Crude oil rose above $57 a barrel for the first time this year after a jump in U.S. refinery demand boosted speculation that economic activity is recovering.

U.S. refineries boosted operating rates last week to their highest level since December, the Energy Department said yesterday, and crude stockpiles increased less than analysts had estimated. European and Asian equities advanced after U.S. Treasury Secretary Timothy Geithner said tests of banks’ capital needs will be “reassuring.”

Crude oil for June delivery rose as much as $1.59, or 2.8 percent, to $57.93 a barrel on the New York Mercantile Exchange, the highest intraday price since Nov. 17. It was at $57.65 a barrel at 9:50 a.m. London time.

“The market is thinking the recession will end earlier than was expected a few months ago,” said Hannes Loacker, an analyst at Raiffeisen Zentralbank Oesterreich in Vienna. “It looks like prices will continue to increase, but I don’t see crude above $60 in the short term.”

U.S. refiners operated at 85.3 percent of capacity in the week ended May 1, up 2.7 percentage points from the week before, the Energy Department report showed. Crude inventories rose by 605,000 barrels last week, versus analysts’ forecasts for a gain of 2.5 million barrels.

Gasoline supplies fell 167,000 barrels to 212.4 million in the week ended May 1, the Energy Department report showed. A 550,000-barrel gain was forecast, according to the median of 16 analyst responses in the Bloomberg News survey.

Still, the increase in U.S. crude supplies brought inventories to 375.3 million barrels last week, the highest since 1990.

‘Taking Heart’

“The market is indeed shrugging the bearish fundamentals and may rather be taking heart from the reassuring comments from Treasury Secretary Geithner,” said Harry Tchilinguirian, senior oil market analyst at BNP Paribas SA in London. “Demand is still weak. Before any durable move higher, the inventory overhang will need to be resolved.”

Brent crude oil for June settlement rose as much as $1.63, or 2.9 percent, to $57.78 a barrel on London’s ICE Futures Europe exchange. That’s the highest intraday price since Nov. 10, 2008. It was at $57.40 a barrel at 9:50 a.m. London time.

The MSCI World Index climbed 0.9 percent at 8:09 a.m. in London.

Record inventories of crude oil are building up around the world threatening to swamp storage space and belying optimism in the markets about an imminent economic recovery.

Rotterdam, Europe's biggest port, is running out of room for more oil, US reserves are at a 19-year record and tankers are being used as floating storage off Britain's south coast, even though OPEC is reducing production.

"From a commodities point of view, world trade is appalling and the demand is just not there," said Ahmad Abdallah, commodities analyst at Gavekal, the economics consultancy. "All inventories are rising – they are bursting at their seams."

Oil prices rose to a five-week high last week above $53 a barrel in line with the recent bull run on the world's equity markets.

Yet despite an OPEC decision last November to cut output by a record 4.2m barrels a day, a move which began to come into effect in February, the fall in demand has been even more striking.

Goldman Sachs estimated last week that global storage capacity could be exhausted by June. Government figures in the US, the world's biggest oil consumer, put reserves at 375m barrels, rising by 4m barrels in one week in April alone.

One estimate said that in addition 100m barrels were currently being stored in tankers at sea across the world – some of these are visible in Lyme Bay off the coast of Dorset and Devon.

Mr Abdallah said official estimates of oil usage for this year had been based on more optimistic assumptions than economic reality.

An average of analysts' predictions reckons on a reduction in demand of 1.5m barrels a day for 2009 over last year, while the International Energy Agency is predicting a fall of 2.5m barrels, but an estimate based purely on current economic growth figures would put the overall decline at 3m.

He said it was a similar story in other commodities, with companies building up inventories while prices were cheap.

"I can't see demand picking up for the rest of this year," he said. "Even if it picks up next year it is going to be from a very weak base."

Goldman Sachs set a price target 10pc lower than at present, at about $45, for July, while Peter Voser, chief financial officer for Royal Dutch Shell, told reporters last week that it was "difficult to see
an uptick in the oil or gas price" in the next 12 to 18 months.

The weak demand for oil will add fuel to the arguments of those who argue the current bull run on the equity markets is a classic fools' rally.

"The further (the oil price) rises, the more sceptical you become," said Mark Pervan, head of commodities research at ANZ. "We are operating in a global recession and oil markets are a proxy for global growth."

U.S. refiners may curb summer activity for the first time in at least 20 years to combat brimming inventories of key transportation and industrial fuels, like diesel and jet fuel, as a slow economy hurts demand.

A glut in these petroleum products, known as distillates, is expected to pressure prices and prompt refiners to cut runs, which could mean foregoing a bump in output and revenue that usually results from operating units near full blast in May through August.

A distillate surplus "is screaming out, because it's far above any other recent (inventory) highs," said Edward Morse, LCM Commodities director in New York.

U.S. distillate stocks rose to 144.1 million barrels last week, a record for late April, government data shows. Crude and products stocks climbed in nine straight weeks to 1.08 billion barrels, a 30-month high.

"The U.S. oil market has a high inventory problem," Carl Holland, an industry consultant in Connecticut, said. "The solution has to be to reduce refinery run rates and slow crude and product imports."

Storage capacity for distillates isn't made public, but tanks are likely near full in key refining regions like the U.S. Gulf Coast and Midwest, analysts said.

Storage constraints, and worries that oversupply will pressure prices, are already preventing a typical spring boost in refining.

Now, some companies have taken to leasing tankers to store distillates offshore in Europe, shipbroker C.R. Weber said, forecasting that the trend will soon come to the United States.

Independent storage tanks in Europe's Amsterdam-Rotterdam-Antwerp oil hub have been rented out nearly 100 percent and some oil companies have been storing gas oil and jet fuel in ships anchored offshore. Ships loaded with about 25 million barrels are already floating near Europe.

"This is the first time ever we've seen distillate being stored offshore," Morse said.

NO UPSWING FOR REFINERIES

Every summer since 1990, when the Energy Information Administration records began, U.S. refinery utilization has had a general uptick during the driving summer months as plants rev up to meet gasoline demand.

But gasoline demand is still dented by the recession after falling last year for the first time since 1991, and refiners have already started to cut back on production as they have sufficient inventories.

Another factor pressuring refiners this summer is that 25 to 40 percent of each crude barrel is refined into distillates, adding to the glut.

Refineries tend to run at 90 percent of their capacity or more in late spring and summer, according to the government. This year, utilization may even fall from last week's levels of 82.67 percent.

"You're not going to see the usual upswing that we normally see this time of year. We're probably going to be flat around 80 percent to 83 percent of capacity (through the summer)," said Jim Ritterbusch, president, Ritterbusch & Associates, Galena, Illinois.

