Posts from ‘May, 2007’

Move Would Open Door
To Gazprom and Tighten
Kremlin Grip on Energy

By GREGORY L. WHITE in Moscow and GUY CHAZAN in London
June 1, 2007; Page A9

Russian regulators could move as early as today to revoke a production permit from a $20 billion BP PLC natural-gas project in Siberia, in a test case of just how far the Kremlin will go in its drive for control over the energy sector.

As the Russian government has tightened its grip over strategic oil-and-gas assets in recent years — effectively nationalizing one of the country’s biggest oil producers and forcing foreign investors to cede control of projects to Russian state companies — opportunities for international oil giants have withered.

Even so, investors have taken Russian officials at their word that foreign companies still are welcome to participate in big projects as long as control is held by the Russian partner. That was the outcome at the $20 billion Sakhalin-2 project, in which Royal Dutch Shell PLC and its Japanese partners last year agreed to sell a controlling stake to Russian natural-gas giant OAO Gazprom after Russian regulators threatened to shut down the project.

Now events around the Kovykta gas field in eastern Siberia have raised fears there could be less room for foreign companies.

Russian licensing authorities accuse a company controlled by BP’s 50%-owned Russian venture, TNK-BP Ltd., of failing to meet production targets at the giant field. The panel empowered to revoke the license holds a regular meeting today, and officials have said Kovykta is likely to be on the agenda.

TNK-BP admits it is producing far less gas than the license mandates, but blames that on its inability to get government approval for an export pipeline to China. TNK-BP’s appeals to amend the license to reduce production targets have been rejected.

Industry officials and analysts suspect the regulatory pressure is a negotiating tactic on behalf of Gazprom, which has been talking for months with TNK-BP about joining the project. Publicly, however, Gazprom officials say they aren’t interested in Kovykta because of the investment required and questions about whether there is enough demand for the gas.

If the Russian authorities revoke the license, Gazprom would be able to bid for it at a future auction, while TNK-BP could be barred by legal restrictions now under consideration. But Gazprom might later invite BP in as a minority partner in the project.

“At this point, BP not losing everything would be seen as a positive surprise,” said Rory MacFarquhar, an analyst at Goldman Sachs in Moscow.

A person close to BP yesterday said momentum in discussions with Gazprom has picked up in recent days, though the outcome remains unclear. BP Chief Executive Tony Hayward met his Gazprom counterpart, Alexei Miller, in Moscow yesterday, but details of the session weren’t released.
 
“It’s not like a straight negotiation with a normal commercial company,” said one person close to BP. “There is so much politics involved.”

Some analysts have speculated the Kremlin might be pushing for a deal in the days before a summit of leaders from the Group of Eight leading nations, which begins Wednesday. But the Kremlin has in the past held major energy deals hostage to political issues. Relations with London are at a low point after Moscow refused to extradite a former KGB agent accused in the poisoning death of a Russian dissident in London last year.

Given the difficulties of navigating Russia’s politicized energy sector, some in BP would be satisfied just to minimize the damage to BP’s reputation as it gets squeezed out.

“For BP, Kovykta has essentially no value,” as developing it depends entirely on the Kremlin, said the person close to BP.

The fate of Kovykta could provide clues to the future of TNK-BP, which was hailed as a breakthrough when it was formed in 2003 but now seems out of step with the Kremlin’s preference for Russian control. BP’s partners in the company, three Russian billionaires, have indicated they don’t want to sell their stakes. But people familiar with the situation say they wouldn’t resist if the Kremlin sought to have Gazprom or state oil company OAO Rosneft buy them out.

The government hasn’t given clear signs. Igor Shuvalov, a Kremlin economic aide viewed as a liberal, said in an interview in November that while a sale to Gazprom would give the gas giant a major boost, “it would send the wrong signals” about state intervention and should be opposed. But earlier this year, Energy Minister Viktor Khristenko said in an interview, “If it’s attractive on the economics, then the acquisition will be made; there’s no politics in this.” Russian officials have explained past takeovers by state companies as purely economic.

Gazprom officials, meanwhile, don’t conceal their interest in TNK-BP, which is Russia’s No. 3 crude producer. In an interview this year, Gazprom Deputy Chief Executive Alexander Medvedev said, “There are a series of assets in the TNK-BP group that are interesting for us,” though he noted there was no sign TNK-BP’s Russian shareholders wanted to sell.

Any takeover would raise the question of whether BP would see its 50% stake reduced in line with Russian desires for local control. Analysts said that would be a setback for BP, which has depended on TNK-BP for growth in production and reserves.

• Nail-Biter: Russian regulators who oversee licensing for oil-and-gas assets today could discuss revoking the permit given to BP’s 50%-owned Russian venture, TNK-BP, for the Kovykta natural-gas project.
 
• The background: The Kremlin has tightened its grip over energy assets in recent years, and opportunities for international oil giants have withered.
 
• The message: The fate of Kovykta could provide clues to the future of TNK-BP, which now seems out of step with Russia’s desire for control.

Write to Gregory L. White at greg.white@wsj.com and Guy Chazan at guy.chazan@wsj.com

Deborah Hargreaves
Friday June 1, 2007

Consumers have more clout than they realise. Certainly, many companies have converted to green causes under sustained customer pressure. And while much of what the corporate sector says about climate change can be dismissed as hot air, there are the beginnings of some very real initiatives.

Most leading companies now espouse some kind of green strategy towards reducing their carbon footprint. Of course, it is easier for those businesses with low emissions such as banks to boast about their environmental credentials. It often backfires when the big polluters in the oil and power sectors try to do the same. Shell has taken a lot of flak over its adverts showing flowers sprouting from a refinery and BP’s move to brand itself “beyond petroleum” has been met with much scepticism.

It was therefore brave of Scottish and Southern Energy to suggest it will try to sell less of its core product. The electricity producer has earmarked a range of financial incentives for users to cut down on their consumption.

