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Forbes: Shell Shocked

EXTRACT: “This company has been losing ground now for many years, and I don’t like that,” says Jeroen van der Veer, the 58-year-old chief executive. “I didn’t see the reserves crisis as something isolated–no, I think the whole company was losing ground. We knew it, but we kept on doing more of the same.”


By Christopher Helman

Scrambling to catch up after its oil reserves scandal, Shell is running ever faster to stay in place. Is there salvation in natural gas?

It took $200 million, a Finnish icebreaker equipped with a 175-ton crane and a floating hotel that housed 450 roughnecks flown in from around the world. In May, two months ahead of schedule, the floating armada assembled by Royal Dutch Shell (nyse: RDS-B – news – people )completed repairs on its giant Mars tension-leg platform in the Gulf of Mexico. Hurricane Katrina had turned Mars into a pile of steel spaghetti, dumped its 100-ton derrick under 3,000 feet of water and mangled pipelines on the seafloor. Resurrected, Mars went back to producing 130,000 barrels of oil and 150 million cubic feet of natural gas (the equivalent of another 26,000 barrels) a day.

Getting Mars back online early was a triumph for Shell–and a rare piece of good news for the world’s third-largest oil and gas company. Financially, Shell is healthy, with a $6.9 billion profit on revenue of $76 billion in the first quarter. Analysts expect it to earn $24 billion, or $7.28 a share, this year.

But $75 oil hides a multitude of sins. In physical terms Shell is weak. Over the past three years it has replaced only 38% of the oil it has pumped. It is desperately searching for new pools of crude while trying to make up for their scarcity by shifting its focus toward natural gas. Gas is plentiful but hard to move–hence, in most cases, much less valuable as it comes out of the ground. Shell has suffered disarray in giant projects in Nigeria and on Russia’s Sakhalin Island, and pricey delays in developing several prospects, including South Mars.

All oil companies confront the fact that petroleum is getting hard to find in politically stable parts of the globe. But Shell is in more of a crisis than the others because of a problem of its own doing: For years it exaggerated the size of its reserves. In January 2004 it confessed to the problem, eventually slicing 4.5 billion barrels of oil-and-gas equivalents off proved reserves, which now stand at 11.5 billion barrels. Counting only crude oil, reserves are down from 6.6 billion barrels in January 2003 to 4.6 billion now. This is more than a bookkeeping matter. Shell’s production of oil has been dwindling at a rate of 7% a year.

“This company has been losing ground now for many years, and I don’t like that,” says Jeroen van der Veer, the 58-year-old chief executive. “I didn’t see the reserves crisis as something isolated–no, I think the whole company was losing ground. We knew it, but we kept on doing more of the same.”

Other oil companies did a better job of coping with the scarcity of new oilfields. Says Robert Kessler, an analyst at Simmons & Co. in Houston: “Exxon (nyse: XOM – news – people ) kept building right through the last down cycle. They booked resources back then so that they’d have them now.”

Now Shell is rushing to catch up. Its capital budget this year, at $19 billion, leads ExxonMobil’s $17 billion and BP (nyse: BP – news – people )’s $16 billion, despite the fact that it is smaller than either. Most of this wad is going into huge projects in Nigeria, Canada, Brazil, the Gulf of Mexico, Russia, Australia, Qatar and Saudi Arabia, all due to be completed by 2015. These, plus a collection of smaller (and iffier) drilling prospects, are attached to fossil fuel reservoirs that may harbor the equivalent of 60 billion barrels of oil equivalent.

“Equivalent” covers up as much as it reveals. A barrel of oil has as much energy as 5,700 cubic feet of gas but is worth $75, versus $35 for the gas. Oil costs $20 per barrel to find, extract and ship across the ocean. Shipping the gas equivalent entails liquefying it, keeping it superchilled on an LNG tanker, then regasifying it at the other end, at a combined cost of $22.50. That assumes that permission can even be found to land the LNG. In the U.S. that’s hard to come by.

