Bruised, but unbroken:
Markets and mergers. More precisely, bad oil markets and big oil mergers turned last year's happy days of January into the sleepless nights of December for energy professionals, managers, and executives.
The cause of last year's bad oil market is no mystery: More oil was available than users wanted to buy.
Big mergers were done for a variety of reasons, most not directly related to the oil prices of the moment.
There was more to it than that. Companies looked across the valley of low oil prices and saw...well...more valley, not the upslope on the other side.
In many ways, the year just past tested the petroleum industry's faith in the new lessons it has learned since the 1980s. Lessons about how to use new ideas, new technology, and new organizations to compete in the wide-open energy market of the future. How to take the long-term view. How to innovate, create.
In some ways its faith in new thinking passed the test. But some responses were, say, more traditional.
Happy daysWhen the year began, U.S. light sweet crude was already more than $7/bbl below its price 1 year earlier. Still, at over $18/bbl, the price was still in that "normal trading range."
There was no need to panic.
In fact, oil and gas managers were hiring professionals as fast as they could. Hiring bonuses were paid to new graduates; "staying bonuses" were paid to the best employees. Companies were preparing for the future, building for the coming expansion, for the long term.
True, global economic growth was slowing. Currencies and regimes in Southeast Asia were crumbling. Winter in the Northern Hemisphere was, for energy sellers, frustratingly mild.
And the dollar cap on the amount of oil Iraq could sell was doubled.
But the modern energy executive does not panic. He or she knows that volatility is a fact of life in today's global oil market. And Asia's troubles? They might last a couple of quarters, then stabilize and soon resume growth.
The Organization of Petroleum Exporting Countries and other oil exporters in late spring agreed to cut production. Such an historic event was bound to firm up the market.
Sleepless nightsBy early November, markets had gotten weaker instead of stronger. OPEC members made 80% of the 2.6 million b/d of production cuts they pledged.
But support for the effort was as hard to maintain as ever. In the face of the lowest oil prices in more than a decade (see charts, p. 20), Nigeria, Indonesia, Venezuela, Qatar, and Iran produced 390,000 b/d more in November than in October.
Through it all, effectively unrestricted by United Nations sanctions or economic discipline, Iraq's exports of almost 2 million b/d held global oil prices under water while the rest of the world's producers struggled to breathe.
Perversely, product markets were weak around the globe, too.
Even with every car manufacturer from Ford to Cadillac to Lexus-and soon Porsche-selling big-engined sport utility vehicles in the U.S. as fast as they could make them, gasoline was as cheap as ever.
Feedstock costs were low; still, refiners' margins were, well...marginal.
By fall expectations-and moods-had changed dramatically from those at the first of the year.
The price of U.S. light sweet crude was at a 12-year low. Brent blend fell below $10/bbl, a record low for the reference North Sea crude.
As bad as that was for some producers, it unfortunately was the best news. Heavy and sour crudes sold at prices deep into the single digits.
The International Energy Agency early in December reduced its forecast for world oil demand in the fourth quarter by 650,000 b/d to 75.7 million b/d.
As late fall became early winter, Northern Hemisphere temperatures, especially in the U.S., were pleasant.
No one wanted to be a whiner. But the oil market just wasn't as much fun any more.
Oil price stability wasn't all it was cracked up to be when "stability" meant $11/bbl for WTI.
At least volatility implies lows and highs.
Nor was it just the short term that was troubling. What about new energy taxes in Europe? The impact of Kyoto treaty demands? These promise long-term damage to economies, which, in turn, bodes ill for petroleum demand.
Consensus was building that oil demand could be weak well into 2000. Some said perhaps much longer.
The trickle of pessimism from oil markets into capital markets became a deluge by the third quarter. If investors punished oil companies when earnings "disappointed," they positively persecuted service and supply companies.
Donaldson, Lufkin & Jenrette said that, through the third quarter, the S&P Oil & Gas Drilling & Equipment Index dropped 30% vs. a 10% drop in the S&P 500 (see chart, p. 21), the worst relative performance since the first quarter of 1986, when the price of oil fell below $10/bbl. Segments of that industry had fallen much farther by early December. Land drilling/workover companies were down more than 70%, while the S&P 500 was up more than 20%.
