approach to (energy) problems,” said Richard Gordon, director of market analysis with the Petroleum Finance Co. Ltd. in Washington. “They are simultaneously restricting supply--and that’s what’s happening, whether you’re talking about restrictions on refiners or delays in bringing supply into the market. . . . At the same time, though, there are a number of key factors--growth in California, demographics, economic demand--saying we need more supply. . . . That’s not a sustainable situation.”