Better gasoline margins may not be enough to prevent cuts in refinery runs. U.S. Gulf Coast crack spreads, the difference between the cost of crude oil and price of wholesale petroleum products, have nearly doubled to $4.96 a barrel, versus $2.59 a barrel last month.

Valero, the largest U.S. refiner, said last month it may run its plants at as little as 79 percent of capacity this quarter, down from 88 percent a year ago.

WHAT A DIFFERENCE A YEAR MAKES

Today's supply scenario contrasts sharply with a year ago, when high diesel demand from China to Chile helped draw down U.S. distillate stocks to levels 30 percent lower than this year. Stocks are usually highest around August, before harvest and heating oil season depletes them, said Addison Armstrong, of Tradition Energy in Stamford, Connecticut.

A drop in freight tonnage hauled by the American trucking industry in March shows the economic downturn has hurt demand.

Now, fears of a global flu pandemic have discouraged air travel.

It is prompting deep discounts for front-month distillate futures. The contango -- where supplies for delivery in later months cost more -- is likely to widen, analysts said.

A gallon of diesel for delivery next month now fetches almost 14 cents less per gallon than diesel for delivery five months out, the biggest discount since August 2008.

This time last year, diesel was in backwardation, with prompt contracts fetching a premium amid strong Asian import demand.

Demand from Asia is still growing, but the global distillate glut means stiff competition to supply the region from exporters such as the former Soviet Union, India and China. Meanwhile, demand has fallen in other export markets for U.S. diesel, like Latin America and Europe.

"That giant sucking sound that we heard last year of China stocking up (on diesel) before the Olympics? It's very unlikely to happen again any time soon," said Andrew Reed, an analyst with ESAI in in Boston.

* U.S. distillate stocks late April at record highs

* Storage constraints may prompt U.S. offshore storage

* Distillate glut could override summer gasoline demand

* Refineries seen operating at around 80 pct of capacity

Additional reporting by Ikuko Kao in London; Editing by Jeffrey Jones and Marguerita Choy

Venezuelan President Hugo Chavez signed a law to allow the government to seize assets from oilfield services companies and said he’ll start taking over boats and docks on Lake Maracaibo today.

The National Assembly approved the law earlier yesterday, allowing for the nationalization of services including water injection at wells, gas compression and dock control.

“I’m going to enact this law immediately,” Chavez said last night. “We’re going to start to recover these assets, which will become property of the state. Now they’re liberated.”

Petroleos de Venezuela SA, the state oil company, is pressing foreign services companies to lower rates as growing debts hamper oil output. Production in Venezuela, the biggest oil exporter in the Americas, was down 8.4 percent last month from a year ago, according to Bloomberg estimates, and services firms have idled rigs this year because of past-due payments.

Venezuela depends on oil exports to finance half the government’s budget.

Chavez didn’t provide names of companies that would be targeted today. Schlumberger Ltd. and Halliburton Co., the world’s biggest and second-biggest oilfield services companies, both operate in Venezuela. The two companies declined to comment when asked about the new law on May 6.

Boats, Docks

Oil and Energy Minister Rafael Ramirez said the state oil company today will seize 300 boats, 61 diving boats and 39 terminals and docks and other assets used by the oil industry on Lake Maracaibo in Venezuela’s western Zulia state. PDVSA, as the oil company is known, will absorb 8,000 employees from subcontractors.

“These intermediary companies speculated, and took a large part of our oil earnings,” Ramirez said yesterday on state television. “With this, we’ll continue reducing costs in our oil industry.”

Venezuela’s output may fall below 2 million barrels per day for the first time in 20 years, said Patrick Esteruelas, a Latin America analyst at Eurasia Group in New York, in a research note yesterday.

Venezuela has already started expropriating assets this year from services companies that have idled equipment.

Yesterday, John Wood Group Plc, a services company based in Aberdeen, Scotland, said that PDVSA took over one of its contracts, and Houston-based Boots & Coots International Well Control Inc. said it suspended operations in the first quarter because of past-due payments.

Williams Cos. said on April 29 that it wrote off $241 million for uncollectible Venezuela payments, while Helmerich & Payne Inc. said it may not be able to collect $116 million. Helmerich has idled seven rigs, while Dallas-based Ensco International Inc. idled one, which was later seized by PDVSA.

Investment Plan

PDVSA cut its investment plan for this year to $14 billion from a previously planned $24 billion on April 28, and in February Ramirez said the company asked service providers to cut their fees by 40 percent after the price of oil plunged.

Chavez has pledged to maintain spending on social programs that provide subsidized food, health care and housing to the poor, even after crude oil prices plunged 61 percent since July.

Crude oil for June delivery rose 37 cents, or 0.66 percent, to $56.71 a barrel on the New York Mercantile Exchange yesterday.

Ramirez said May 6 that Venezuela, a member of the Organization of Petroleum Exporting Countries, supports efforts to raise the price of oil to $70 a barrel.

Angel Rodriguez, a lawmaker and president of the Energy and Mines Commission in the National Assembly, said in an interview May 6 the government won’t expropriate foreign-owned oil and gas drilling rigs.

China Petroleum & Chemical Corp., Asia’s biggest refiner, expects the nation’s oil-product demand to grow at 0.6 to 0.7 times that of the gain in gross domestic product, said Zheng Baomin, director of investor relations.

The government has forecast GDP to expand 8 percent in 2009, Zheng said at a conference today in Singapore. This equates to China’s oil-product demand growing between 4.8 percent and 5.6 percent this year, according to Bloomberg calculations based on Zheng’s speech.

“China’s oil demand will be in positive territory this year,” said Francisco Blanch, managing director and head of global commodity research, at Bank of America Corp.’s Merrill Lynch unit. “China’s injecting so much money in the economy and there’s a push to hand it out to consumers and businesses.”

China’s oil products consumption rose 11.9 percent to 215 million tons in 2008, according to the China Petroleum & Chemical Association. Consumption of oil products slumped in the first quarter of this year by about 8.7 percent from a year- earlier period as the global recession reduced demand in developed economies for toys and textiles.

Zheng said China Petroleum & Chemical, known as Sinopec, has seen signs that the decline in oil-product demand is slowing. Chinese oil product demand fell 16.5 percent in January, 8.1 percent in February and 2.7 percent in March.

Chinese consumers, who four years ago bought a fifth as many cars as the U.S., purchased more automobiles early this year, Blanch said.

Shares of Sinopec were trading 2.8 percent lower at HK$6.26 at 11:42 a.m. in Hong Kong, having earlier gained as much as 3.7 percent to HK$6.68.

Russia is planning a fleet of floating and submersible nuclear power stations to exploit Arctic oil and gas reserves, causing widespread alarm among environmentalists.