In mid-December, oil buyers and investors briefly lost touch with reality and bid up crude futures and oil and service company shares when the U.S. and the U.K. launched military strikes on Iraq (OGJ, Dec. 28, 1998, p. 24). Regaining their senses after 48 hr, it was obvious that little had changed: Iraq exported merrily, demand was still weak, weather was warm, storage was full, and producers had capacity to spare.
By yearend, the picture of energy's future was one that, perhaps, should have carried this warning: "May not be suitable for sensitive viewers."
Such as oil and gas producers, and oil field suppliers.
New ideas, old answersTo survive the 1990s, oil and gas company executives changed the way they thought about markets, organizations, and competitors. Managers changed the way they thought about technology-not just how it worked, but how it should be used and who should pay for it.
Since the early 1980s, the petroleum industry reinvented itself. Companies reengineered everything that stood still long enough. Executives adopted those new paradigms their consultants always talked about. Everyone-at least publicly-obeyed demands to embrace change and make it their friend.
Growing competition was cited as the biggest challenge, technology the way to survive it and prosper.
As people and companies dealt successfully with volatile markets and previously unheard-of change, confidence grew that new ideas could, indeed, solve the market, technological, and political problems of the future.
But it took just a few months of prices near $10/bbl to bring some responses that were quite traditional.
Many companies whacked their spending. They whacked their drilling. They whacked their staff.
In the U.S., there were new calls for federal help for independent producers, for a "comprehensive national policy." Government purchase of oil for the Strategic Petroleum Reserve to "help" producers was suggested (OGJ, Dec. 28, 1998, p. 24).
All these responses might have been part of a new paradigm. But if so, it looked a lot like the old paradigm.
Limited optionsCutting back on drilling, other E&P spending, and staff seems drastic and shortsighted. They seem like old-fashioned remedies. They can wreck individual careers.
But what else should be done?
Companies revert to traditional responses to market conditions because, in many cases, they are the right responses.
If too much oil is damaging business, why spend money to find or develop more? At least, right now.
Industry pledges allegiance to markets driven by supply and demand. Participating in such markets requires constant reallocation of capital and people. Market realities cannot be ignored even though, for individuals who are "reallocated," it can be painful.
That's one of the industry's biggest challenges for the long term: designing hiring programs that significantly reduce the swings in staff levels.
An executive accustomed to managing market risk should be able to do that.
And until it's done, industry's credibility at the college hiring hall will continue to suffer.
A turnaround, but when?Expectations, like energy markets, usually overshoot the mark. Pessimism and optimism obey a law of physics that usually applies to bodies: An attitude in motion tends to remain in motion until acted upon by an outside force.
As pessimism gathered steam last fall, forecasters extended the life of the oil price slump from months to years; then to a decade.
Belief that $17-21/bbl is the "normal" trading range for WTI was challenged. Could $11-14/bbl for WTI be a new trading range instead of a temporary bottom? (OGJ, Dec. 28, 1998, p. 18).
Is 1998 further evidence that, over time, natural resources continue to become more plentiful rather than more scarce as the late Julian Simon preached?
As 1999 begins, market and competitive pressures have not eased. The outlook is for slow economic growth in the best economies, recession in the worst. The resulting weak demand will keep crude prices low.
Economic crises in some regions may also force a temporary setback in attitudes toward privatization that flourished during much of the 1990s. That will delay economic growth and energy demand growth.
Nothing will move oil prices upward-at least for any length of time-until demand begins to grow again.
Prices will never be as high as producers would like. Gas Research Institute forecasts the refiner's acquisition cost of crude, adjusted for inflation, will be $17.50/bbl in 2015.
But extremely low prices, like those during much of last year, increase demand. They decrease supply and excess capacity. Then a new relationship between demand and supply emerges.
It always happens.How much higher prices will go and when, of course, no one is sure. There is one proven theory, however:
Low prices are the best cure for low prices.
Merge and purgeThey just kept getting bigger. Halliburton Co. and Dresser Inc. British Petroleum Co. plc and Amoco Corp. Total and Petrofina (see table, p. 22 [53,248 bytes]).