It is significant, then, that Shell relies on gas for 48% of its fossil fuel production by energy value, while the corresponding ratio at other giant oil companies is between 37% and 41%. Shell may be in love with gas because it has no choice. “I have no doubt that the future is gas,” Van der Veer recently told a conference in Amsterdam.

In Shell’s 99-year history Van der Veer is the first of his type–a sole chief executive, ruling from headquarters in the Hague. Until last year the company was a Siamese twin of British and Dutch corporations, with dual stock listings and dueling boards of directors. Trained as an economist and mechanical engineer before joining Shell in 1971, the skinny (he’s an avid jogger), bespectacled Van der Veer is at ease with flowcharts and schematics. He shows off a series he has meticulously hand-drawn on graph paper and keeps in a black binder. It’s his way of reducing Shell’s problems to underlying components, distilling strategy into a mantra familiar to every executive: “More upstream, profitable downstream.” If your production goes up, your income from refining and marketing also goes up.

The current mess has its origins in the late 1990s, when then chairman Mark Moody-Stuart, instead of beefing up exploration and production, cut cap-ex and dismissed thousands of seasoned managers and engineers. The idea was for Shell to keep growing in an asset-light manner, outsourcing much of the drilling to oilfield contractors like Schlumberger. Whoever was spinning the drill bits and selecting the spots at which to sink them, Shell wasn’t developing new oil and gas fields fast enough to replace what it pumped out.

Unsurprisingly, Shell started “finding” lots more oil and gas by reevaluating what it already had. For the three years ending with 2000, Shell legitimately replaced just 60% of produced reserves. But Phillip Watts, head of exploration and production, boldly reported a three-year average replacement rate of 102%. According to an investigation conducted for Shell by New York City law firm Davis, Polk & Wardell, Watts’ ability to hit the numbers got him appointed chairman in 2001.

In Oman Shell overbooked 250 million barrels of oil equivalent in reserves it expected to find in expansions of existing fields. In Australia it booked 500 million BOE from the Gorgon gas fields, even though it hadn’t yet decided to invest in the project. None of this was publicly known when Watts moved up to the chairman’s suite. He was replaced in E&P by Walter van der Vijver, who soon realized the extent of overbookings but didn’t sound the alarm. Indeed, in 2002 he flubbed a rare opportunity to help Shell grow out of its reserves hole, selling out its remaining 50% stake in an Indian oil prospect to Cairn Energy for $7.25 million. Cairn has since found 3.5 billion barrels of oil there.

Following reviews of operations in Oman and Nigeria, Shell released a statement in January 2004 saying it would recategorize 20% of its proved reserves. That prompted questions and investigations. In March 2004 Watts, Van der Vijver and Judith Boynton, the chief financial officer, resigned. Shell’s investigations revealed overbookings in 100 of its 300 biggest fields. The eventual fallout included four more restatements and $240 million in fines and civil settlements, with two more cases pending.

A managing director since 1997, Van der Veer had run a refinery, worked overseas and been president of the Royal Dutch side, overseeing its chemicals business–and so hadn’t been tarred by E&P. He approved Shell’s shareholder reports for 2002 and 2003 but says he was unaware that the reserves in those reports were padded. “I feel no responsibility,” he insists. “Otherwise, I wouldn’t be sitting here.”

Estimating reserves is as much art–or politics–as science. Shell has been in Nigeria for 50 years, and there’s a lot of oil there. But how much can it get its hands on? Some of its Nigerian fields had leases set to expire before the company could possibly recover the oil it claimed as proved reserves. And relations with the host government are not good. The company’s enemies in that country accuse it of destroying the environment, bribing officials, arming security forces and working behind the scenes to silence anti-Shell protesters. The company says it is a responsible corporate citizen and respects human rights.