A prototype floating nuclear power station being constructed at the SevMash shipyard in Severodvinsk is due to be completed next year. Agreement to build a further four was reached between the Russian state nuclear corporation, Rosatom, and the northern Siberian republic of Yakutiya in February.

The 70-megawatt plants, each of which would consist of two reactors on board giant steel platforms, would provide power to Gazprom, the oil firm which is also Russia's biggest company. It would allow Gazprom to power drills needed to exploit some of the remotest oil and gas fields in the world in the Barents and Kara seas. The self-propelled vessels would store their own waste and fuel and would need to be serviced only once every 12 to 14 years.

In addition, designers are known to have developed submarine nuclear-powered drilling rigs that could allow eight wells to be drilled at a time.

Bellona, a leading Scandinavian environmental watchdog group, yesterday condemned the idea of using nuclear power to open the Arctic to oil, gas and mineral production.

"It is highly risky. The risk of a nuclear accident on a floating power plant is increased. The plants' potential impact on the fragile Arctic environment through emissions of radioactivity and heat remains a major concern. If there is an accident, it would be impossible to handle," said Igor Kudrik, a spokesman.

Environmentalists also fear that if additional radioactive waste is produced, it will be dumped into the sea. Russia has a long record of polluting the Arctic with radioactive waste. Countries including Britain have had to offer Russia billions of dollars to decommission more than 160 nuclear submarines, but at least 12 nuclear reactors are known to have been dumped, along with more than 5,000 containers of solid and liquid nuclear waste, on the northern coast and on the island of Novaya Zemlya.

The US Geological Survey believes the Arctic holds up to 25% of the world's undiscovered oil and gas reserves, leading some experts to call the region the next Saudi Arabia. But sea ice, strong winds and temperatures that can dip to below -50C have made them technologically impossible to exploit.

Russia, Norway, Denmark, Canada and the US have all claimed large areas of the Arctic in the past five years. Russian scientists used a mini-submarine to plant a flag below the North Pole in 2007 and have claimed that a nearby underwater ridge is part of its continental shelf.

Last week, ministers from many Arctic countries heard scientists and former US vice-president and Nobel prize winner Al Gore say that the Arctic could be free of ice in the summer within five years, with drastic consequences for the world's climate and human health.

But many countries bordering the Arctic see climate change as the chance to exploit areas that were once inaccessible and to open trade routes between the Pacific and Atlantic.

According to a new report by the Arctic Council, an intergovernmental forum, Russia is considering other nuclear plants for power-hungry settlements. "The locations that have been discussed include 33 towns in the Russian far north and far east. Such plants could be also used to supply energy for oil and gas extraction," says the report by the Arctic Monitoring and Assessment Programme.

International oil companies are preparing to go back into Iraq by the end of the year, despite Baghdad's failure to pass an oil law and continuing concerns over security.

BP and Royal Dutch Shell are among companies expected to bid for oil service contracts next month, with the long-term objective of being allowed to develop the world's third-largest oil reserves.

In the past week, executives from many of the world's biggest oil companies - expelled almost 40 years ago - have assured Iraqi officials they plan to commit to working in the country.

Jeroen van der Veer , chief executive of Royal Dutch Shell, said his company was participating in the bidding process and that the new contract terms had made it more attractive to invest there. "Yes, sure. In the end, you have to make up your mind," he said.

The service contracts, which are divided into six groups of fields, include upfront guarantees of soft loans worth a total of $2.6bn (€2bn, £1.7bn).

A BP spokesman said: "If successful, we could see ourselves back in Iraq by the end of the year barring any unforeseen delays."

For five years, following the US invasion of Iraq, oil executives had been insisting on better security and the passage of a hydrocarbon law - seen as crucial by the Bush administration as an indicator of political stability - before they would be willing to invest billions of dollars. Now the companies say they are prepared to return to Iraq even though the country's oil law remains bogged down by political discord and its fragile peace faces two imminent tests: the forthcoming elections and the US military's departure.

Thamir Ghadhban, chairman of the advisory board to Iraq's prime minister and a former oil minister, told the Financial Times that the coming bidding round - the first since the end of the 2003 war - would be heavily subscribed.

"International oil companies are short of reserves and opportunities and countries control almost 88 per cent of oil reserves. The only real opportunity is Iraq."

He said an oil law would no doubt make the companies "more satisfied, but we are not working from a void. We have laws".

Mr Ghadhban added that not one company had come to him with second thoughts or to declare it would not bid because of the absence of a hydrocarbons law. "The oil companies will bid and it will be competitive."

BP, Shell, Total and ExxonMobil were part of the consortium of oil companies whose assets were appropriated by Baghdad when the country nationalised the industry in early 1973.

Iraq, which produces about 2.4m barrels of oil a day, holds reserves of about 115bn barrels, which are relatively easy and inexpensive to tap.

Only Saudi Arabia and Iran hold more oil, but both are off limits to international companies, which have had to move into increasingly remote or expensive areas such as the Arctic and Canada's oil sands.

The breakthrough on Iraq's contracts comes after months of negotiations between Iraqi officials and oil company executives.

Alex Munton, analyst at Wood Mackenzie, the industry consultant, said: "There has been an effort to try to go as far as they can so the oil companies' concerns, raised by the absence of a hydrocarbons law, can be met through the contracts."

He added: "Iraq may be at the bottom of any scale ranking investment climate - even for hardened oil companies - but it is at the top of any scale ranking the attractiveness of its oil reserves."

Bids are due at the start of June and the winners are expected to be revealed by the end of that month. Iraq's cabinet plans to ratify the agreements before the end of August, which would mean companies have to begin work in November or risk losing the contract.

"Iraq is not interested in signing contracts that will not be worked on," Mr Ghadhban stressed, noting that the contracts committed companies to begin work three months after ratification.

Given Iraq's recent record, delay and derailment remain a possibility. For Baghdad, however, getting the contracts signed has become more urgent since the collapse in oil prices - to $50 a barrel from $147 last summer - left a gaping hole in its budget.

For the companies, the drop in the oil price may have drastically reduced available cash but not so much as to force them to forgo the biggest investment opportunity since the fall of communism lifted the barriers to Russia and the Caspian.

A huge oil discovery in Kurdish Iraq sent the share price of Heritage Oil, the London-based explorer, soaring yesterday and added further pressure on Baghdad to issue permits for long-awaited exports of crude oil from the region.

Heritage said that tests completed on a well drilled in its Miran West concession revealed reserves of between 2.3 billion and 4.2 billion barrels. Heritage reckons that between half and 70 per cent of the oil is recoverable, suggesting that at least one billion barrels can be brought to the surface.

The company’s shares rose 24.9 per cent to close at 500p as analysts concluded that the find would transform Heritage much as Rajasthani oil made the fortune of Cairn Energy and Ghana did the same for Tullow.