This is very much driven by customer interests. SSE says about 10% of its consumers are eager to cut down. It sees its plan as a bit like a loyalty card and a way to hold on to customers in a fiercely competitive market. Investors rewarded its foresight with a jump in the shares.

Another reason for firms to boost their green credentials is pre-emptive. With President Bush finally converting to the cause, many businesses are concerned that if they do not cut down on carbon, they will be forced to do so.

Ryanair is obviously getting edgy about the media coverage of the environmental consequences of cheap flights. While this is yet to have a discernible effect on customer behaviour, it can only be a matter of time.

There is already some anecdotal evidence that people are starting to feel guilty about taking too many short-haul flights. A poll in last week’s Guardian showed that almost half of air travellers questioned said they had changed their behaviour because of the environmental impact of flying.

This is potentially bad news for budget airlines whose entire business model revolves around encouraging people to fly more. Governments have so far shied away from shackling the airline sector, but it remains vulnerable to regulatory intervention.

For smart companies, there is a business opportunity in climate change. There is plenty of money to be made from cleaner energy and environmental technology. Share prices for clean technology companies have been rocketing in the US. Investors are keen to jump on the green bandwagon.

With governments still parleying about the need to cut emissions levels, the real influence lies with the consumer and the investor. Spending power is what makes the corporate sector sit up and listen.

deborah.hargreaves@guardian.co.uk

http://business.guardian.co.uk/story/0,,2092887,00.html

As Baghdad burns, destabilising the entire region and sending the price of oil soaring, Calgary booms

Naomi Klein
Friday June 1, 2007

The invasion of Iraq has set off what could be the largest oil boom in history. All the signs are there: multinationals free to gobble up national firms at will, ship unlimited profits home, enjoy leisurely “tax holidays”, and pay a laughable 1% in royalties to the government.

This isn’t the boom in Iraq sparked by the proposed new oil law – that will come later. This boom is already in full swing, and it is happening about as far away from the carnage in Baghdad as you can get, in the wilds of northern Alberta. For four years now, Alberta and Iraq have been connected to each other through a kind of invisible seesaw: as Baghdad burns, destabilising the entire region and sending oil prices soaring, Calgary booms.

Here is how chaos in Iraq unleashed what the Financial Times recently called “North America’s biggest resources boom since the Klondike gold rush”. Albertans have always known that in the northern part of their province there are vast deposits of bitumen – black, tarlike goo that is mixed up with sand, clay, water and oil. There are approximately 2.5 trillion barrels of the stuff, the largest hydrocarbon deposits in the world.

It is possible to turn Alberta’s crud into crude, but it’s awfully hard. One method is to mine it in vast open pits: first, forests are clear-cut, then topsoil scraped away. Next, huge machines dig out the black goop and load it into the largest dump trucks in the world (two stories high, a single wheel costs $100,000). The tar is diluted with water and solvents in giant vats, which spin it around until the oil rises to the top, while the massive tailings are dumped in ponds larger than the region’s natural lakes. Another method is to separate the oil where it is: large drill-pipes push steam deep underground, which melts the tar, while another pipe sucks it out and transports it through several more stages of refining, much of it powered by natural gas.

Both techniques are costly: between $18 and $23 per barrel, just in expenses. Until quite recently, that made no economic sense. In the mid-80s, oil sold for $20 a barrel; in 1998-99, it was down to $12 a barrel. The major international players had no intention of paying more to get the oil than they could sell it for, which is why, when global oil reserves were calculated, the tar sands weren’t even factored in. Everyone but a few heavily subsidised Canadian companies knew that the tar was staying put.

Then came the US invasion of Iraq. In March 2003, the price of oil reached $35 a barrel, raising the prospect of making a profit from the tar sands (the industry calls them “oil sands”). That year, the US Energy Information Administration “discovered” oil in the tar sands. It announced that Alberta – previously thought to have only 5bn barrels of oil – was actually sitting on at least 174bn “economically recoverable” barrels. The next year, Canada overtook Saudi Arabia as the leading provider of foreign oil to the US.

All this has meant that Iraq’s oil boom has not been delayed; it has been relocated. All the majors, save BP, have rushed to northern Alberta: ExxonMobil, Chevron and Total, which alone plans to spend $9bn-$14bn. In April, Shell paid $8bn to take full control of its Canadian subsidiary. The town of Fort McMurray, ground zero of the boom, has nowhere to house the tens of thousands of new workers, and one company has built its own airstrip so it can fly in the people it needs.

Seventy-five percent of the oil from the tar sands flows directly to the US, prompting Brian Hall, an energy consultant with Colorado-based IHS, to call the tar sands “America’s energy security blanket”. There is a certain irony there: the US invaded Iraq at least in part to secure access to its oil. Now, thanks partly to economic blowback from that disastrous decision, it has found the “security” it was looking for right next door.

It has become fashionable to predict that high oil prices will spark a free-market response to climate change, setting off an “explosion of innovation in alternatives”, as New York Times columnist Thomas Friedman wrote recently. Alberta puts the lie to that claim. High prices have indeed led to an R&D extravaganza, but it is squarely focused on figuring out how to get the dirtiest possible oil out of the hardest-to-reach places. Shell, for instance, is working on a “novel thermal recovery process” – embedding large electric heaters in the deposits and literally cooking the earth.

And that’s the Alberta tar sands for you: the industry already contributing to climate change more than any other is frantically turning up the heat. The process of refining bitumen emits three to four times the greenhouse gases produced by extracting oil from traditional wells, making the tar sands the largest single contributor to Canada’s growth in greenhouse gas emissions. The $100bn in projected investments from the tar sands have also turned Canada into a global climate renegade.

That money is the primary reason why, at next week’s G8 summit in Heiligendamm, my country’s oil-friendly prime minister, Stephen Harper, will join George Bush in opposing all serious attempts to cap or reduce greenhouse gases. Back at home, his government fully supports the oil industry’s plans to more than triple tar sands production by 2020, with no end in sight. If prices stay high, it will soon become profitable to extract an additional 141bn barrels from the tar sands, which would place the largest oil reserves in the world in Alberta.

