MISC. SELECTED NEWS STORIES - SUNDAY A.M. 10/18/98
Motley Fool Hero's Of Friday 10/16/98
Offshore oil and gas drilling rigs operator R&B Falcon Corp. (NYSE: FLC) pumped out a $1 5/8 gain to $11 1/2 after signing a letter of intent with natural gas and hydrocarbons production company Vastar Resources (NYSE: VRI) to construct an ultra-deepwater semisubmersible drilling rig, which is expected to generate a total of $220 million in revenues for R&B Falcon over three years.
Elsewhere in the oil patch, energy services firm Halliburton (NYSE: HAL) picked up $4 1/16 to $34 after forming a joint venture to develop oil and gas assets with Russian oil producer Tyumen Oil Co.
Other oil drillers and services firms rose as well, as one industry analyst speculated to the Motley Fool that investors may be rotating into the cyclical sector. Schlumberger (NYSE: SLB) added $4 7/8 to $52, Transocean Offshore (NYSE: RIG) rose $2 3/8 to $30 7/8, Baker Hughes (NYSE: BHI) gained $2 11/16 to $21 11/16, Varco International (NYSE: VRC) moved up $1 5/8 to $8 5/8, Cooper Cameron (NYSE: RON) advanced $5 1/4 to $35, and Noble Drilling (NYSE: NE) jumped $2 to $15 1/4.
Here We Go Again
The oil surplus won't last as long as we might wish
By James Srodes (JAMES SRODES is a Washington writer specializing in international business)
October 19, 1998
Most news analysts got it wrong when they credited low oil prices for the recent proposed $48 billion takeover of Amoco by British Petroleum. What's really driving this mega-merger is an impending global oil shortage that will have profound economic and social implications. Seen in this light, the BP-Amoco merger makes short and long-term sense, and the light also shines on other oil companies.
For European companies like BP, marriages of convenience with American merger partners will offer shelters for profits from the uncertainties of the European monetary union. Also, there will be cost savings from cutting staff and consolidating offices. And U.S. oil companies like Amoco bring retail service-station networks and refineries into the world's largest market for petroleum products. But most of all, the new hybrid giants will have the muscle to survive critical challenges that loom in the not-too-distant future.
Behind the BP pursuit of an American base is a recent series of alerts from many respected petroleum engineers, acknowledged by oil-industry executives and government energy planners: We rapidly approach the point where the global output of new discoveries of oil will begin to contract sharply even as the world demand for energy products becomes still more acute.
Put most simply, a consensus has formed in recent months that within a few years new supplies of conventional oil energy will be outstripped by spiking world demand. Very soon after that the real volume of oil output will begin to shrink abruptly -- even as demand growth coasts a bit higher.
We've seen this before, but the 21st century's supply disruptions and soaring prices will dwarf the OPEC crunches of 1973 and 1979.
The best industry estimates reckon that the world began this year with 1,020 billion barrels of oil in "proved" reserves. At the current production rate of 23.6 billion barrels a year, these supplies would last only another 43 years -- if there were no growth in demand.
As for growth in supply, the industry has spent the past 20 years exploiting a new age of discovery technology. Now many oil geologists say that 90% of the globe's oil fields have already been tapped and many are already exhausted.
Bigger Problem
There are several things wrong with the current consensus. Many of the OPEC nations have been inflating their estimates of proved oil reserves. More obviously, consumption of oil products has already jumped by 50% in Asia and by a third in Latin America, since 1990. By the estimated peak production year of 2010, world demand will have risen by more than 60% to as much as 40 billion barrels a year. Finally, there is the geological bad news that once a mature oil field reaches the midpoint in its productive life it becomes harder to pump out each remaining barrel. Examples of mature fields include much of the Middle East, the North Slope and the North Sea.
Two remarkable things about this latest crisis outcry are how recent it is and how authoritative are the alarmists. It was only last November that two top oil geologists presented papers on the impending oil depletion to a conference of the International Energy Agency of the United Nations in Paris. Colin J. Campbell, an Oxford-trained geologist, and his French counterpart, Jean H. Laherrere, have been senior geologists for firms such as Total, Texaco and Amoco for more than 40 years. Currently they work at the industry think tank Petroconsultants in Geneva.
The two geologists were so convincing that the IEA dropped a generation-old view that held oil discoveries to be merely a function of price -- that is, the higher the price the more oil will be found. Last March, at the Moscow summit of the Group of Eight major industrial nations, the IEA presented its own paper to the national leaders accepting the Campbell-Laherrere view that sometime between 2010 and 2020 the crisis will be upon us full blast. The Campbell - Laherrere analysis also cut the reserve of oil currently known to be in the ground to about 850 billion barrels.
Since then, others have joined in the public debate. Recently, Franco Bernabe, chief executive of the Italian oil company ENI SpA, has given a series of interviews in which he moved the doomsday clock forward to between 2000 and 2005. He forecast that today's world price for a barrel of oil would soon begin to rise from its $15 base and quickly pass the $30 mark. He forecast that both the British and Norwegian sides of the North Sea will begin to see production declines within three years. The United States passed its peak (even with Alaska) long ago. Left open for argument is the amount of new oil left to be discovered in the Third World.