The find has potentially greater political consequences: at present there is no export route for Kurdish oil because of continuing arguments between Baghdad and the Kurdish Regional Government (KRG) in Arbil. Negotiations are under way to secure permits from Baghdad to allow oil from Tawke, a separate discovery by DNO, a Norwegian oil company, to be transported via Iraq’s northern pipeline to the Turkish port of Ceyhan.

A third company, Addax Petroleum, has also made a large discovery but the addition of a potential several billion barrels from Miran West could significantly enhance Iraqi oil exports.

“Iraq is an area where you can find giants,” Paul Atherton, chief financial officer of Heritage, said. “We are 65 kilometres from Kirkuk.” Kirkuk is one of Iraq’s biggest and oldest oilfields, discovered by a European consortium in the 1930s. It originally had 22 billion barrels of oil.

Ethnic and political jealousies have dogged the KRG efforts to develop an oil industry independently of Baghdad with the help of foreign investors. While Exxon, Shell and Total waited for opportunities to exploit known giant oilfields in southern Iraq, the Kurdish authorities granted licences to small but adventurous firms to drill in unexplored regions in the north.

The redevelopment of Iraq's oil industry will needed to be funded in part by soft loans provided by international companies, the country's oil minister Hussain al-Shahrastani has confirmed.

Speaking to Reuters in London at a conference promoting investment in the country, the minister said that weak oil prices had created a large dent in the country's fiscal budget and added that the money needed to fill this gap would have to be paid in part by foreign companies looking to search for oil in the country.

Speaking of the current development conditions attached to existing tender applications, al-Shahrastani said: "These are not signature bonuses but soft loans that we expect the international oil companies to provide, that will be repaid by the oil produced."

He added that the country is not prepared to slow the pace of its development programme as it waits for higher oil prices.

Speaking to the Independent, Sir Claude Hankes, an adviser to the Trade Bank of Iraq, warned that UK companies risked missing out in development plans because of their failure to commit to training programmes for Iraqi workers.

A massive natural-gas discovery here in northern Louisiana heralds a big shift in the nation's energy landscape. After an era of declining production, the U.S. is now swimming in natural gas.

Even conservative estimates suggest the Louisiana discovery -- known as the Haynesville Shale, for the dense rock formation that contains the gas -- could hold some 200 trillion cubic feet of natural gas. That's the equivalent of 33 billion barrels of oil, or 18 years' worth of current U.S. oil production. Some industry executives think the field could be several times that size.

"There's no dry hole here," says Joan Dunlap, vice president of Petrohawk Energy Corp., standing beside a drilling rig near a former Shreveport amusement park.

Huge new fields also have been found in Texas, Arkansas and Pennsylvania. One industry-backed study estimates the U.S. has more than 2,200 trillion cubic feet of gas waiting to be pumped, enough to satisfy nearly 100 years of current U.S. natural-gas demand.

The discoveries have spurred energy experts and policy makers to start looking to natural gas in their pursuit of a wide range of goals: easing the impact of energy-price spikes, reducing dependence on foreign oil, lowering "greenhouse gas" emissions and speeding the transition to renewable fuels.

A climate-change bill being pushed by President Barack Obama could boost reliance on natural gas. The bill, which could emerge from the House Energy and Commerce Committee in May, is expected to set aggressive targets for reducing emissions of carbon dioxide, the most prevalent man-made greenhouse gas.

Meeting such goals would require quickly moving away from coal-fired power plants, which account for substantial carbon emissions. President Obama wants the U.S. to rely more on renewable energy such as wind and solar power, but those technologies aren't ready to shoulder more than a fraction of the nation's energy burden. Advocates for natural gas argue that the fuel, which is cleaner than coal, would be a logical quick fix. In addition, billionaire energy investor T. Boone Pickens has been touting natural gas as an alternative to gasoline and diesel for cars and trucks.

"The availability of natural-gas generation enables us to be much more courageous in charting a transition to a low-carbon economy," says Jason Grumet, executive director of the National Commission on Energy Policy, who was a senior adviser to President Obama during the campaign.

Just three years ago, the conventional wisdom was that U.S. natural-gas production was facing permanent decline. U.S. policy makers were resigned to the idea that the country would have to rely more on foreign imports to supply the fuel that heats half of American homes, generates one-fifth of the nation's electricity, and is a key component in plastics, chemicals and fertilizer.

But new technologies and a drilling boom have helped production rise 11% in the past two years. Now there's a glut, which has driven prices down to a six-year low and prompted producers to temporarily cut back drilling and search for new demand.

The natural-gas discoveries come as oil has become harder to find and more expensive to produce. The U.S. is increasingly reliant on supplies imported from the Middle East and other politically unstable regions. In contrast, 98% of the natural gas consumed in the U.S. is produced in North America.

Coal remains plentiful in the U.S., but is likely to face new restrictions. To produce the same amount of energy, burning gas emits about half as much carbon dioxide as burning coal.

Natural gas has never played more than a supporting role in the nation's energy supply. Crude oil, refined into gasoline or diesel, fuels nearly all U.S. cars or trucks. Coal is the dominant fuel for generating electricity.

Natural-gas production in the U.S. peaked in the early 1970s, then fell for a decade due to weak prices and declining gas fields in Texas, Louisiana and elsewhere. Production bounced back in the 1990s with the discovery of new fields in New Mexico and Wyoming, but by 2002, output was falling again -- this time, most experts thought, for good. Believing the U.S. would soon need to import liquefied natural gas from overseas, companies such as ConocoPhillips, El Paso Corp. and Cheniere Energy Inc. spent billions on terminals, pipelines and storage facilities.

The supply fears drove up prices, which spurred innovation. Oil-and-gas companies had known for decades that there was gas trapped in shale, a nonporous rock common in much of the U.S. but considered too dense to produce much gas.

In the 1980s, Texas oilman George Mitchell began trying to produce gas from a formation near Fort Worth, Texas, known as the Barnett Shale. He pumped millions of gallons of water at high pressure down the well, cracking open the rock and allowing gas to flow to the surface.

Oklahoma City-based Devon Energy Corp. bought Mr. Mitchell's company in 2002. It combined his methods with a technique for drilling straight down to gas-bearing rock, then turning horizontally to stay within the formation. Devon's first horizontal wells produced about three times as much gas as traditional vertical wells.

The development of the Barnett Shale almost single-handedly reversed the decline in U.S. natural-gas production. Last year, the Barnett produced four billion cubic feet of gas a day, making it the largest field in the U.S. Other companies such as Newfield Exploration Co., Southwestern Energy Co. and Range Resources Corp. found shale fields across the U.S.