In 1995 Shell discovered Bonga, Nigeria’s biggest oil and gas field, with 600 million BOE of proved and probable reserves. The plan was to bring Bonga online by 2003. But sloppy management, violence and lackluster Nigerian contractors made that date impossible. After the company rebuffed an order by Nigeria’s congress to pay $1.5 billion in environmental reparations, militants in Nigeria’s Warri region repeatedly attacked Shell infrastructure and kidnapped 20 contractors, killing 2. Bonga finally came online in November 2005 at a cost of $3.6 billion, $900 million over budget. It will reach 200,000 BOE per day of production later this year. Not a day too soon: Production at Shell-operated ventures in Nigeria has fallen from 910,000 BOE a day in 2003 to a recent 450,000.

Soon after taking over in early 2004, Van der Veer launched a push to improve Shell’s project management. He’s hired 3,000 new technical staff and is schooling them in the finer points of procurement, cost estimation and reserve classification. Higher up the chain, Van der Veer put in place more reserve coordinators and auditors, accountable not to E&P planning and strategy managers but to senior executives. Replenishing reserves is no longer a metric to evaluate executives and dole out bonuses.

Van der Veer has another headache. Sakhalin Island, lying off the eastern coast of Siberia, is believed to hold 50 billion BOE of oil and gas. The reserves are being developed in at least five projects; Shell is in charge of the second, Sakhalin II. In partnership with Japanese LNG shippers Mitsui and Mitsubishi (other-otc: MSBHF.PK – news – people ), Shell hopes to tap 17 trillion cubic feet of gas (that’s 3 billion BOE) and 1.2 billion barrels of oil. The Kremlin watches these projects very carefully, since Russia is in line to receive royalties once the venture’s costs are paid off. In 2000 Shell figured it would cost $9 billion to build Sakhalin II, including a 103,000-ton concrete base, 220 feet tall, sunk 100 feet below the iceberg-strewn waves, with seismic shock absorbers to stabilize the platform against earthquakes; an LNG liquefaction plant that, at 1.3 billion cubic feet of gas a day for up to 30 years, would be the world’s largest; and thousands of miles of pipeline crisscrossing pristine rivers and streams.

But concrete, steel and labor weren’t getting any cheaper. And there were unanticipated expenses in new roads as well as pipelines to appease environmentalists protecting whale migrations and salmon runs. Costs were rising, but Shell didn’t know how much until last year, when Van der Veer ordered new analyses. Further complicating matters, Shell was also negotiating to trade half of its 55% stake in Sakhalin II with state-owned gas monopoly Gazprom for half of a giant natural gas field called Zapolyarnoye. A week after signing that deal, Shell says it completed its reassessment for Sakhalin II’s cost: $20 billion.

Russian President Vladimir Putin wasn’t pleased. Meeting with Van der Veer in the Hague last November, Putin reportedly criticized the cost escalation. The fate of that deal is now on hold, and Russia has since excluded Shell from the international consortium developing the giant Shtokman gas field in the Barents Sea. “Is Sakhalin still a good deal? That’s what we think,” says Van der Veer. If Shell succeeds in developing 4 billion BOE at a mere $20 billion, it’s paying $5 a barrel in capital costs. That’s not bad, given that Shell averaged $8.90 in capital spending per BOE produced last year. Yet on top of that will come operating costs of $6 or so per BOE to get Sakhalin’s bounty out of the ground.

Canada is even less hospitable to investors: The tarry, sandy reserves there soak up more like $24 a barrel in capital and $15 in production costs. Still, the $3 billion Shell has spent on Canadian oil sands since 1999 is starting to pay off, as the current 200,000 barrels per day may grow to 500,000. In March the company paid $400 million to lease 200,000 acres in Alberta. That looks like a bargain, given that 30 billion barrels of oil lie beneath, but the oil is molasses-thick and locked in very tight limestone formations. Shell intends to insert heaters into the reservoir 1,000 feet below the surface and cook the crude in place to 650 degrees Fahrenheit so that it can be sucked up through conventional wells. The heaters might work as intended–or they might not.