Then Exxon Corp. bought Mobil Corp. for $75 billion and formed the largest industrial company-not just the largest oil company-in the world.
Based on transactions announced in the first 9 months of 1998, Randall & Dewey Inc., Houston, said U.S. upstream acquisition and divestment activity alone was valued at a total of $38 billion in 255 transactions. Of these, deals totaling more than $23 billion yielded an average acquisition cost of $6.60/boe, including the U.S. part of the BP-Amoco deal. Excluding that deal, value of the reported reserves was $4.99/boe.
David Bole, Randall & Dewey's vice-president of corporate research, sees a "continuing trend toward larger mergers and combinations as prices remain depressed." The goal is, of course, to increase margins.
"Successful deals will be those that overcome valuation issues and social issues about who will run the (combined) company," says Bole.
Consolidation was not new in 1998, but the companies involved raised the significance of the trend by an order of magnitude.
Service companies were doing it in a big way, too. Normal spending cuts gave plenty of reason; merger frenzy added special incentive.
A lengthy merger trend, especially involving big companies, decreases the total need for equipment, services, and people.
The party line-what executives of big merged companies often explained to TV viewers-was that these mergers were driven by the need to be able to "do the big deals," to play in the league with both the big multinationals and the state-owned companies.
Perhaps. But Exxon, Mobil, BP, Amoco, and Total could do almost any deal that made economic sense before they combined with their peers.
A more important reason for these giants-and smaller companies, too-to join forces is ever-growing competition for markets and opportunities.
Companies must continue to increase earnings. If the price of their product cannot go up, two options remain: Increase revenue by boosting volume, or further reduce costs.
Mergers often can help do both.
Is consolidation near an end?
No. Even with the combination of the two largest U.S. companies, there are many more possible combinations.
One analyst even suggested last year that the U.K.'s seven remaining sizable independent E&P companies should be merged into one company.
Traditional combinations of smaller companies, independent companies, struggling companies, and companies that see synergies will continue.
No combination can be ruled out.
What will be the result?
It's not all bad. New opportunities emerge when companies, especially big ones, combine. Properties are divested, some by choice, others to satisfy the demands of trade regulators.
These are opportunities for independent producers or refiners.
And as lean as energy companies have become, bigness still brings problems. A renewed attack on inefficiency often means more outsourcing; new work for service providers, large and small.
Or will companies return to doing more jobs "in house?" Would a big oil company do that by buying a big service company, for example?
It doesn't seem likely.
Providing a given service or technology to several clients, as service companies do, offers more opportunity for profit and growth than providing it to only one "client."
And the forward thinkers' mantra for petroleum companies has been: Buy technology, let someone else spend money to develop it.
No, the outsourcing trend is not likely to be reversed soon. It's been more than 50 years since oil companies began to divest their drilling departments, starting down the path of what is now called "outsourcing."
The path has been uneven, but it has been headed in the same direction for decades. Nothing is now beyond consideration by the "outsourcerers."
Futurists even talk about oil companies becoming "asset managers" only, handing everything from exploration through field abandonment over to someone else.
"Focusing on core competencies" will continue to be a real strategy as well as an overused slogan.
But even with the megamergers of 1998, the time when a big energy company's only job is to watch the cash register is far in the future.
A new industryThe past year wasn't just about bad markets and big mergers.
There also was activity within that global concoction of bad science, bureaucrats, and big tax revenue opportunities that has become the global warming industry.
At that industry's big meeting of the year in Buenos Aires, representatives of 160 nations concluded a second round of negotiations. The U.S. signed the Kyoto global warming treaty there, making it the 60th nation to sign.
The U.S. Senate must ratify the treaty.
In the weeks following the Buenos Aires meeting, balmy weather hung around into early winter in the Northern Hemisphere, especially in the U.S.
It likely was inexplicable to global warming alarmists that there were no reports that energy users frolicking in mild temperatures exhibited almost no fear that an increase of 1-2? in average global temperature over the next several decades would be a disaster.
Nor were there reports that those energy customers showed any outward signs of physical, mental, or economic stress that could be traced to warmer-than-average temperatures.
Both supporters and opponents of drastic measures to limit CO2 production are clear on their respective positions. But, as is often the case, "the petroleum industry" had trouble deciding what it should do about global warming, if anything.