One of the most aggressive companies was Oklahoma City-based Chesapeake Energy Corp., which got into the Barnett a couple of years behind cross-town rival Devon, and was an early entrant into the second big U.S. field, the Fayetteville Shale in Arkansas. In 2005, Chesapeake Chief Executive Aubrey McClendon sent teams of geologists across the country with a mission: Find the next Barnett. Less than two years later, they told him they had it, in Louisiana.

The Haynesville Shale is centered in northern Louisiana, one of the country's oldest oil- and gas-producing regions. Wildcatters had explored beneath the lush cow pastures and cotton fields as far back as the 1870s. Shreveport, the region's largest city, saw decades of booms and busts until the 1980s, when a glut of cheap oil from overseas all but killed the region's oil industry.

Oil companies knew about the Haynesville Shale, but it was considered a less viable prospect than the Barnett. The shale lies 10,000 or more feet below ground, where high pressure and 300-degree temperatures are enough to fry high-tech drilling equipment.

But in 2006, Chesapeake drilled an exploratory well and decided the results were promising enough to justify the higher cost of drilling in such harsh conditions. By late 2007, Mr. McClendon says, "we knew that we had a tiger by the tail."

In March 2008, as oil and gas prices were soaring, Chesapeake went public with its findings. The rush was on: Dozens of companies dispatched agents to the area to lease land for drilling, turning farmers and ranchers into millionaires overnight.

"There was excitement in the air," recalls Jeffrey Wellborn, a Shreveport resident who sits on the board of the local Sierra Club. "You thought everyone in the world had won the lottery."

The frenzy marked the peak of a nationwide drilling boom that was fueled by a combination of soaring energy prices and easy credit. It didn't last. Between July and October, oil and gas prices fell by more than 50%, and kept falling.

The weakening economy eroded demand for both oil and gas. Natural gas, unlike oil, suffered from a supply glut. U.S. gas production rose 7.2% last year, while oil production fell 1.9%. As a result, oil prices are up 12% since the start of 2009. Natural-gas prices have fallen 41% to their lowest since 2002.

Gas producers saw their profits evaporate and share prices slump. Liquefied-natural-gas imports plunged, leaving import terminals nearly idle. Worried about a glut, companies cut back sharply on drilling and formed a lobbying group to try to boost demand.

The growing supply created opportunities for policy makers and environmentalists, who saw natural gas as a possible solution to the nation's energy problems. Some groups suggested burning more gas and less coal for power generation. Others favor its use in vehicles.

Mr. Pickens has spent millions promoting an energy plan that aims to, among other things, convert thousands of big-rig trucks to run on natural gas. Mr. Pickens has large investments in natural gas and stands to benefit if his plan is adopted. In TV ads, Internet videos and speeches, he emphasizes a different goal: reducing U.S. dependence on foreign oil.

Mr. Pickens arrived for a recent speech in Dallas in a natural-gas-fueled Honda Civic with a bright blue "Pickens Plan" logo. He told a packed auditorium that the U.S. is importing two-thirds of its oil even as the country is "absolutely overwhelmed with natural gas." If the reverse were true, he said, he would favor burning oil.

Some environmentalists have embraced Mr. Pickens's plan as a way to fight climate change. Carl Pope, executive director of the Sierra Club, says he sees natural gas as a "bridge fuel" that could help the U.S. burn less coal and oil until renewable sources of energy are ready to take over.

The dual message of energy security and environmental responsibility has helped Mr. Pickens win powerful allies, including Senate Majority Leader Harry Reid, House Speaker Nancy Pelosi and dozens of elected officials from both parties. A bipartisan bill providing tax incentives for natural-gas cars looks likely to pass this year.

Not everyone shares Mr. Pickens's enthusiasm for natural-gas vehicles. Major users of natural gas, such as utilities and chemicals companies, are concerned the plan would drive up prices -- an outcome that would benefit producers.

Energy Secretary Steven Chu and some other policy makers have expressed doubts about the practicality of retrofitting hundreds of thousands of service stations to offer natural gas. Some environmental groups, including the Natural Resources Defense Council, have argued that natural gas is better used to replace coal for power generation, and that cars should run on electricity generated by the sun, wind and natural gas.

Market forces are already helping natural gas make inroads against coal and oil. Gas is now cheaper than coal in many parts of the country, leading utilities to burn more gas. Of the 372 power plants expected to be built in the U.S. over the next three years, 206 will be fired by gas and just 31 by coal, according to the Energy Information Administration.

Natural gas is gaining market share far more slowly in transportation. Earlier this year, AT&T announced it would convert up to 20% of its truck fleet to run on natural gas, largely because it has been cheaper than gasoline in recent years. Cities including New York, Los Angeles and Atlanta have converted part of their bus fleets to run on natural gas, for air-quality reasons.

Shreveport could be the next city to make the switch. In March, Mayor Cedric Glover announced that the oil capital turned natural-gas boomtown would abandon diesel and convert its bus fleet to natural gas.

Russell Gold contributed to this article

Europe's decades-old oil-indexed gas contracts are creaking under a deluge of cheap liquefied natural gas, sagging demand and sliding producer profits but change will be slow in a conservative market, analysts say.

Most of Europe's gas has been supplied under long-term contracts priced off oil since the 1970s, because crude offered a relatively transparent reference point that consumers and producers could agree on before gas became a global commodity through the growth of liquefied natural gas (LNG) trade.

But the global economic crisis has slashed crude prices, testing gas producers' dedication to oil-benchmarked deals. And while gas contract prices have started to fall, consumers could buy even cheaper gas on the spot market if they did not have to meet contracted pipe gas obligations.

"I don't think we have ever seen a time when the prices in the contracts were under greater threat," Jonathan Stern, director of gas research at the Oxford Institute for Energy Studies, said.

"It's increasingly clear that the oil linkage doesn't make any sense in the gas market...However, all of the major stake holders - producers, exporters and importers - love them."

Producers like long-term contracts because they provide investment security by requiring consumers to pay for a set amount of gas even if they do not need it.

The contracts have been equally popular with big buyers in continental Europe because they guarantee long-term supplies at a predictable price.

But the economic crisis has slashed energy demand across Europe, while slack Asian LNG demand has seen many tankers head to Europe over the last few weeks, driving spot prices down and making pipeline supplies less attractive.

"If enough cheap LNG comes into Europe, we could see tremendous pressure on spot prices falling, we could see significant inability to take (pipeline gas) and all of a sudden things could begin to unravel," Stern said.

"You have a big enough market in Europe now for gas that the supply and demand dynamics set the price. You still have long term contracts, you just have them with prices that are market determined."

Noel Tomnay, principal gas analysts at consultants Wood Mackenzie, agreed that the longer spot gas continues to be significantly cheaper than oil-indexed gas the more likely customers are to try to renegotiate contracts.

