Crude oil rose for the first time in three days on better-than-expected corporate earnings and as jobless claims held below levels seen in late June.

Oil gained as much as 2.5 percent as stock futures advanced on increased optimism that the economic downturn will ease. The number of people collecting unemployment insurance decreased for a third week, according to the Labor Department. A U.S. report yesterday showed that crude supplies unexpectedly climbed as demand lagged behind year-earlier levels.

“More people think the economy has bottomed and are buying equities and commodities as a result,” said Bill O’Grady, the chief market strategist for Confluence Investment Management in St. Louis. “The fundamentals of the oil market are still poor, but investors are looking to the future.”

Crude oil for September delivery rose $1.28, or 2 percent, to $64.63 a barrel at 9:05 a.m. on the New York Mercantile Exchange. Prices are up 45 percent this year.

Yesterday, futures dropped $3.88, or 5.8 percent, to $63.35, the biggest one-day decline since April, after the Energy Department reported that crude-oil inventories gained 5.15 million barrels to 347.8 million in the week ended July 24.

“Yesterday, we had a big selloff based on supply and demand,” said Peter Beutel, president of Cameron Hanover Inc., an energy consulting company in New Canaan, Connecticut. “It looks like we are back to trading on extraneous external factors like the equity market and dollar instead of the fundamentals.”

U.S. stockpiles of distillate fuel, a category that includes diesel and heating oil, rose 2.1 million barrels to 162.6 million, the highest since January 1985, the department said yesterday in its weekly report.

Goldman Forecast

Goldman Sachs Group Inc. maintained its forecast that West Texas Intermediate crude oil, the benchmark grade for New York futures, will reach $85 a barrel by year-end as the recent weakness in fundamentals will be temporary.

“Concerns over economic growth and weak oil statistics led a commodity selloff yesterday,” Goldman analysts, led by London-based Jeffrey Currie, said in a report today. “However, we believe most of these drivers are less negative than they first appear.”

Brent crude oil for September settlement on London’s ICE Futures Europe exchange increased $1.63, or 2.5 percent, to $68.16 a barrel.

Falling oil and gas prices hit profits at European oil majors Royal Dutch Shell Plc (RDSa.L) and Repsol (REP.MC) in the second quarter, prompting both to cut costs and scale back investments.

Shell said the industry was grappling with a combination of weak demand for energy, excess capacity, and high industry costs, with no early respite expected.

Net income excluding inventory adjustments plunged about two thirds at both companies, repeating a tale told earlier in the week by a string of energy companies including BP and ConocoPhillips, and reflecting the sharp drop in oil prices from their July 2008 peak of $147 a barrel.

Tighter refining margins also took a toll, helping knock 58 percent off net income at Finnish oil refiner Neste Oil.

The drops would have been worse, but for foreign exchange gains after the dollar strengthened, but even so, both companies outperformed analysts' expectations. 

Shell Chief Executive Peter Voser, who took office earlier this month, gave a sombre outlook for energy demand and prices.

"We are not banking on a quick recovery," he said in a statement.

Shell's London-listed A shares were down 0.3 percent at 0857 GMT, while Repsol shares had edged up 0.15 percent, buoyed by a better-than-expected performance at its Argentine unit. Both were underperforming the DJ Stoxx European oil and gas sector index .SXEP, which was up about 0.5 percent.

COST CUTS

Hague-based Shell, the world's second-largest non government-controlled oil company by market value, is aiming to tackle the tough environment by slashing costs.

It said it achieved $700 million in cost savings in the first half of the year compared with the same period in 2008.
This excludes savings from the stronger dollar, which shaved another $2 billion off costs in the first half.

British rival BP said earlier this week it had saved $2 billion in the first half of the year, helped by currency gains.

Since July 1, Shell has cut 20 percent of senior management positions and said there would be "substantial further staff reductions". It also said its capital investment budget would fall 10 percent next year to $28 billion.

Analysts at Petercam said that shouldn't affect its production growth target of 2-3 percent between now and 2012.

Repsol said it had put in place a "an extraordinary savings plan" that would slash over 10 percent of its planned 2009 spending.

Shell, Europe's largest listed company, said oil and gas production continued to fall, dropping 5.3 percent in the quarter compared to the same period of 2008.

Repsol enjoyed a 1 percent lift in output compared to the same period of 2008, which was depressed by an oil workers' strike in Argentina.