Developing the sands is devouring trees and wildlife – the Pembina Institute, the leading authority on the tar sands’ environmental impact, warns that boreal forests covering “an area as large as the state of Florida” risk being levelled. Now it turns out that the main river feeding the industry the massive quantities of water it needs is in jeopardy. Climate scientists say that dropping water levels are the result – fittingly enough – of climate warming.

Contemplating the collective madness in Alberta – a scene even the Financial Times has labelled “some dystopian fantasy” – it strikes me that Canada has ended up with more than Iraq’s displaced oil boom. We have its elusive weapons of mass destruction too. They are out near Fort McMurray, in the jet-black goo beneath the earth’s crust. And with the help of trucks, pipes, steam and gas, these weapons are being detonated.

* A version of this article appears in the Nation

www.nologo.org

http://environment.guardian.co.uk/climatechange/story/0,,2092931,00.html

By Russell Hotten
Last Updated: 12:12am BST 01/06/2007

BP chief executive Tony Hayward has held talks with his counterpart at Russian energy monopoly Gazprom ahead of a meeting today that could decide the fate of the UK company’s involvement in the huge Kovykta gas field in Siberia.

The agency that awards licences for exploration and development is due to decide whether to strip BP’s joint venture in Russia, TNK-BP, of the right to operate at the gas field, a project that would be a huge revenue earner for the UK company. Separately, the agency Rosnedra is also to consider revoking licences for UK firm Imperial Energy.

Gazprom has no stake in Kovykta, but the Kremlin appears to have a strategy to see Russia’s vast energy assets return to state control. The Kovykta affair has echoes of Royal Dutch Shell’s experience at Sakhalin-2, where after months of pressure the Anglo-Dutch company relinquished control of the project to Gazprom.

BP said Mr Hayward met Gazprom chief executive Alexei Miller yesterday to discuss “their many areas of mutual business”. A BP spokesman would not say if Kovykta was on the agenda. Mr Hayward was in Moscow for a TNK-BP board meeting that had been planned several months ago, he said.

Meanwhile, Rosnedra said it would review three licences given to Imperial, plus those awarded to several other firms.

http://www.telegraph.co.uk/money/main.jhtml?xml=/money/2007/06/01/cnbp01.xml

Jeffrey Jones
reuters news agency

CALGARY, Alberta–Royal Dutch Shell Plc’s Canadian unit is still committed to the idea of a $16.2 billion Arctic gas pipeline, but must be assured of better returns before going ahead, its outgoing chief executive said Thursday.

Clive Mather, who retires next week as Shell absorbs its formerly publicly traded Canadian unit, said the Mackenzie Valley Pipeline’s backers face a hard decision on making the huge investment due to surging costs and “fragile” economics.

Mather made the comments a day after the Rex Tillerson, CEO of Mackenzie partner Exxon Mobil Corp. , said the project may have to wait until the cost environment improves.

“Do we remain committed? We very much remain committed to the principle,” Mather said in an interview. “We’ve got to work out a solution with all of the other partners in this to a point where we can actually get to an investment decision, and that’s going to be tough.”

Project leader Imperial Oil Ltd.is in talks with Ottawa in hopes of wresting financial support to improve the economics of the line, which would ship up to 1.9 billion cubic feet of gas to southern markets, much of it from three big fields on the Beaufort Sea coast. Shell owns one of them.

The proponents want the government to allow accelerated depreciation, to pay for infrastructure like roads and to guarantee that third-parties will sign up to ship gas on the 1,200 km line to Alberta.

Imperial’s cost estimate more than doubled in March, reflecting soaring prices for labour and materials like steel.

Tillerson’s comments were among the strongest that the development is on shaky financial ground.

“I still remain quietly confident,” said Mather, who took the helm at Shell Canada, one of the country’s biggest oil companies, three years ago.

“This was always going to be difficult. It’s been going already for many years, but the fundamentals are strong – I mean the fundamentals associated with bringing that stranded gas to market, the fundamentals associated with opening up a potential new (supply) basin in the North.”

Indian and Northern Affairs Minister Jim Prentice declined Thursday to say if Ottawa would offer more incentives.

“This is a private sector enterprise and it will have to achieve private sector rates of return and it will have to make sense on free market principles. So I await to see whether that is the case or not with this project,” Prentice said.

“If it isn’t, then the proponents in the free enterprise system will have to consider alternatives.”

Mather, 59, is the last CEO of Shell Canada before it is integrated into the Anglo-Dutch oil major’s worldwide operations. Royal Dutch Shell bought out minority shareholding for $8.7 billion (Canadian) in April.

The personable British executive, a Shell veteran, is not involved in the integration of the business, best known for its massive oil sands holdings and national gas station chain.

But he said the unit, which employs about 5,000 people, will be structured like the parent’s businesses, split more along business lines than regional ones, with refining and marketing a good candidate for that.

However, Royal Dutch Shell has been clear about Calgary remaining a major centre in its operation, he said.

Mather said “as a good oil and gas man” he will miss running a fully integrated company, which mines oil sands crude, processes it, refines it and sells it at the gas pump.

“The other thing I like is having a public company and the share price. I am a very competitive animal and I like the challenge of seeing my stock out there, seeing how we do and seeing how others do,” he said.

(Additional reporting by David Ljunggren in Ottawa)

May 31, 2007 06:16 PM

http://www.thestar.com/Business/article/220090

Vanguard (Lagos)
1 June 2007
Hector Igbikiowubo

IN yet another twist to the unfolding scenario in the Niger Delta, Kedere youths in Ogoniland have shut the valve on the Bomu manifold located on the Trans-Niger pipeline, effectively shutting-in 150,000 barrels per day of crude oil output from the Shell Petroleum Development Company operated joint venture.

This caused oil prices to rebound slightly after falling sharply the previous day.
 
Shell announced Wednesday that 150,000 bpd of crude oil production has been locked in at its Bonny Light terminal in Nigeria after pipelines were sabotaged.