"We see this as putting a lot of pressure on those long term contracts and a dangerous time for justifying the perpetuation of those oil-indexed contracts," he said.

"But we anticipate that oil-indexed contracts still have a lot of life left in them because they satisfy the needs of buyers and sellers."

Gas exporters are especially keen on oil-indexed deals when crude prices are high, with big producers of both fuels such as Russia seeing their income soar when oil surged to over $147 a barrel last July.
But their fondness for oil-linked contracts seems to be waning again as their profits plunge, with oil down about 60 percent from record highs seen last summer.

Russian Energy Minister Sergei Shmatko said last month the world's largest gas producer was in talks with customers about changing the terms under which about a quarter of Europe's gas is supplied.

ALTERNATIVES
Europe's pipeline gas suppliers -- Russia, Algeria and Norway -- could raise the base price for gas in their contracts while reducing the oil weighting.

"I suspect we are going to see a period, through the (contract) price reviews, where you gradually increase the percentage of gas in the mix and you reduce the percentage of oil," said Niall Trimble, director of the Energy Contract Company.

"It's very likely that in 10 years time we will be working substantially on spot gas prices but I don't think we are going to see a big bang."

Because most gas on the continent is sold on long-term contracts, market-liberaliser Britain has the only really liquid spot gas market in the region.

UK spot prices have tumbled since January as large amounts of LNG have been unloaded in the country at a time of falling demand.

Significant amounts have been sucked away through a link to Belgium by bargain hunters in continental Europe who are taking as little contracted gas and buying as much spot as they can.

PRICE SPIKES

But analysts warn a pan-European spot market, with few or no long term deals underpinning supplies, could lead to huge price spikes should demand rebound and today's cheap and plentiful LNG become a distant memory.

Unless Europe succeeds in diversifying its sources through building more pipelines, the existing trio of big pipeline gas players could implicitly set gas prices when supplies get tight.

"Once the market ceases to be oversupplied then who is going to be the marginal supplier?," Tomnay said.

"It would mean a lot more volatility but would you actually end up with lower prices on a prolonged basis, maybe not." (Reporting by Daniel Fineren; Editing by Keiron Henderson)

The internet's increasing appetite for electricity poses a major threat to companies such as Google, according to scientists and industry executives.

Leading figures have told the Guardian that many internet companies are struggling to manage the costs of delivering billions of web pages, videos and files online – in a "perfect storm" that could even threaten the future of the internet itself.

"In an energy-constrained world, we cannot continue to grow the footprint of the internet … we need to rein in the energy consumption," said Subodh Bapat, vice-president at Sun Microsystems, one of the world's largest manufacturers of web servers.

Bapat said the network of web servers and data centres that store online information is becoming more expensive, while profits come under pressure as a result of the recession.

"We need more data centres, we need more servers. Each server burns more watts than the previous generation and each watt costs more," he said. "If you compound all of these trends, you have the perfect storm."

With more than 1.5 billion people online around the world, scientists estimate that the energy footprint of the net is growing by more than 10% each year. This leaves many internet companies caught in a bind: energy costs are escalating because of their increasing popularity, while at the same time their advertising revenues come under pressure from the recession.

One site under particular scrutiny is YouTube — now the world's third-biggest website, but one that requires a heavy subsidy from Google, its owner. Although the site's financial details are kept under wraps, a recent analysis by Credit Suisse suggested that it could lose as much as $470m (£317m) this year, as it succumbs to the high price of delivering power-intensive videos over the internet.

And while the demand for electricity is a primary concern, a secondary result of the explosion of internet use is that the computer industry's carbon debt is increasing drastically. From having a relatively small impact just a few years ago, it is now leapfrogging other sectors like the airline industry that are more widely known for their negative environmental impact.

However, tracking the growth of the internet's energy use is difficult, since internal company estimates of power consumption are rarely made public.

"A lot of this internet stuff is fairly secretive," Rich Brown, an energy analyst at the Lawrence Berkeley National Lab in California, told the Guardian.

"Google is probably the best example: they see it as a trade secret: how many data centres they have, how big they are, how many servers they have."

One study by Brown, commissioned by the US environmental protection agency, suggested that US data centres used 61bn kW of power in 2006. That is enough to supply the whole of the UK for two months, and 1.5% of the entire electricity usage of the US.

Brown said that despite efforts to achieve greater efficiency, internet use is growing at such a rate that it is outstripping technical improvements – meaning that American data centres could account for as much as 80bn kW hours this year.

"Efficiency is being more than overwhelmed by continued growth and demand for new services," he said. "It's a common story … technical improvements are often taken back by increased demand."

Among the problems that could result from the internet's voracious hunger for electricity are website failures and communications disruption costing millions in lost business every hour – as well as power cuts and brownouts at plants which supply data centres with electricity.

To combat this, initiatives are taking place across the industry to cope with the problem, including new designs for data centres, innovative cooling methods and more investment in renewable energy.

Researchers at Microsoft's £50m research lab in Cambridge are even turning to older technology in an attempt to turn the clock back – by replacing energy-hungry new machines with the systems used in older, less powerful laptops.

"It turns out that those processors have been designed to be very energy efficient, basically to make batteries last," said Andrew Herbert, the director of Microsoft Research Cambridge.

"We found we can build more energy-efficient data centres with those than with the kind of high performance processors you find in a typical server."

Google was among the first internet companies to take action to reduce its footprint by developing its own data centres — but even though it pumped an estimated $2.3bn into infrastructure projects last year, it remains unclear whether it is winning the battle.

The company's vice-president of operations, Urs Hölzle, told the Guardian that it was struggling to contain energy costs. "You have exponential growth in demand from users, and many of these services are free so you don't have exponential growth of revenue to go with it," he said.

"With good engineering we're trying to make those two even out … but the power bill is going up."

Despite mounting evidence that the internet's energy footprint is in danger of running out of control, however, Hölzle dismissed concerns about the environmental impact of using the web as "overblown".

"One mile of driving completely dwarfs the cost of a search," he said. "Internet usage is part of our consumption, just like TV is, or driving. There is consumption there, but in the grand scheme of things I think it is not the problem."

BRITAIN is facing an energy crisis as a rise in renewable power is pushing the "outdated" National Grid to breaking point, experts warned yesterday .

Analysts say the network cannot cope with the extra electricity generated by wind, wave and solar sources.

They fear the increase in renewables will overload a system that was not designed to accept so much incoming power.

Inenco, the UK's largest energy analyst, said Britain could be plunged into darkness unless the infrastructure was updated.

Inenco analyst Ian Parrett said the overhaul could cost the government between £5 billion and £10bn. He said: "The UK's electricity infrastructure is so outdated and expensive that the renewables push towards wind farms and other forms of micro-generation is going to place an impossible strain on the network.