Given the extent to which sand, tar or murderous thugs get in the way of petroleum production, it’s no surprise that Shell’s engineers see salvation in natural gas. For decades gas in remote locations was flared off as a nuisance by-product alongside more easily shipped oil. That started to change in 1973, when Shell completed its first liquefied natural gas plant in Brunei. LNG plants chill the gas to –260 degrees Fahrenheit, thereby shrinking its volume 600-fold, so that it can be shipped to gas-hungry nations like Japan, Korea and, shore neighbors permitting, the U.S. At 10.3 billion cubic feet (or 1.8 million boe) a day, Shell’s gas output is on track to surpass oil in five years, with one-seventh of the gas being liquid at some point on the journey to the customer.

With liquefaction plants in five countries, Shell ships a dominant 34% of the world’s LNG, a business that is growing at 14% a year. Between 1999 and 2006 Shell spent $12 billion to develop 11 LNG processing plants, producing 5.2 billion cubic feet a day. This year in Oman it completed a plant that processes 500 million cubic feet a day at a cost of $700 million, the lowest ever. By 2009 it expects to bring on 8 new gas-chilling operations.

Some of Shell’s brightest longer-term gas prospects are in Saudi Arabia, where it has done business since the 1940s and helped build chemical plants. As a token of that close relationship, Van der Veer has a bejeweled curved Saudi dagger, a traditional gift to boys entering manhood, hanging in his otherwise spartan corner office. In mid-July Shell began the first of seven wildcat wells it will drill this year in the Kingdom’s Rub al-Khali, a desert known as the Empty Quarter (a name Van der Veer hopes is merely metaphorical). The work is part of a joint venture led by Shell (40% stake), Saudi Aramco and Total, which will explore 81,000 square miles of desert, half the size of California. No telling how much gas they’ll find, because no one ever bothered to look for it.

Next door in Qatar, Shell is preparing to build a $4 billion LNG project and a $6 billion plant that will convert gas into a synthetic diesel fuel worth $95 a barrel. Shell already operates the world’s biggest gas-to-diesel plant, in Bintulu, Malaysia, which produces some 15,000 barrels a day. Qatar’s plant will do 140,000.

If you can turn natural gas into a high-value fuel, why not do the same with coal, which is even more plentiful in parts of the globe (like the U.S. and China)? Shell’s gasification technique consists of partially combusting pulverized coal to yield carbon monoxide and hydrogen gas, which combine to form synthetic natural gas.

After pollutants like mercury and sulfur are filtered out, the clean syngas can be burned to create electricity, like at the 250-megawatt power plant Shell built in Buggenum, Holland. Or it can produce chemical feedstocks, at a lower cost than natural gas, as at the 15 gasification plants being built, using Shell technology, in China. Shell aims to combine coal gasification with gas-to-diesel technology in an alliance with coal miner Anglo American.

Up to a point, lavish capital outlays like these can make up for a shortage of old-fashioned oil wells. Hell-bent to replace reserves, Shell has earmarked just $5 billion this year for dividends and share buybacks–compared with $20 billion each for ExxonMobil and bp. Skeptical, or simply embittered over the reserve accounting scandal, investors price Shell at only 9 times trailing earnings, versus 11 and 12 for its two larger rivals. Van der Veer, who says he expects to be in his job for no more than six more years, will have to work quickly to prove the skeptics wrong.

“This company has been losing ground for many years, and I don’t like that.”

By the Numbers

Shell Game

Its most promising projects are also its most expensive ventures. Will they pay off?

14,700 barrels of synthetic diesel a day at Bintulu.

$3.6 billion is what it cost to build Bonga and produce 200,000 BOE a day.

$20 billion makes Sakhalin the world’s most costly energy project. Source: Shell. and its sister non-profit websites,,,,,, and are owned by John Donovan. There is also a Wikipedia feature.

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