While explaining the development a company spokesman, who did not want his name in print, explained that negotiations were currently ongoing to get the youths to open up the manifold to allow free flow of crude oil from the wells.

“Although we do not have any response from the youths yet, we believe that before the close of business activities today, we will have cause to cheer,” he said.

The shut in volume effectively brings the total shut-in volume in the country to about 850,000 barrels per day.

Militant attacks in the region have cut peak Nigerian crude production by around 25 percent for more than a year.

The attack comes the day after the new Nigerian President Umaru Yar’Adua found militants receptive to his conciliatory inauguration speech, raising hopes of increased stability in the crude-rich Niger Delta Region.

Feelers from the creeks indicates that the militants may have decided to give Yar’Adua measured respite. Perhaps this disposition informed the release of the four American hostages on Wednesday by the Niger Delta Frontier Force (NDFF).

At 10:43 a.m. in London, benchmark Brent crude contracts for July delivery were up 42 cents at US$68.55 per barrel.

Meanwhile, New York crude contracts for July delivery were up 54 cents at US$63.68 a barrel.

http://allafrica.com/stories/200706010001.html

EXTRACT: TNK-BP’s woes appear to mirror those faced by Shell at Sakhalin-2 last year. Shell and its Japanese partners sold a majority stake to Gazprom after months of pressure by Mitvol’s agency over purported environmental violations. Shell CEO Jeroen van der Veer met with Miller 10 days before agreeing to sell to Gazprom at a Dec. 21 meeting with Putin at the Kremlin.

THE ARTICLE

Friday, June 1, 2007. Issue 3669. Page 1.
By Miriam Elder
Staff Writer

BP’s new chief Tony Hayward held talks with Gazprom CEO Alexei Miller in Moscow late Thursday, as a deal on the gas giant’s entry into BP’s flagship Kovykta project appeared imminent.

Hayward and Miller “discussed issues of mutual interest” during talks at Gazprom’s central Moscow offices, BP spokesman Vladimir Buyanov said.

Neither BP nor Gazprom would comment on whether the two discussed Kovykta, the huge gas field in eastern Siberia that TNK-BP has been fighting to keep amid mounting state pressure.

Several sources said President Vladimir Putin wanted a deal on Kovykta to be struck before he left for the Group of Eight summit in Germany, which begins Wednesday.

Oleg Mitvol, deputy head of the Natural Resources Ministry’s environmental watchdog, has recommended that TNK-BP be deprived of its license at Kovykta for failing to fulfill production quotas. TNK-BP owns Kovykta through its majority share in license holder Rusia Petroleum.

“We understand that [the issue of Kovykta] is not to be decided by us,” Gazprom spokesman Sergei Kupriyanov said Thursday. “Is everything all right with the license? So what is there to talk about?”

Gazprom has denied holding talks with TNK-BP over Kovykta, which is estimated to hold 1.9 trillion cubic meters of gas but is at an early stage of development.
 
The ministry’s subsoil agency will not discuss Kovykta during a meeting Friday, agency spokesman Vitaly Tsoi said. The agency’s license review commission meets every two weeks.

“Kovykta will not be looked at,” Tsoi said. “Forget about Kovykta for now.”

Yet a ministry source said the commission would likely review the Kovykta license Friday. “I’m about 94 percent certain they will look at it,” the source said.

Under the license, Rusia Petroleum is obliged to produce 9 billion cubic meters of gas per year. It has been producing less than 1 bcm in the absence of an export pipeline to China.

Industry and Energy Minister Viktor Khristenko said Thursday that Russia was in talks with China to build a gas pipeline to the country.

The pipeline should be partially completed in the next five to six years, Khristenko told Reuters at a Paris energy conference, adding that he hoped additional pipelines would be built from fields in eastern and western Siberia. The “volumes, capacities and timeframe for such gas transport distribution systems are being discussed,” he said.

Analysts say the ministry’s increasing focus on Kovykta could indicate that negotiations on Gazprom’s entry into the project might be drawing to a close.

Yet Kovykta remains an anomaly in the country, lacking a state-controlled Russian partner as the Kremlin seeks to bring major oil and gas projects under state control.

TNK-BP owns 63 percent in Rusia Petroleum. Interros, currently controlled by billionaires Vladimir Potanin and Mikhail Prokhorov, holds 26 percent and the Irkutsk regional government holds 11 percent.

TNK-BP officials have said in recent weeks talks with Gazprom have been held more often than ever before.

Hayward flew into Moscow late Wednesday to attend a meeting of TNK-BP’s board of directors, Buyanov said. Hayward was due to fly out late Thursday.

Kupriyanov said Miller’s meeting with Hayward had only been arranged recently, declining to provide specifics.

“That there is a dialogue going on at the top levels could be suggestive of some kind of breakthrough,” said Roland Nash, head of research at Renaissance Capital.

Hayward and former BP chief Lord Browne met with Putin in March as TNK-BP announced it would bid for Yukos assets at a bankruptcy auction. Critics said BP was bowing to the Kremlin in a bid to ease the pressure on Kovykta.

TNK-BP’s woes appear to mirror those faced by Shell at Sakhalin-2 last year. Shell and its Japanese partners sold a majority stake to Gazprom after months of pressure by Mitvol’s agency over purported environmental violations.

Shell CEO Jeroen van der Veer met with Miller 10 days before agreeing to sell to Gazprom at a Dec. 21 meeting with Putin at the Kremlin.

“The bottom line is the Kremlin wants Kovykta to be under its control rather than BP’s,” Nash said, adding that having TNK-BP retain a stake in the project would be a good compromise.

“Given the current investment environment, the danger is that Kovykta being taken away would just confirm the feeling that Russia is drifting backward on several fronts,” he said.