More precisely, the question was what should the industry or a company be seen to be doing.
European companies made much of favoring more study of the issue and expanding their budgets for renewable fuels.
On the other side of the Atlantic, the typical position was that global warming isn't certain and climate change is not cause for alarm.
Still, William O'Keefe, American Petroleum Institute executive vice-president, said the U.S. oil industry wants to contribute to solutions to the potential risks of climate change. He told a congressional hearing that U.S. oil industry leaders believe that some precautionary actions should be taken to reduce the growth in greenhouse gas emissions.
Through all the meetings, treaties, and posturing by all parties, little progress was made in answering completely and objectively three questions:
- Is the climate getting warmer?
- If so, is that a bad thing?
- If it is, can humans do anything about it?
Alive and wellDespite fears to the contrary, privatization is alive and well, even in capitalist countries. Evidence that momentum remains is apparent in these examples:
Saudi Arabia gave every other country that is trying to attract foreign petroleum investment a new reason to be more competitive. Saudi Crown Prince Abdullah ibn Abdulaziz, in a meeting in the U.S. with executives of seven oil companies, asked for suggestions about roles the companies might play in Saudi upstream ventures. Speculation and rumor about what will result from this overture were widespread. But executives close to Middle East oil think it's unlikely such a significant signal would be sent without serious purpose.
In Brazil, Petrobras's 43-year monopoly over exploration, production, refining, distribution, and export and import of oil effectively ended in July. Private-sector investment will be allowed in all parts of the industry, and 93% of Brazil's sedimentary basins will be removed from Petrobras's control and put up for bidding for companies from Brazil and abroad. Companies are eager to participate. But they're finding patience necessary.
The U.S. Department of Energy completed the sale of its 78% interest in Elk Hills oil field near Bakersfield, Calif., to Occidental Oil & Gas Corp. for $3.65 billion, proving that privatization opportunities still exist in one of the world's most privatized countries. Chevron Corp. owns the other 22%. It is believed to be the largest federal privatization in U.S. history.
More, cheaper, easierMaybe technology is to blame for low oil and product prices...yes, maybe that's it!
With the world awash in oil and the ability to find more reserves easier, cheaper, and in more places advancing rapidly, some began to ask, not entirely facetiously:
Is industry too smart for its own good?
Is a gloomy oil market outlook the result of technology that is too effective?
Has 3D seismic run amok?
They are silly questions. There is always good reason for developing new technology.
And besides, technological advance in any given field also obeys that pesky law of physics: Once in motion, it tends to stay in motion.
Knowing their development history, a random sample of technology and operating milestones reached last year is evidence of that dictum:
A well with a horizontal reach of 10.1 km, a world record, was completed by BP Exploration Operating Co. Ltd. in U.K. Wytch Farm oil field. Drilled from an onshore location into a reservoir that extends offshore, initial production was 20,000 b/d.
The Baldpate deepwater production platform, a compliant tower structure capable of handling 60,000 b/d of oil, 200 MMscfd of gas, and 75,000 b/d of water, will be the tallest freestanding structure in the world. The $300 million Gulf of Mexico development project is on Garden Banks Block 260, in 1,650 ft of water, 120 miles off Louisiana.
Extra-heavy oil production from Venezuela's Orinoco belt under the first big joint venture with foreign companies began. If this and other projects go forward as announced, nearly 500,000 b/d of upgraded crude will be coming from this region in the next 3-4 years. Are reserves of oil in place only 1.3 trillion bbl, as some contend, or 1.8 trillion bbl, as Petroleos de Venezuela SA says? Whichever. Either number is greater than the world's proved conventional crude reserves. And 270 billion bbl have been classified as recoverable. Development , upgrading, and marketing this resource will cost $12-13 billion, just for the initial projects identified thus far.
Improvements in gas-to-liquids (GTL) technology promised improved economics for remote gas reserves. A multiclient study by Arthur D. Little Inc. (ADL), Cambridge, Mass., indicates that recent strides in processing, catalysts, and plant operations are finally making the technology commercially viable, nearly 75 years after development of the original Fischer-Tropsch process. "ellipse(GTL) is on the brink of commercial viability," said ADL. Weak demand in the coming year or two may pull it back from the brink. But that will be temporary.