"It was not designed for two-way power generation, where smaller generating sources put energy back into the grid, and this will continue to be the case unless the government invests heavily in upgrading the grid."

He added "This is all in stark contrast to a country like Germany, where not only is the energy supply system a lot more efficient, connecting local energy supplies to it is either free, via government subsidies, or costs just a few thousand pounds."

One of Britain's largest water companies is planning to convert waste piped from millions of British homes into fuel that could be sold to power companies.

Severn Trent, which supplies water and waste services to 3.7 million households, already generates nearly 17 per cent of the electricity that it consumes by burning sewage gas, or methane, collected from its network of sewage plants across the Midlands and mid-Wales.

Tony Wray, Severn Trent's chief executive, told The Times that the in-house scheme was the first step in a programme to develop raw sewage sludge into pellet fuel for burning in power plants, which are being offered subsidies to switch to environmentally friendly biomass alternatives to coal and natural gas.

Since 2003, Renewables Obligation Certificates — a form of subsidy to accredited generators — have been available for electricity that is generated by burning biomass fuels, which include wood, straw or sewage gas and sludge.

“Sludge has half the calorific content of brown coal, so this is a very viable fuel,” Mr Wray said. “The trick is to find new ways to dry it. Wet sludge is not very economical to use.”

Severn Trent is working with the European Bioenergy Research Institute at Aston University in Birmingham to develop a system using a chemical process known as pyrolysis, which would effectively bake sludge into a form that could be used to produce heat and electricity. Mr Wray said that initially Severn Trent would test the fuel but ultimately could sell it to utilities, creating a new revenue stream.

Water groups are under growing pressure to find new uses for more than one million tonnes of sewage sludge that is produced in the UK every year. Before 1998, much of the waste was dumped at sea or in landfill sites, but sea disposal is now banned under European Union law, while landfill has become an increasingly expensive option because of higher taxes and stricter government controls. This year, landfill tax is set to increase by 20 per cent to £40 per tonne, up from £32 in 2008. Next year, it is set to rise again to £48 per tonne.

Severn Trent utilises sewage gas to fuel 53 separate heat and power generation units at 35 of its sites. For example, at Minworth sewage treatment works near Birmingham, Severn Trent generates an average of 9.5 megawatts of electricity — enough to provide power for about 18,000 homes.

The British water industry has spent almost £500million developing new ways to treat and manage sewage, according to Severn Trent.

About 347,000km of sewers collect more than 11billion litres of waste water in the UK every day. This water is treated at about 9,000 sewage treatment works across the country. Roughly 62 per cent of the country's sludge is treated and recycled into a type of fertiliser known as biosolids, which is used to fertilise more than 80,000 hectares of British farming land every year.

While there is growing interest in the use of waste for fuel, it is not unprecedented. In the Thirties, sewage gas was used to power public transport systems in some German cities, including Essen and Munich.

Severn Trent, which also generates some electricity from hydro-electric turbines, which are installed on three of its large reservoirs, wants to generate 30 per cent of its electricity from renewable sources by 2013.

Project delays and cancellations across the renewable energy industry mean that this year’s gathering at the world’s biggest annual wind energy conference and exhibition will be keen for word of stimulus funds to help get projects back on track.

Investment in renewables has been delayed or even withdrawn as the credit crisis has stemmed the flow of capital. The economic recession has cut into sales of clean technology, while plunging prices of oil and natural gas have rendered such projects less economically viable.

The Obama administration’s economic stimulus package includes $56bn in grants and tax breaks for US clean energy projects over the next 10 years and a budget of $15bn a year to fund renewable energy programmes.

Yet the US government has not worked out how to deliver those funds; none of that money has been seen by the wind-power industry.

Many in the sector do not have the certainty they would like that they will be recipients, said Rob Gramlich, policy director of the American Wind Energy Association, which is organising this week’s conference in Chicago.

He said: “There is cautious optimism now that could turn to nervousness unless the industry sees the actual dollars start flowing”.

That issue is expected to be addressed by Ken Salazar, secretary of the US Department of the Interior, a keynote speaker at the forum.

Other speakers include Vic Abate, vice president for Renewables at GE Energy; Ditlev Engel, president and chief executive of Vestas Wind Systems; Michael Polsky, of Invenergy; Don Furman, senior vice president of development, transmission and policy at Iberdrola Renewables; and General Wesley Clark, chairman of Emergya Wind Technologies Americas.

Interest in wind energy in the US has been stoked in part by T. Boone Pickens, the oilman who has made giving the US an alternative to importing fossil fuels a personal mission.

He has formed Mesa Power to build the world’s biggest wind farm in Texas, with 2,700 turbines generating enough power for 1m US homes. And while he has “lost some people” with the downturn, turbines are due for delivery in 2011.

He said: “We have not lost any enthusiasm”.

Even with dire economic conditions, the wind energy industry installed more than 2,800MW of US generating capacity in the first quarter of this year, with projects completed in 15 states.

Denise Bode, AWEA chief executive said: “These brand-new wind projects shine a ray of hope on our economy today. But the nation still lacks the long-term signal that is needed to build up renewable energy on a large scale.”

That would come with a Renewable Electricity Standard, which the industry wants Congress to pass, requiring utilities to generate 25 per cent of their power from renewables by 2025. That would support massive growth of wind energy in the US.

Wind energy meets only about 1 per cent of US energy needs. Yet the desire to increase that capacity is apparent – attendance at the AWEA conference is expected to be about 20,000, up from 13,000 last year.

GE’s Mr Abate said customers for his company’s wind turbines were not cancelling orders but rather postponing them, underlining that they still believed in wind.

Yet, he added, the industry was growing impatient for stimulus funds. After all, he noted, of the 21 financial institutions that GE Energy had as partners on wind projects before the crisis, only four remained.

Mr Abate said: “There is definitely a sense of urgency on behalf of the industry to get the money out. To date, not a dime has reached our customers.”

Britain’s most lucrative train franchise is on the brink of failure, leaving the Government facing a £1 billion hole in its rail budget.

National Express is in talks with the Department for Transport about the future of its East Coast line operation, which has been hit hard by the recession and is incurring heavy losses.

The company is contracted to pay the Government £1.4 billion over seven years for the franchise. But now it hopes to persuade the department not only to let it off the rest of the charge, but also to pay the company to carry on running the trains.

The Government wants to avoid the impression that it is bailing out a private company and fears that, if it agrees to the deal, other train companies would also demand new terms. Stagecoach is in dispute with the DfT about how much it is due to pay next year for the South West Trains franchise. Arriva is also facing heavy losses on its CrossCountry line. Both insist that they will honour their financial commitments to the ministry, but they may take a different view if National Express secures a favourable deal.