The subsoil agency was due to review London-listed Imperial Energy’s license for projects in the Tomsk region on Friday. Mitvol had accused the company of environmental violations and overstating reserves. “The company feels confident the issue will be resolved,” an Imperial Energy spokesman said.

http://www.themoscowtimes.com/stories/2007/06/01/002.html

May 31st 2007
From The Economist print edition

The carbon market is working, but not bringing forth as much innovation as had been hoped

EVERY year the average sow and her piglets produce 9.2 tonnes of carbon-dioxide equivalent through the methane emissions from their effluent. In the past, that has been a problem both for the environment and for pig-farmers. In developing countries the pig-effluent collects in open lagoons which smell bad and get infested with flies. Sometimes it flows straight into nearby water systems.

Now this problem has become an opportunity. Bunge, an agricultural-commodities business based in America, builds lined and enclosed pools to collect the effluent and captures the methane that it emits. The farmer can use the gas to generate electricity. By preventing methane from escaping into the atmosphere, Bunge creates a credit which it can sell on the carbon market. The farmer gets to keep 20-30% of the value. Bunge has 40 such projects operating in Brazil and is planning to expand into Mexico, Guatemala, Peru and the Philippines.

The carbon market is truly innovative. Although it works like any commodity market, what is being bought and sold does not exist. The trade is not actually in carbon, but in not-carbon: in certificates establishing that so many tonnes of carbon dioxide (or the equivalent in other greenhouse gases) have not been emitted by the seller and may therefore be emitted by the buyer.

The purpose of setting up the market was, first, to establish a price for carbon and, second, to encourage efficient emissions reductions by allowing companies which would find it expensive to cut emissions to buy credits more cheaply. It has had some success on both counts—some would argue too much on the second.

A carbon price now exists, established by the European Emissions-Trading Scheme (ETS). In its first phase it has been volatile (see chart 2) because information about Europe’s industrial emissions was poor, so the market got a shock in early 2006 when it emerged that the European Commission had been too generous with the allowances it handed out to industry. Phase one allowances (2005-08) are now virtually worthless. But the commission has learnt its lesson and got meaner with allowances, thus pushing up the price in phase two.

The supply of carbon credits comes principally from two sources. The first is the allowances given to companies in the five dirty industries covered by the ETS (electricity, oil, metals, building materials and paper). The second source of carbon dioxide lies outside Europe. The European Commission linked the ETS to the “clean-development mechanism” (CDM) set up under the Kyoto protocol. This provides for emissions reductions in developing countries—such as those on the Latin American pig farms—to be certified by the UN. Such “certified emissions reductions” (CER) can then be sold.

The demand for carbon credits comes mostly from within the ETS, from polluters who need certificates allowing them to emit carbon. There is some demand from Japan, which has a voluntary scheme, and from companies and individuals elsewhere in the world who want to offset their emissions for moral reasons, or to make themselves look good.

The trade is now sizeable. Some €22.5 billion-worth ($30.4 billion) of allowances were traded last year, according to Point Carbon, a data-provider, representing 1.6 billion tonnes of CO2—a huge increase on the €9.4 billion traded in 2005. Europe’s ETS made up about 80% of the total value.

Developing-country CERs accounted for about €4 billion of last year’s trade: 562m tonnes of CO2. According to New Carbon Finance, a research company, carbon funds worth $11.8 billion have been raised so far. Half of that total is managed from London. Climate Change Capital, a niche investment bank, raised $130m for its first carbon fund, launched in July 2005; its second, launched a year later, is now worth around $1 billion. According to Tony White of Climate Change Capital, all the money for the first came from hedge funds, which like risk. By the time the second fund was established, more cautious investors, such as pension funds and banks, were prepared to put money into it.

The money has gone mostly into projects in developing countries to produce CERs. Bunge’s Brazilian pig-farmers are making CERs out of their animals’ effluent. But the bulk of the investment has gone into greenhouse-gas capture in China.

Cheap and cheerful

The most potent greenhouse gas is HFC-23, a by-product of HCFC-22, a chemical used in, among other things, fridges. It is now mostly banned in the developed world. Its global-warming effect is, tonne for tonne, 11,700 times greater than that of carbon dioxide, so it is good to get rid of it, and cheap, too; capturing it and burning it off costs less than €1 for the equivalent of one tonne of carbon dioxide. These days China produces most of the world’s HFC-23. That—along with the fact that the Chinese government is efficient to deal with—explains why 53% of the total volume of CDM projects in 2006—worth around €3.5 billion in total—went to China.

The very cheapness of cutting emissions of HFC-23 makes the trade controversial. Credits costing less than €1 to produce have been sold on the market for up to €11. Factories have found that their damaging by-product, HFC-23, can be more valuable than their main output. The Chinese government, realising how much money there is in this business, has imposed a tax of 65% on revenues from it, and in February this year it launched its own $2 billion CDM fund. So European consumers, who are paying for greenhouse-gas abatement through their electricity and other bills, are contributing billions of dollars to the Chinese government’s coffers via the CDM.

Easy options—HFC-23 and other fabulously dirty (ie, profitable) industrial gases—will soon run out. Guy Turner at New Carbon Finance reckons that the days of the CER that costs less than €1 to produce are over, and that the range is now more like €1-5. But there is plenty of scope at that level. China’s industrialisation is a fast and dirty business, and there will be no shortage of greenhouse gases produced there for rich-country money to clean up.

That is part of the problem. Of the 65% of companies surveyed by Point Carbon earlier this year which claimed that the ETS had led them to abate their emissions (up from 15% the previous year), most were planning to buy credits rather than cut their own emissions. Yet the ETS was intended to cut European emissions as well as Chinese ones.

This is happening on a small scale. At times the carbon price has made it worth power companies’ while to switch from dirty fuels to cleaner gas. “We massively reduced our lignite production when the CO2 price was at its height,” says Alfred Hoffmann, head of portfolio management in Scandinavia and Germany for Vattenfall, a Swedish power company. Lignite is dirtier than black coal. But then gas prices rose, making switching less attractive.