Nothing left to find?Not by a long shot. Not only is the world not running out of oil or gas, it is not even running out of places to look for oil and gas.
Continuing to look in spite of market ups and downs paid off nicely in 1998, especially for the consumers of the future. Here's a small sample of last year's discoveries:
In the Norwegian Sea, Amoco Norway Oil Co. said its discovery on Block 6507/5 could have reserves of at least 200-500 million boe. It's on a structure called Donnatello that lies between the producing Norne and Heidrun oil fields.
Near Terra Nova field off Newfoundland, a find by Amoco Canada Petroleum Co. Ltd., has been declared a "significant discovery" by the Canada-Newfoundland Offshore Petroleum Board. The board's "significant discovery" classification does not depend on rigorous economic criteria, but a second well planned for 1999 will tell more.
Its gas strike off Trinidad and Tobago, says Enron Oil & Gas Co., is the biggest discovery in company history. EOG's first well on its Omega prospect off southeastern Trinidad cut 400 ft of pay in multiple zones and flowed on restricted test at rates of 32 MMcfd of natural gas and 875 b/d of condensate.
Exploration revived on Alaska's North Slope after a string of satellite discoveries that could help efforts to halt-even reverse-a production decline in northern Alaska. ARCO Alaska Inc.'s Ken Thompson said the company has identified 50-60 small-to-medium prospects that could be developed at low cost and produced through existing facilities.
Angola's offshore Block 17 yielded a big discovery for Elf Aquitaine. Since 1996, Elf's Girassol, Dalia, and Rosa oil finds on Block 17 have turned the deepwater area off Angola into the world's hottest play (see related story, p. 32). Early estimates put oil reserves in each of these finds at more than 500 million bbl.
Ten other events
- Speaking of exploration, it seems intuitive that the great exploration technology developed in the past decade should improve success ratios. On an industry-wide basis, however, it was hard to see that in the numbers. That is, until the U.S. Energy Information Administration took another look at its data and corrected major errors in U.S. well completions. For most of 1989-92, exploratory oil and gas well completions were more than double the totals originally reported. Errors for exploratory dry holes weren't nearly as great. The result: The success rate for exploratory drilling jumped after the correction. We knew it all the time, intuitively.
- The American Petroleum Institute, after virtually all its members had done so, decided last year to restructure. Effective this year, the industry's largest trade group will reorganize into three functions. A basic management and administration function will continue to focus on strategic issues-global warming, taxes, trade, et al. The "resources" third will offer services for hire in the areas of communications, government relations, legal, research, analysis, and statistics. The final third of API would be six groups focused on industry segments: upstream, downstream, natural gas, pipeline, marine, and allied.
- This news just in last year: U.S. oil reserves increased in 1997 for the first time in 10 years. In the country with the world's most holes and most producing wells, reserves of natural gas and natural gas liquids rose, too. The U.S. Energy Information Administration said reserves gains in 1997 were 2.4% for crude, 0.4% for dry gas, and 1.9% for NGL.
- Royal Dutch/Shell found a way to dispose of Brent spar without offending anyone-after 2 years and $36 million. The spar's hull will be dismantled in a Norwegian fjord and used to build a quay extension. But don't try to copy this solution. Heinz Rothermund, managing director of Shell Expro, said, "It is a unique re-use solution for a unique structure. Brent spar disposal will not set a precedent for other offshore structuresellipse."
- Yet another National Energy Strategy was proposed by the U.S. Department of Energy. OK, maybe it wasn't one of the year's major events. But it should be noted that then-secretary of DOE Federico Pe?a said the document will go "beyond traditionally expressed energy policies," with the objective of ensuring "affordable, clean, and secure energy supplies." DOE proposed that the government halt the decline in U.S. oil production by 2002 and then reverse it. At the same time, the policy called for DOE to help reduce expected U.S. oil consumption by 1 million b/d by 2010. More oil supply, less demand. Not a prospect to cause feverish excitement among producers in 1998's oil market. Sec. Pe?a announced his retirement shortly after he announced the new policy; Bill Richardson replaced him.