So much global economic progress depends on the exploitation of oil. Energy from all hydrocarbon sources accounts for 80% of what makes our world go and oil accounts for 38% of all energy used. And it's oil that truly powers economic activity because it produces so much raw lift for activities, since it is so movable and can be used in so many ways.
Most "alternative" energy sources require more energy to get them running than they ever produce. For instance, it takes 71% more energy to produce a gallon of ethanol from grain than the energy contained in a gallon of ethanol will generate in use. A barrel of oil routinely offers 10 or more times the raw power for our activities than it takes to get it, conferring an enormous profit not only on the companies that supply oil but on the entire economy.
Some alternative sources are just the figurative drop in the bucket. Wind generators require technological investments that outweigh the power they can generate, even if every windy hillside is sown with them. Solar cells pay off only in remote locations. Other substitutes are possible and may provide almost as much economic profit. But construction of nuclear reactors or projects to wrench oil from shale deposits have mostly been cancelled during the last 20 years of oil surplus and low prices. And coal, which is abundant and profitable, has environmental costs. The recent uproar when strip miners blasted the top of a scenic West Virginia mountain showed just how much of our environmental consciousness will have to be reassessed during the next energy crisis.
Advancing the Market
This is where market forces come in and why the BP-Amoco merger fits the rough logic of the days ahead. Soon enough the giant oil combines of the next decade will find themselves doing battle with the likes of Vice President Gore and British Prime Minister Tony Blair. The bigger the major oil producers become, the longer they can hold out against the temptations of politicians to redistribute what oil remains. The 'Seventies offer a convincing example of the impulse to tax "windfall profits" and spend the proceeds on vegetarian-style alternative energy sources.
Then very quickly the fight will be over the dwindling petro-reserves themselves. Those nations rich with oil and strong in resolve will get their energy fix. By that standard America can thrive quite nicely; so, too, can countries as diverse as Britain, Mexico and South Africa. Other European Union members will fare according to their ability to command and pay for energy (in dollars and not in euros, thank you).
Much of the social safety net that defines the industrial West will be up for debate again at considerable political pain. Nuclear power, with all the fears it raises, will be back on the policy agenda again.
There will be obvious nations at risk too. Some are already visible on the horizon. Russia, which has lost control of the petro-energy subsidies that made collectivism possible, is imploding before us. Japan, which must import each barrel it uses of economic growth, is adrift. Even some nations that have oil -- Indonesia and Nigeria, for example -- must show they can control it, lest it be poured down the drain of civil strife.
Other productive and oil-rich regions face challenges. The Middle East with its easy pickings grows increasingly unstable with each passing day. Some new fields, such as the Caspian Sea area, are hostage to rival bands of terrorists whichever way their pipelines head.
Finally there are the have-nots, those poor nations strangled by a poverty that can be alleviated only by massive use of more and cheaper energy. Think of China, India or Pakistan unable to obtain the means of prosperity and the picture grows dark indeed. The struggle for national prosperity fueled by energy will not automatically go to the rich and already powerful. The nuclear wild card makes players of all nations.
Left to market forces, the energy producers of the world will find and exploit a range of energy resources at the prices that reflect the needs of the world. But the vision of the last half century -- that anyone can have everything -- is no longer likely.
JAMES SRODES is a Washington writer specializing in international business.
Crude Oil Prices Down In Venezuela
-- Sun, 18 Oct 1998 10:00 EST
The average price of Venezuelan crudes was down 0.92 U.S. dollar per barrel in the past week despite the start of winter season in the northern hemisphere.
As winter comes, market demands often go up, but the crude average went from 11.90 dollars per barrel last week to 10.98 dollars this week, said the Energy and Mines Ministry.
Based on information available so far, the ministry projected that the price this year would average 11.12 dollars per barrel.
The average oil price was 11.22 dollars in the first quarter of this year, and 10.83 dollars in the third quarter. The average price this month is estimated at 11.60 dollars per barrel.
Repeat Of Canadian Oil & Gas Stories The Past Few Days
Change In Strategy For Canadian Oil Companies
Western Canada's not running out of natural gas, but future supplies will increasingly come from smaller pools, says a new study on Canada's natural gas potential.
That means exploration companies will have to change strategy and drill more, shallower wells, rather than look for larger pools at deeper levels, said consultant Robert Meneley, one of the study's authors.
"There is a lot of gas in Canada. Drawing it out is a question of [commodity] price," he said.
Canada's recent discoveries are coming from pools containing about one billion cubic feet each. In the 1970s, the average new gas pool contained about four billion cubic feet.
Some large pools remain to be found in Western Alberta and the Rocky Mountains foothills, he said.