Additional reporting by Catherine Hornby in Amsterdam, Jonathan Gleave in Madrid and Brett Young in Helsinki, editing by Will Waterman

Talking to corporate analysts over the several years that I’ve been back in the U.S. and covering oil, a recurring question I hear is how Exxon manages year after year without exception — unlike its Big Oil rivals — to replenish its cache of proven oil and natural gas reserves. That’s what the company has reported in its news releases and annual reports for the last nine years — an unbroken trajectory of replacing more than 100% of the oil and natural gas that it pumps out of the ground.

The answer is that it hasn’t done so, not at least according to the rules of the Securities and Exchange Commission, which governs such matters. When you examine Exxon’s annual filings for 1999-2008, the company has had a quite-normal — for oil companies, that is — four years of exceeding 100% replacement, and five years not. For instance, for 2008 the company issued a statement saying that it possessed 22.8 billion barrels of proven reserves; yet its 10-K filing with the SEC reported just 21.1 billion barrels in proven reserves (to get there, see page 7 of the 10-K, and tally up the developed and undeveloped reserves in the consolidated and equity categories).

So I gave Exxon a call. How do you get from 21.1 billion barrels to 22.8 billion barrels? I asked.
Add in the oil sands, was the reply.

That would be the approximately 1.8 billion barrels of oil equivalent that Exxon has booked so far in its Alberta, Canada, oil sand holdings (see pages 22 and 23 of the 10-K; add the Syncrude and Kearl reserves).

Strictly speaking, SEC rules don't permit comingling of oil that's pumped out of the ground, along with oil sands -- exceptionally tar-like material that in most cases isn't pumped, but instead is actually mined like a mineral, then mixed with chemicals in order to move it to a refinery for processing. But companies can comingle them in public announcements such as news releases and annual reports that are read by reporters, investors and Wall Street analysts, according to an SEC spokesman.

This isn't criticism of Exxon. Rather, it's simply evidence that Exxon, like all of Big Oil, is mortal. I wrote about this earlier a piece in Business Week.

In fact, Exxon has been highly critical of how the SEC requires it to report reserves. It has said that it has its own, rigorous, internal methods of assessing its proven reserves, and that this process far more accurately reflects what it possesses.

Why does reserve replacement attract so much attention? Because investors and company analysts regard this metric as a primary measure of an oil company's health. If a company's reserve base is consistently stable or growing, then it's regarded as maintaining its assets as a base for growth. If the reserve base is consistently shrinking, a company can be thought to be cannibalizing itself.

For 2008, for instance, Shell says that it replaced just 95% of what it drilled. The year before, Chevron reported a replacement rate of just 10-15%. That attracted them much critical commentary.

And Exxon? It reported that it replaced 101% of its production in 2007, in addition to 103% in 2008. Yet its SEC report shows that its proven reserves actually dropped both years -- to 21.7 billion barrels from 22.1 billion barrels from 2006 to 2007; and, as mentioned above, on down to 21.1 billion barrels in 2008. The sands made the difference. Without the sands, Exxon's reserve replacement last year would have been about 27%.

The situation will change starting next year. The SEC is going to start allowing companies to combine the oil sands with other reserves. The decision came after oil companies argued strenuously that new technology makes unconventional oil equivalent to conventional reserves, so that now there is no reason not to permit companies to put them in the same basket.

Whatever the case, for the record below are the comparisons for the last nine years, including links for most of them to both the 10-Ks and the relevant news release or annual report.

The demand for oil has hit a short-term peak in the west and industry predictions of how long it will take to recover are getting longer, research from Greenpeace shows.

The Shifting Sands report pulls together oil demand forecasts from Opec and the International Energy Agency (IEA).

The report found both have cut their medium and long-term forecasts - partly due to the impact of the current recession, but also down to new government policies.

"In the longer term, the impact of two key policy instruments adopted in the US and EU are cited as gaining in influence. These are the US Energy Independence and Security Act and the EU Climate and Energy package. These policies, and the fact that there has been a degree of saturation in these markets, have led to the unanimous conclusion among these agencies that oil demand in the OECD has peaked."

The report adds that, although demand in countries such as China and India will continue to grow, "a global peak in oil demand may be within sight".

Greenpeace says this could put at risk the tens of billions of dollars major oil companies have invested in carbon-intensive tar sands projects.

The report also contains data showing how the oil majors have become increasingly reliant on tar sands, with Shell emerging as the most heavily involved.