FLPA

Bringing home the methaneThe carbon price has delivered some of the innovation that it was supposed to generate. Shell, for instance, is pumping CO2 from a refinery in the Botlek area of the Netherlands into 500 greenhouses producing fruit and vegetables, thus avoiding emissions of 170,000 tonnes of CO2 a year and saving the greenhouse owners from having to burn 95m cubic metres of gas to produce the CO2 they need.

Alcan, an aluminium company, is planning to use the heat from one of its smelters to increase the efficiency of its power-generation plant at Lynemouth in Northumberland in Britain. Wyn Jones, managing director of Alcan’s British smelting and power-generation operations, says this will save 150,000 tonnes of CO2 a year (€3m if the price of CO2 is around €20 a tonne, as Alcan expects) and 60,000 tonnes of coal (£2.1m, or $4.2m, at around £35 a tonne). He is not sure how much the project will cost, but is reckoning on a payback period of around five years.

But European emissions overall are not falling, which suggests there may not be as much switching out of coal, or as much technological innovation, as had been hoped. Chinese CERs are too cheap and the carbon price is too low and too volatile. Even when it was bouncing around at €15-25, it did not seem to encourage much new investment. According to Bjoern Urdal of Sustainable Asset Management, who took a detailed look at the effects of the carbon price on the German electricity market last year, replacing old coal-fired power stations with gas-fired ones became worthwhile only at a carbon price of €33. He has not done the sums since last November, when the European Commission chucked out Germany’s “transfer rule” (which would have exempted new coal-fired stations from the ETS for 14 years), but reckons the break-even point will have come down to more like €25.

That helped raise the carbon price. So did the commission’s decision to slash national governments’ planned allocations to industry for the period 2008-12. The price of phase two allowances has risen to a level high enough to get some power generators to switch from coal to gas at the margin when the gas price is moderate; but not high enough to get them to replace coal-fired power stations with gas-fired ones—nor to encourage much of the innovation that carbon trading had been expected to spawn.

http://www.economist.com/surveys/displaystory.cfm?story_id=9217960

May 31st 2007
From The Economist print edition

Scrubbing carbon from coal-fired power stations is possible but pricey

THERE are two remarkable things about Sleipner T, a gas rig in the middle of the North Sea owned by Norway’s state-owned oil company, Statoil. One is the working conditions. Technicians get around NKr600,000 ($100,000) a year, private rooms with televisions and ensuite bathrooms, and work two weeks out of every six. That is what you get when social democracy meets oil wealth.

The other unusual thing about Sleipner T is that the CO2 which has to be extracted before the gas can be sold does not contribute to global warming. Instead of being pumped into the atmosphere it is reinjected into the ground, 1,000 metres below the seabed. That is what you get when an innovative company meets a carbon tax.

Statoil started capturing and storing its carbon dioxide in 1997, five years after Norway introduced a carbon tax. Nobody paid much attention then, but these days Statoil gets a regular stream of visitors because carbon capture and storage (CCS), also known as carbon sequestration, is widely seen as a possible quick fix for global warming.

It is the abundance, cheapness and dirtiness of coal that makes CCS so appealing. Coal produces 50% of America’s electricity, 70% of India’s and 80% of China’s. It is widely distributed around the globe, which enhances its attractions at a time of concern about energy security. Burning coal is the cheapest way of generating electricity. And coal produces around 40% of the CO2 emissions from energy use.

High gas prices have meant that coal has been enjoying a revival in recent years. In America some 150 new coal-fired power stations are on the drawing board. In China, two 500MW coal-fired power plants are starting up every week, and each year the country’s coal-fired power-generating capacity increases by the equivalent of the entire British grid. So anything that offers the prospect of cleaning it up is attracting a great deal of interest.

Guardian

Sending carbon back where it came fromStandard pulverised-coal (PC) generation can be made a bit cleaner by burning the fuel at higher temperatures. “Ultrasupercritical” generation can cut CO2 emissions by a fifth. But if demand goes on increasing, that is not enough. Hence the interest in CCS.

CCS is being done in three places—at Sleipner; at In Salah in Algeria, where the CO2 removed from gas produced by a joint venture between BP, Statoil and Sonatrach, Algeria’s state-owned energy company, is stored in the desert; and at the Weyburn oil field in Saskatchewan, Canada, where the CO2 produced by a coal gasification plant in North Dakota is piped across the border and used to increase the pressure in a partly depleted oil field. This process, known as enhanced oil recovery (EOR), is in use in 70 oil fields around the world, but at Weyburn, unusually, some of the CO2 remains underground.

Most of the operations involved in CCS are familiar. First, the CO2 must be separated from other gases. At Sleipner, for instance, the CO2 content of the gas that emerges from the oil field is 9%. That has to be reduced to 2%, which is done by passing the gas through amines (nitrogen-based chemicals). Second, the CO2 is moved along in pipelines. That is commonly done in EOR, as is the third stage—injecting it into the ground.

The fourth stage is the least familiar. When CO2 is being used for EOR, it returns to the surface (except at Weyburn). For sequestration, however, the CO2 must be stored underground, probably in depleted oil and gas fields or in porous briny rock. Statoil has been doing this for a decade at Sleipner, and there is no sign of the stuff bubbling up again. Scientists say that within decades or centuries it will dissolve, and within centuries or millennia it will react with elements in the rock and form new minerals. But this part of the process needs more study.

The challenge is to put all those technologies together and deploy them at a reasonable cost, and on a scale that can make some impact on emissions. That will take some doing. If 60% of the 1.5 billion tonnes of CO2 that America produces every year from coal-fired power stations were liquefied for storage, it would take up the same amount of space as all the oil the country consumes.

Coal-fired power stations are the likeliest candidates for CCS because they are dirty and numerous. But there is a difficulty with PC plants: they spew out a huge volume of flue gas, of which CO2 is only a small part. Separating it from other gases is expensive. The main alternative is to turn coal into gas before using it to generate electricity. The resulting CO2 and hydrogen are then separated, the hydrogen used to generate electricity and the CO2 stored. A few such integrated gasification combined-cycle (IGCC) plants have been built.