The study, sponsored by the Canadian Gas Potential Committee, a volunteer group of geologists, geophysicists and engineers, estimates Western Canada has 62 trillion cubic feet of remaining gas reserves, plus undiscovered potential reserves of 122 trillion cubic feet, for a total of 184 trillion cubic feet. Canada produces six trillion cubic feet a year.
The estimate does not include natural gas in relatively unexplored areas like offshore British Columbia, the Arctic, the Yukon, or unconventional sources like coalbed methane.
David Manning, president of the Canadian Association of Petroleum Producers, said the emphasis on smaller pools doesn't mean major producers will leave the basin and head for frontier areas where there's still potential for large discoveries. "They will just be more innovative in their approaches to smaller pools."
The survey estimates 60% of Canada's new gas reserves will come from 200,000 smaller pools.
In the past 10 years, exploration drilling has resulted in the discovery of about 1,000 gas pools a year.
The study, based on public and confidential data supplied by exploration geoscientists from across the industry, found that the undiscovered gas potential in the Western Canadian basin is distributed 80% in Alberta, 15% in British Columbia, 2% in Saskatchewan, 2% in the Northwest Territories and 1% in the Yukon.
Additions to natural gas supplies from conventional reservoirs are expected to come mostly from existing plays and revisions. Only 12% will come from newly discovered plays.
Canada Must Crank Up Gas Drilling, Say Geologists
A Canadian geology organization on Thursday added its voice to a growing chorus of energy experts saying the industry must crank up the number of natural gas wells it drills each year to maintain production and meet growing demand.
Exploration results in western Canada during past decade indicate that most new gas discoveries are coming from smaller deposits, or pools, typically containing one billion cubic feet each, according to research conducted by the Canadian Gas Potential Committee, a group of volunteer geologists, geophysicists and engineers.
That compares to average reserves per discovery during the 1970s in the four billion cubic feet range.
"Most of the new reserves will come from smaller accumulations," Bob Meneley, the committee's senior analyst, told reporters on Thursday. "Industry will have to drill many more gas wells in western Canada."
He did not offer an opinion on how many more wells would have to be drilled to uncover the smaller pools at a quick enough rate. But he said about 60 percent of western Canada's new reserves would be found in an estimated 200,000 smaller pools and an estimated 5,000 new pools would have to be discovered each year. Other analysts have said recently that the industry would need to drill far more than 6,000 gas wells annually over the next five or 10 years to meet demand. Canada's gas producers are projected by brokerage FirstEnergy Capital Corp. to drill just 4,600 gas wells this year.
The committee said a shift to smaller exploration targets in western Canada did not mean that the country's gas supply was waning, however, even as production rises to an expected level of six trillion cubic feet a year.
In a 1997 report, the group estimated western Canada alone had 62 trillion cubic feet of remaining gas reserves, plus undiscovered marketable gas potential of 122 trillion cubic feet. The estimates do not include resources in frontier regions such as the high Arctic or unconventional sources, like coalbed methane.
The committee also announced on Thursday that it named former Canadian National Energy Board Chairman Roland Priddle as its chairman, as it works to compile another report on gas potential by the year 2000.
Alberta Gas Producers Face Shortfall, Analysts Warn
Alberta natural gas shippers could find themselves running out of product if a long, cold winter sets in, says a Calgary gas analyst.
Martin Molyneaux, an analyst with FirstEnergy Capital Corp., said yesterday, based on his revised estimates, TransCanada PipeLines Ltd. could face a shortfall of up to 1.4 billion cubic feet a day from field production. Gas in storage will only be able to meet up to 1.1 bcf/d of demand.
TCPL released figures last week showing it will meet expected demand of 13.8 billion cubic feet a day during the winter months through 12.9 bcf/d from field production and 900 million cubic feet a day from storage.
But Molyneaux said he believes field production will be lower, only reaching 12.5 to12.7 bcf/d.
"[Producers] are not drilling at that level yet," he said.
Pulling 900 million cubic feet a day from storage is "stretching the envelope, but do-able. It becomes an issue of supply at what price."
Alberta has storage capacity for 185 billion cubic feet of gas.
Last year, TCPL met 13.1 bcf/d of demand with 12.4 bcf/d from field production and 700 million cubic feet a day from storage.
Analysts believe depleted storage and lower than expected production will push natural gas prices up next summer.
Molyneaux has revised his price to $2.75 a thousand cubic feet for 1999, up 20¢ and substantially higher than the $2.20 to $2.40 a thousand cubic feet Canadian producers are using for their 1999 budgets.
In order to fill TCPL's expansion Nov. 1 of 400 million cubic feet a day and another smaller expansion by November 1999, 18,000 gas wells will have to be drilled and tied in.
That will likely take until the end of 2002 to achieve, he said.
The number of gas wells coming on stream this year will be 10% fewer than expected at about 4,600 wells, Molyneaux estimated.
Pipeline capacity will increase to 14.2 bcf/d this winter with TCPL's expansion and Northern Border's addition of 700 million cubic feet a day.
Bob Reid, president of TCPL's Canadian mainline, said all firm contracts will be met. He expects supply to remain tight through next summer but move into balance by the fall.
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