• DATA: Revisions to oil demand forecasts

• DATA: Carbon intensity of oil and gas production by company

As the global economy recovers from the current downturn, there is a significant risk that resurgent energy demand will coincide with tight supply, vaulting oil prices higher again. Indeed, prices are already on the rise. Research by the McKinsey Global Institute (MGI), combining macroeconomic modeling with an understanding of industry dynamics, finds that unless business leaders and policymakers act decisively on both oil supply and demand, there is a risk that a second oil shock could follow economic recovery—indeed, one that could be lengthier than the second price spike that hit the world economy in the 1970s.

In the 1970s there was a silver lining to the twin shocks. For a long time after, energy demand remained subdued and the world saw a revolution in energy efficiency and substitution. Never again, policymakers vowed, would they allow soaring energy prices to take their economies hostage.

As it did in the 1970s, energy demand likely will surge once the world economy expands again. MGI expects demand to grow more than 2% annually between 2010 and 2015, nearly a full point faster than in the period from 2006 to 2010. At the same time, we face a supply picture that is less promising than it was in the 1970s.

Sudden withdrawals of supply led to both 1970s oil shocks—an OPEC embargo in the first, and the collapse of Iranian oil supply in the wake of Iran's revolution in the second. But in the aftermath of both episodes, supply grew rapidly, boosted by the fact that OPEC and non-OPEC countries were able to take advantage of the discovery of new fields.

The Trouble with Supply
Today, tight credit as well as uncertainty about oil price levels is compromising investment in new supply. Even after the credit crunch eases, producers could remain cautious in the face of strenuous efforts by markets such as the U.S. to lessen their dependence on imported oil, adding uncertainty to the demand outlook. In any case, even in a more benign investment environment, producers will find adding supply capacity more difficult than they did in the 1970s because of the challenge of producing oil from rapidly maturing oil fields and the difficulty of finding new low-cost oil fields.

One way to avoid imbalance in the oil market in the face of constrained supply is higher prices that dampen demand—but the transmission mechanism is much weaker today than it was in the 1970s due to energy subsidies and the lower energy intensity of many economies. In this context, fuel substitution and higher energy efficiency become vital checks on demand.

Here, too, the prospects appear less promising than they did in the 1970s. Back then, the twin oil shocks triggered improvements in energy efficiency and a substitution to different types of fuel, spearheaded by developed countries. These moves reined back demand for a long time. Such efforts continue today and are paying dividends—in the U.S., for example, both demand for fossil fuels and per capita energy consumption will fall between 2006 and 2020. Overall OECD fossil fuel demand will be almost flat.

But decisive action by developing regions is vital this time because they will account for 90% of energy demand growth between now and 2020. Even if the current recession proves to be deeper than the downturn in the 1970s, rapid growth in developing economies would boost global energy consumption significantly.

Reducing Global Demand
There are many actions that policymakers can take, even in the short term, to abate energy demand in parallel with measures to ensure supply, and these need not come at a high cost. We calculate that investments to increase energy productivity that offer investors a return of 10% or more could reduce global oil demand by as much as 10% by 2020, or between 6 million and 11 million barrels per day—the amount required to keep demand and supply in balance.

But although some developing countries have taken action on energy efficiency—China's fuel-efficiency standards, for instance—these efforts are not yet sufficiently broad-based or robust. Moreover, it is unlikely that developing countries will substitute fuels at the rate witnessed in the 1970s when developed economies were able to make "easy" switches. Today, for example, residual fuel oil comprises only 12% of total petroleum-products demand, and nearly half of the total is used for marine bunkers where no real substitute is available. Finally, one potential quick win—the removal of fuel subsidies, largely in the Middle East—could cut 2 million to 3 million barrels per day of demand in 2020 but is unlikely to materialize for political reasons.

It may already be too late to avert a second oil shock that could develop as early as 2010, depending on how quickly the global economy recovers. This is not to say that developing countries should take a laissez-faire stance toward energy demand. A vigorous emphasis on shifting to fuels that are potentially more plentiful offers additional significant demand-abatement potential. Action to boost energy productivity—the output achieved for a given amount of energy consumption—in industry and buildings could abate 6 million barrels per day. (With higher energy productivity in light vehicles, this would rise to 8 million barrels per day.)

In developed countries, removing trade barriers to sugar-cane ethanol, requiring all vehicles to be flex-fuel, and reversing the recent shift to diesel in passenger vehicles would be useful steps. Increasing the size limit for trucks could save between 0.5 and 1.0 million barrels per day. In the longer term, investing in nascent technologies—particularly electric vehicles and biofuels—will come into play. Investing in public-transportation infrastructure also will be important, particularly in developing countries that are building new capacity on a large scale.