- The Minerals Management Service's royalty controversy highlighted what passed last year for statesmanship and government objectivity. Sen. Barbara Boxer (D-Calif.), might not have said it best, but she said it in the fashion of the Clinton administration: "The issue is simple: Big oil companies have been cheating American taxpayers out of royalty payments for yearsellipseWe cannot continue to subsidize Big Oil, who list profits in the billions each year, at the price of our children's education." Sen. Boxer happened to be talking about MMS's oil royalty rule in this instance, but "the children" were handy weapons in most of the administration's battles.
All that was usually needed to adapt the weapon for a new fight was to fill in blanks for "name of issue here" and "name of target here." MMS cannot issue its controversial oil royalty rule until June 1, or until it can negotiate an agreement with industry.
- How to export crude from the Caspian Sea and Central Asia-an agreement awaited all year-was an important event that did not happen. Agreement on a preferred export option for Caspian crude, set for October, stalled again. The main upstream players in Azerbaijan postponed a meeting in which they were to recommend to the Azeri government their preference for a pipeline route. The Clinton administration wants a pipeline from Baku to Ceyhan, Turkey, to avoid Iran and Russia. But that alternative is also the most costly. The politics within and outside the region is tough enough to deal with. But exploration disappointed in 1998. And, considering flooded oil markets, the most important question became not how to get the oil out, but who would buy it when it gets out. Further delays, for all these reasons, are likely.
- U.S. sanctions policy softened-slightly. Increased questioning of the effectiveness of economic sanctions against a long list of countries may have helped set the stage for change. Oil industry leaders applauded U.S. attempts to improve relations with Iran, for example. Earlier moves were made to support cultural and academic exchanges. But it didn't help U.S. companies get their share of National Iranian Oil Co.'s 24 oil and gas development projects and 17 exploration blocks offered to foreign investors. U.S. firms are barred from investment in Iran because of trade sanctions, but many attended a London conference staged to give details of projects on offer.
- The Y2K thing may be Armageddon. Or it may not be. Planes may crash; employees may not be able to get their parking garage gate to open. Or none of that may happen. Shell says "Quite simply, it is the biggest project in the history of the world." Maybe. But for individual companies, it won't be the biggest project. As of May, BP was planning to spend $150 million on the Year 2000 problem; ARCO about $20 million; Royal Dutch/Shell more than $100 million. Big money, of course. And a shame to have to spend it on something as trivial as the inability of computers bought as recently as the mid 1990s to compensate for a change in the first two digits of the year. Who's to blame for that, anyway? El Nino? The Asian economies? Bill Gates? Someone should pay.
- Enron formed a new water utility company and made a $2.2 billion bid to take over Wessex Water in Southwest England. Enron Chairman Kenneth Lay said the move is "ellipsea logical extension of Enron's expertise developed in the world energy business." He said there are only a handful of large private-sector companies in the $300 billion worldwide water market. A logical extension. Interesting.
Don't touch that dialMany of 1998's problems will be solved this year; many won't. And there will be a sizable list of new ones.
Things will happen that experienced oil men and women said never could happen.
But 1999 will prove once again that no industry is as central to political, economic, and social issues as energy. No industry is as critical to the well being of nations, companies, individuals.
No industry is as exciting.
Stay tuned for the next installment of this gripping saga.
John L. Kennedy
The cause of last year's bad oil market is no mystery: More oil was available than users wanted to buy. Big mergers were done for a variety of reasons, most not directly related to the oil prices of the moment. There was more to it than that. Companies looked across the valley of low oil prices and saw...well...more valley, not the upslope on the other side. In many ways, 1998 tested the petroleum industry's faith in the new lessons it has learned since the 1980s. Lessons about how to use new ideas, new technology, and new organizations to compete in the wide-open energy market of the future. How to take the long-term view. How to innovate, create. In some ways, its faith in new thinking passed the test. Some responses were more traditionalellipseBut 1999 will prove once again that no industry is as central to political, economic, and social issues as energy. No industry is as critical to the well-being of nations, companies, individuals. No industry is as exciting. Stay tuned for the next installment of this gripping saga.
Copyright 1998 Oil & Gas Journal. All Rights Reserved.