Every which way

Now that power utilities are beginning to accept that they will have to do something about carbon, the big question is what. GE has bought Chevron’s IGCC technology. The cost of generating electricity from it, according to GE’s Steve Bolze, is 20-25% more than a PC plant, but Mr Bolze believes that, once the cost of separating carbon is taken into account as well, IGCC may be cheaper.

Philippe Joubert, president of power systems at Alstom, which in March announced a joint venture with American Electric Power, America’s biggest coal-fired generator, rejects the idea that IGCC is cheaper, even with CCS. “This is clearly not true. We should know. We are in IGCC as well as PC. It’s clearly 10% more expensive. All serious academics realise that it is more expensive.” A study by MIT published in March tends to side with Mr Bolze. Generating electricity from an IGCC plant with carbon capture, it maintains, is 35% more expensive than PC without CCS; but PC with CCS is 60% more expensive than PC without.

Plans for IGCC plants are proliferating. In America, at least, that says more about subsidies than about faith in the technology’s future. George Bush announced a $2 billion clean-coal initiative in 2002, and the 2005 Energy Policy Act, notorious for its pork content, included $1.6 billion-worth of subsidies for coal gasification.

According to the International Energy Agency, around 15 power plants with CCS are being planned and another seven CCS projects are on the drawing board. Most make economic sense either because of direct subsidy or because of their particular economic circumstances. Statoil and Shell are planning to sequester CO2 from a Statoil power plant on the Norwegian mainland under Shell’s Draugen platform. The investment is justified by Norway’s carbon tax, currently about €50 per tonne. BP is planning a petroleum-coke-fuelled power plant in California, where electricity is particularly expensive and the petroleum coke for the power plant comes as a by-product of oil refining; the project is a joint venture with Edison International, an electricity company.

One big company that is making a sizeable punt on CCS is Vattenfall, which is building a 30MW plant in Germany. “I’m totally convinced”, says Lars Josefsson, Vattenfall’s chief executive, “that the issue of carbon sequestration will change the way we do business in the long term. I believe the companies that realise that soonest will be the winners.”

If CCS is to take off, the rules on CO2 storage need sorting out. The 1996 London protocol on dumping waste at sea was amended earlier this year to allow CCS at sea. But rules on land need attending to, for promoters of CCS worry that it will become as contentious as nuclear waste.

And, as always, there is the problem of cost. At present, academics reckon that it would take a carbon price of around $30 to make sequestration economic—below the peak that the ETS hit briefly in 2006, and way above the $10 safety valve in the only carbon bill in Washington, DC, to mention a figure. But the cost may come down, because that is generally what happens as technologies are commercialised.

Despite the tricky economics, the sheer abundance of coal is an argument for pursuing CCS. And if it can be made to work, it has a certain poetic circularity: the carbon extracted from the earth as fossil fuel shall return unto the earth whence it came.

http://www.economist.com/surveys/displaystory.cfm?story_id=9217908

May 31st 2007
From The Economist print edition

Car and fuel companies are investing in clean transport

KEN LIVINGSTONE, the mayor of London, last year caused a mild panic among drivers who cruise the city’s narrow streets in “Chelsea tractors” (SUVs to the rest of the world). He announced that he was planning to charge cars emitting more than 225g of CO2 per kilometre £25 a day to go into the centre of London rather than the standard £8. “Red Ken” has always enjoyed stirring it among the rich, so he was probably quite happy at the stink he caused.

Worldwide car ownership is growing around 5% a year, so if emissions from cars are to be cut, engines will have to become dramatically more efficient, or there will have to be a technological breakthrough to replace petrol with a clean fuel. Now that governments seem to be getting serious about emissions, car and fuel companies are getting serious about finding less polluting alternatives.

Fuel-efficiency regulations of varying kinds already exist in all the countries that matter, but in America, where they were fairly tough during the oil crises of the 1970s and 1980s, they have lost their bite. Improvements in engine efficiency have been used not to reduce fuel consumption but to weigh cars down with gizmos. And car companies have carried the burden of those regulations. Fuel companies, so far, have got off scot-free.

That seems to be changing. Mr Livingstone’s initiative is only one of many new measures that have been proposed around the world to cut vehicle emissions. California is trying to impose greenhouse-gas emissions standards on cars, though the motor manufacturers have taken the state to court on the ground that this is federal-government business. In his most recent state-of-the-union address, George Bush’s big concession to the greens was to propose a 4% a year tightening in fuel-efficiency rules.

The EU has had a long-standing voluntary deal with the carmakers under which they would aim to reduce the average CO2 emissions of their fleets to 120g/km by 2012. But thanks to consumers’ growing enthusiasm for high-power, high-emissions cars, that seemed unlikely to happen, so this year the European Commission decided to impose a mandatory standard. There was a big row, but the commission got most of what it wanted.

And now governments are taking aim at fuel companies too. In January California announced that by 2020 it will require a 10% reduction in the carbon emissions that a fuel emits over its life cycle. That has implications for “unconventional oil”—petrol made from oil shale and tar sands. Although CO2 emissions from the resulting fuel are the same as those from conventional sources, producing it is a filthy business, so such rules will discourage its use. Europe is planning to follow California. That is not necessarily a coincidence. There is a lot of traffic between Brussels and Sacramento on green issues.

Tighter regulation will not hit all companies equally (see chart 9). German car firms are particularly vulnerable, which was why they made the most fuss about the commission turning the voluntary target into a mandatory one. The French and the Italians were smugly silent.

A corny idea

“This industry is 98% dependent on petroleum. GM has concluded that that’s not sustainable,” says Larry Burns, GM’s vice-president of R&D and strategic planning. “It’s all about displacing petroleum.”

The Prius’s success—390,000 Americans own one—is a testament to Toyota’s vision and marketing. But it is not clear how much potential there is in the hybrid market. Bill Ford announced in 2005 that his company would be building 250,000 hybrids by 2010, but it no longer seems to be aiming for that. Anyway, hybrids are not a solution to global warming. Their somewhat greater fuel efficiency will soon be offset by the increase in global car ownership. More radical technological changes are needed.

