Sure, Big Oil is raking in money. But new reserves are more elusive, and governments are bargaining harder.
Times could hardly seem better for big oil companies. Buoyed by high crude prices, Western oil majors are reporting outsize profits. Stock valuations? They’re stratospheric.
But if investors knew the details of a recent auction of oil plots in Libya, they might temper their enthusiasm. Libya has thrown itself open for investment, and the oil majors of Europe and the U.S. have stormed in, hungry for a piece of the country’s 25 billion barrels in reserves. At an auction on Jan. 29 for exploration rights for 15 Libyan blocks, the bidding got so heated that the winners wound up with “extremely harsh terms that will make it difficult for them to make profits,” says Craig McMahon, an analyst at oil consultant Wood Mackenzie in Edinburgh. McMahon figures that for one block, No. 106, which was bid on by 16 companies and won by Occidental Petroleum Corp. (OXY ), the government is likely to capture upwards of 98% of the revenues, compared with around 80% on other deals in North Africa, where governments drive hard bargains. Occidental says McMahon’s estimate is too high and that it’s happy to get a stake in an underdeveloped oil patch. “The days that people had gotten used to, where oil was inexpensive and easily available — those days are gone,” says an Occidental spokesman.
Libya’s auction underscores the strange state Western oil companies find themselves in. Problems are emerging in the midst of incredible plenty. The industry’s record of replacing oil and gas reserves has turned lackluster. From Russia to Libya to Venezuela, investment terms and tax regimes are becoming less favorable as governments angle for a bigger cut of the oil wealth. “Despite the current appearance of riches, there are long-term trends that will have a negative effect on industry profitability,” says J. Robert Maguire, co-head of global energy investment banking at Morgan Stanley (MWD ) in London.
Costs are rising fast. Day rates for deep-water drilling rigs have more than doubled in the last year, rising from $75,000 to $150,000 and above, says Lehman Bros. Inc. analyst Angeline M. Sedita. Some observers wonder when the markets will notice that the industry is facing headwinds. “Nobody is asking the hard questions,” says Fadel Gheit, a senior analyst at Oppenheimer & Co. (OPY ) in New York. “It is all forgiven thanks to the obscene profits they are making.” Gheit thinks investor pressure on companies to gain access to more resources and slash costs will eventually drive a new wave of mergers — even if oil prices stay high. And if they drop, the consequences could be severe.
Replacing Output
Gheit and other industry watchers believe major oil companies face some fundamental challenges. For starters, companies need to replace annual output by well over 100% to sustain production growth — a target many are struggling to achieve, says Wood Mackenzie analyst Robert Plummer. He reckons that Royal Dutch/Shell Group’s (RD ) reserve-replacement ratio has hovered at around 44% to 57% over the past five years, if the U.S. Securities & Exchange Commission’s definition of reserves is applied. One consequence is that Shell’s 2004 actual production of oil and gas declined by 3% from the previous year. Even BP PLC (BP ), considered one of the best-run of the majors, missed the mark. It added 110% to its reserves according to British accounting — but just 89% according to more conservative SEC rules. “Today is not a good time to scramble around” for reserves, says BP CEO John Browne.
Clearly, it’s getting harder for companies to replenish the oil and gas they pump. The question is whether this is because they cut back exploration budgets in response to low oil prices in the ’90s or because opportunities are running thin. The answer is probably a combination of both. At any rate, the average size of finds dropped from 353 million barrels in the 1970s to 107 million since 2000, figures Morgan Stanley. “The law of diminishing returns is alive and well. We’re drilling more to get the same volumes,” says Arthur L. Smith, CEO of John S. Herold Inc., a Norwalk (Conn.) energy consulting firm.
The scramble for reserves is also accelerating the shift away from mature fields such as those in the North Sea and Alaska, where companies have been harvesting the fruits of investments they made in the 1960s and ’70s at costs far lower than those that prevail today. Now the focus is on developing countries such as Angola, Nigeria, Trinidad, or the states of the former Soviet Union. Companies have little choice but to make the change. Production in the North Sea and Prudhoe Bay in Alaska is falling, and they need to add new resources to maintain output.
But there are serious costs associated with moving into new territories. An oil zone such as the North Sea or the Gulf of Mexico is a vast network of fields, many of which share terminals, processing plants, pipelines, and other expensive pieces of equipment. In the North Sea, companies such as Total (TOT ) help maintain output levels by plugging newly discovered satellite fields into existing networks.
That’s not the case in basins like Sakhalin in Russia and Tenghiz in Kazakhstan. There, companies must invest not only in drilling but also in building fresh infrastructure at much higher prices. Morgan Stanley figures that finding and development costs rose by 86% from 1999 to 2003, to $6.70 per barrel of oil equivalent.
Meanwhile, some of the richest acreage remains largely off limits to Western oil companies. With prices high, there’s less incentive for countries with huge reserves of cheap oil, such as Iran, Kuwait, and Saudi Arabia, to cede opportunities to global companies. “We know by experience that it’s easier for OPEC countries to open for foreign investment when oil prices are low,” said Thierry Desmarest, CEO of France’s Total, in an interview with BusinessWeek last fall. No rapid opening in the Gulf area is likely.
To build up reserves, oil majors are relying more and more on acquisitions of known assets. BP’s $8 billion purchase of 50% of Russia’s TNK in 2003 boosted reserves by 11%. Other outfits are pursuing unconventional and more capital-intensive sources of oil and gas, from tar sands to liquefied natural gas to drilling in increasingly deep water. This, of course, drives costs up even further. International majors are also facing stiffer competition for deals from Chinese and Indian companies, which are willing to spend big to lock up energy supplies for their fast-growing economies.
In this environment it’s tough to play catch-up after poor exploration results. That’s what Shell is racing to do. The company is hiring 1,000 exploration and production personnel and focusing its $15 billion per year capital spending on boosting reserves. Those engineers will undoubtedly find more oil. Whether it will be enough to keep the party going is another question.