A ministry source dismissed reports that a deal with National Express had been approved in principle, saying the company could be stripped of its two profitable rail franchises — East Anglia and c2c — if it defaulted on its East Coast payments.

“There is a cross-default clause in the contract which we could invoke if they stopped paying. They could not only lose all their franchises but would leave a bad impression which might affect future franchise competitions,” the source said.

However, ministers may decide that accepting the terms proposed by National Express would cost the taxpayer less in the long run than allowing the franchise to collapse and seeking another company to run it. Either way, the Government will have to revise sharply downwards its projections for income from franchises over the next six years. It will either have to cut investment in the rail network — possibly by cancelling expansion and electrification of key lines — or increase the subsidy.

Ministers are considering abandoning the plan announced in 2007 to make passengers pay a much higher proportion of the costs of the railway. The Government said then that the contribution made by passengers would rise from 25 per cent of total costs in 2007 to 50 per cent by 2014.

Norman Baker, the Liberal Democrat transport spokesman, said: “If the Government bails out National Express it will give the green light to every other train company to go to the DfT with a bowl asking for more money. What is the point in having a system that claims to hand risk to the private sector but the minute companies get into trouble they are rescued with taxpayers’ money?”

Richard Bowker, the chief executive of National Express, told The Times: “We are having discussions with the DfT which include the impact of the recession on the East Coast franchise. Today we are meeting all our obligations for that franchise.”

Asked if National Express would still be meeting them tomorrow, he said: “I am not going to get into what I am sure would be a very interesting discussion.” He implied that National Express should not be expected to pay the price for failing to predict the recession. “I don’t think anybody in May or June 2007 [when National Express agreed the East Coast contract] saw the depth or ferocity or pace of this recession coming.”

National Express reported yesterday that underlying revenue growth at East Coast had fallen to 0.3 per cent in the first three months of this year. It refuses to discuss passenger numbers. The company had based its franchise bid on the assumption that revenue would grow by 10 per cent every year until 2015.

Douglas McNeill, transport analyst at Blue Oar Securities, said: “The DfT has to weigh up the choice between principle and hard cash. If they hold National Express to their franchise terms, the risk is that the company may decide to hand back the franchise and the retendering would be done on much less generous terms for the taxpayer.”

National Express, which also runs buses and coaches, employs 43,000 people worldwide, 16,000 of them in Britain. It made 750 people redundant recently.

If you’re fighting to stay afloat in the teeth of a recession, you’re not going to worry about distant threats like peak oil and climate change, right? Wrong, say Brian Souter, Moir Lockhead, Will Whitehorn and Richard Brown. The UK’s leading transport chiefs tell Martin Wright why action now is essential for their business survival.

At the end of the year, eight UK companies came together under the auspices of the UK Industry Taskforce on Peak Oil and Energy Security to publish a report entitled The Oil Crunch. It was a stark warning that cheap, easily available petroleum production is likely to peak by 2013, sending the price soaring and the markets into turmoil. It called on the Government to respond with a crash programme of investments in energy efficiency and renewables, among other measures. These would not only offset the impact of peak oil, it argued, but also deliver massive cuts in carbon emissions [see 'What does cheap oil mean for renewables?'].

Among the signatories to The Oil Crunch were three of the UK’s principal transport operators, Stagecoach, First Group and Virgin. These are not the easiest of times for the sector: after several years of stellar growth, passenger numbers on trains in particular are levelling off rapidly, and the operators are locked in complex tussles with the Government over the terms of franchise agreements.

Meanwhile, times are relatively sunny for Eurostar. Although not involved in the report, the company has recently become a vocal proponent of low-carbon travel.

So Green Futures asked the key leaders in each company what peak oil and climate change mean for their business – and how they square it with day-to-day survival...contd.

The next time you buy fish and chips for tea, the oil they were cooked in could fuel your bus ride home.

The latest addition to First's bus fleet due to hit the road will be fuelled by biodiesel produced from waste cooking oil.

Branded "The Chipper", the single decker bus is part of a six-month trial to see if frying oil can be cost effective.

Southville-based company McKeown Bio Fuels will collect the waste oil from a number of businesses which are sponsoring the trial, including Bishopston Fish Bar in Gloucester Road, Teohs pan-Asian restaurants, and First's own canteen at the depot in Easton Road.
McKeown – the company that won the Evening Post's award for sustainable business last year – will then add chemicals and convert the oil into biodiesel.

 The biodiesel is then used to fuel the bus, without the need to convert the vehicle.

The bus – a 1998 Dennis Dart – will run on the No.73 route, between the city centre and Cribbs Causeway, passing many of the businesses supporting the project along the way.

Anyone stuck in traffic behind the bus will be able to smell a faint aroma of chips from the vehicle exhaust. The bus also sports another first for First, a full colour route display on the front of the vehicle.

People can support the project directly by donating their own waste cooking oils at either of the city's household waste recycling centres.

John Bickerton, engineering project manager for First UK Bus, said: "As well as being a near carbon-neutral fuel source, biodiesel made from waste cooking oil can produce less carbon monoxide when it is burnt, so it is considered better for the environment than conventional diesel.

"During this project we'll be closely monitoring the emissions produced by The Chipper, examining them every 28 days.

"If it is shown that the vehicle produces less smoke as a result of running on biodiesel, that would be very good news."

At the end of the six-month trial the company will consider whether it is cost effective to roll out the fuel to the rest of its fleet.

The buses require about 600 litres of biodiesel to run every week.

The 100 per cent biodiesel bus is one of a package of green initiatives First has been looking at. Others include vehicles that automatically shut off after four minutes of being idle and environmentally friendly tyres.

Justin Davies, managing director of First in Bristol, said: "We welcome any opportunity to trial new or alternative technologies, particularly if in doing so we're able to reduce our own impact on the environment.

He added: "It will also be interesting to see what local bus users think of the trial."

Power capacity in Britain is sufficient to charge electric cars in the medium term, according to a new report.

The study, which was carried out by a team of representatives from companies such as Ricardo, Jaguar-Land Rover, E.ON and Amberjac Projects, suggested that a ten per cent increase in electric cars and plug-in hybrids would raise power demand by less than two per cent.

It also revealed that the increase in demand for energy would most likely be spread over the market and be distributed evenly.

Neville Jackson, group technology director at Ricardo, said: "The increasing electrification of road vehicles is likely to be a key enabler for future significant reductions in transport-related CO2 emissions.

"While the provision of publicly accessible street level infrastructure in the form of recharging points remains a challenge, the research findings published today show that existing UK power grid capacity will be sufficient in the medium term to support a significant expansion of plug-in hybrid and electric vehicle use and is therefore not a constraint on implementation."