Ethanol is one possibility, because although burning it emits CO2, growing the crops needed to produce it absorbs the stuff, at least in theory. The farming lobby has been pushing it as a new source of revenue. The car industry is keen on it: if the fuel changes, then the cars don’t have to. GM has been running a “live green, go yellow” campaign to promote it.

Ethanol currently accounts for only 3.5% of American fuel consumption, but thanks to heavy subsidies its use is growing by 25% a year, says Matt Drinkwater of New Energy Finance. When oil prices were at their peak, the payback period on an ethanol plant was 11 months. Not surprisingly, they have sprung up all over the Midwest. Soaring demand for maize for ethanol caused the sharp rise in the corn price which led to “tortilla riots” in Mexico.

There are three problems with corn ethanol. First, the market is limited. At present, any car can take E10 fuel (10% ethanol) but only 6m out of America’s 237m cars and trucks are “flex-fuel” vehicles that can take E85 (85% ethanol). Converting a car costs only around $200, but invalidates the guarantee. Detroit has promised that half of its output will be “flex-fuel” by 2012.

Second, corn ethanol is expensive. At the pump it is competitive with gasoline; but according to the International Institute for Sustainable Development, America’s subsidy costs taxpayers somewhere between $5.5 billion and $7.3 billion a year. And high tariffs keep out imports of cheap Brazilian ethanol made from sugar cane.

Third, corn ethanol is not very green. Some people think that corn ethanol is responsible for more emissions than it saves, because so much energy is used in growing the corn. Dan Kammen and Alex Farrell of the University of California at Berkeley reviewed six studies on the issue and concluded that, gallon for gallon, ethanol is probably 10-15% better than petrol for emissions of greenhouse gases. That is a help, but no panacea.

A better bet may be cellulosic ethanol—ethanol that can be made out of straw, switchgrass, wood chips—pretty much anything with cellulose in it. Mr Bush, keen on a technological quick fix for global warming, has offered $385m in government subsidies to bring cellulosic ethanol to market.

A lot of people are trying. Vinod Khosla’s company, Range Fuels, is planning to build a commercial-scale ethanol plant in Georgia. Using woodchips as a feedstock, it employs heat and chemicals to break down the tough bonds in cellulose molecules. Up to $76m of subsidy will help it on its way. Many companies are working on suitable enzymes to break down those bonds. One such is Iogen, in which Goldman Sachs and Shell have taken stakes. It will be getting up to $80m from the government.

One further problem with ethanol is that it is less energy-intensive than petrol, so you get fewer miles per gallon. That is one reason why BP is putting its money into a different fuel, biobutanol, which is more energy-intensive than ethanol. BP is developing it in a joint venture with DuPont, for which biobutanol offers a possible way into the fuel business.

And then there is the electric car—not the hybrid car that uses electricity for pottering about in the city and switches to its combustion engine at speed, but the fully electric sort that uses either a hydrogen fuel cell to produce electricity or a battery to store it.

Hydrogen is an attractive way of powering a vehicle because it can be made from all the sources that electricity can. But hydrogen fuel cells have been just around the corner for a long time. GM has been working on them since the 1960s, and reckons that so far it has spent $1 billion. The technology’s appeal is obvious, for it could revolutionise not only the car: if the hydrogen fuel cell can produce electricity to power a vehicle, why not a house as well?

There was a bubble of excitement about fuel cells in the late 1990s, and shares in companies such as Ballard Power Systems rocketed. But hopes that a fuel-cell car would be on the market early this decade were disappointed. The fuel cell, says Shell’s Duncan Macleod, was “overpriced and over-promised at the front end”.

Still, fuel-cell vehicles are getting onto the roads. London ran three buses for a three-year trial and is now planning to buy ten. There are around 60-80 hydrogen buses and 200 cars on the road worldwide, and a few filling stations. Shell, which is taking hydrogen seriously, is about to open its first filling station in California. It has one already, in Washington, DC, to service ten cars, and another in Iceland, for three buses. It is an expensive business. London’s three-year, three-bus trial cost £4.5m. Hydrogen cars cost around $1m each to build, according to Mr Macleod. At the pump the hydrogen costs $5 a kilo—about the same, in terms of mileage, as current petrol prices. How much does it cost Shell to make? “A lot more than $5,” says Mr Macleod, laughing.

GM is also working on battery technology. At this year’s Detroit motor show it unveiled the Chevrolet Volt, which has both a battery and a combustion engine. The technology got generally good reviews, but GM has not said when it will start producing the car commercially.

Meanwhile, rushing up on the inside lane are those disruptive people from Silicon Valley. Last year Elon Musk, a South-African-born entrepreneur who started PayPal, an online payments system, unveiled the Tesla, an electric sports car. It plugs into the wall and stores the energy in a lithium-ion battery—the sort used in laptop computers, only with 6,831 cells. And it’s a pretty, and nippy, little car. “A Porsche can accelerate from 0-60 in 4.7 seconds,” says Mr Musk with understandable pride. “The Tesla can do it in four seconds.”

It has a few disadvantages. The first is cost. Mr Musk has pre-sold the first 350—the first 120 of those for $100,000 apiece. “The average net worth of the first 120 customers is over $1 billion,” he says. However, he plans to start work on a budget version next year. The second is range. The Tesla’s maximum is 250 miles. If there are other downsides, they may become clear in August or September this year, when the first production models should slip silently off the production lines and onto America’s roads.

Clean-energy entrepreneurs may find the transport business harder to crack than power generation, because the existing infrastructure of pipelines and service stations is dedicated to petrol. Yet Brazil, where sugar ethanol now accounts for 40% of fuel used by cars, shows that it can be done. Now that governments are beginning to lean on big oil as well as on the car companies, the drive towards cleaner transport is likely to pick up speed.

http://www.economist.com/surveys/displaystory.cfm?story_id=9217898