Any and every policy to abate energy-demand growth will make a useful contribution—in the short term, mitigating the damage of a second shock on the world economy; and in the long term, laying the groundwork for a sustained period of balance in oil markets that will underpin the world's future prosperity.

Scott S. Nyquist is a director in McKinsey & Co.'s Houston office and a leader in McKinsey's global energy and materials practice.

The cost of pumping a barrel of oil out of the ground depends on a variety of factors, including the size and accesibility of the field.

Oil companies are often reluctant to give precise cost information.

The following provides estimates of the cost of running a field for OPEC members and other individual countries, obtained from traders and industry analysts.

It also gives the International Energy Agency's more general assessment of costs for the oil-producing regions of the world.

ESTIMATES BY COUNTRY
Saudi Arabian crude is the cheapest in the world to extract because of its location near the surface of the desert and the size of the fields, which allow economies of scale.

The operating cost (stripping out capital expenditure) of extracting a barrel in Saudi Arabia has been estimated to be around $1-$2, and the total cost (including capital expenditure) $4-$6 a barrel.

Extraction of Iraqi oil is in theory also very cheap, although there are political and security challenges.
Industry analysts estimated total costs at between $4-6, although they said some fields could be more expensive.

In the United Arab Emirates, operating and capital costs combined were estimated to be around $7 a barrel.

Oil extraction from mature and deep water offshore fields is much more expensive than from the accessible hydrocarbon territory of the Gulf.

In Nigeria, production in ultra-deep water fields can reach $30 a barrel compared with onshore costs of around $15, according to analysts.

In offshore Angola, it costs around $40 to produce one barrel of oil (operating and capital costs), traders told Reuters.

Operating and capital costs in Algeria, Iran, Libya, Oman and Qatar were all estimated to be around $10-15 a barrel.

In Kazakhstan, where reserves are big and largely unexploited, the cost to produce a barrel for medium-sized producers, such as Kazakh state oil company KazMunaiGas is around $15-18, and for Kazakhstan's largest operator Tengizchevroil, it is about $10-12, the Kazakh-British Chamber of Commerce said.

Analysts said these were operating costs, probably including transport, as it is expensive to move the oil to distant ports.

In Venezuela, where fields tend to be mature and small and it is difficult to make new discoveries, production costs were generally estimated at $20 a barrel (operating and capital costs).

Those figures do not include the more expensive Orinoco oil from the country's sand deposits.

One analyst said the extraction of one barrel of Orinoco was around $30 (operating and capital costs).

Ecuador, where fields are also small and the distance to ports add to costs, analysts pegged extraction costs at $20 a barrel. 

In the mature British North Sea, where the remaining oil is difficult to access, the industry body Oil & Gas UK said the break-even cost was around $50 a barrel. One analyst said operating and capital costs were $30-40 a barrel. 

The International Energy Agency (IEA) -- in its latest November 2008 world energy outlook -- gave the following estimates for the all-in costs of producing oil from various types of hydrocarbons in different parts of the world:

Source: International Energy Agency World Energy Outlook 2008 Compiled by Martina Fuchs, Christopher Johnson, Karen Norton, Joe Brock and Barbara Lewis, Editing by James Jukwey

 International oil companies expressed unanimous disapproval Tuesday of proposed legislation to revamp the oil and gas industry in Nigeria.

At a senate hearing on the bill, executives of U.S. producers Chevron Corp. and Exxon Mobil Corp., Italy's Eni SpA, as well as Anglo-Dutch company Royal Dutch Shell PLC said the bill would cost the firms billions of dollars and drastically diminish foreign investment in Nigeria's oil industry.

Government officials didn't respond to requests to comment on the hearing.

Nigeria's export revenue comes almost entirely from oil. The bill is the centerpiece of changes initiated by President Umaru Yar'Adua after his election in 2007. It is intended to revitalize an industry that has seen production of more than one million barrels a day of oil shut down amid attacks on pipelines, deteriorating infrastructure and mounting bureaucratic hurdles.

The bill, which has been in the works for almost a decade, still isn't in its final iteration. However, the fundamental changes it proposes include imposing higher royalties for every barrel of oil produced as well as higher tax rates on companies operating in Nigeria. The bill also would allow the government to renegotiate existing deep-water contracts and repossess unexplored fields already contracted to companies.

Oil company officials say for months they tried to discuss concerns about the bill with government officials, but were granted only ceremonial meetings that yielded no substantive discussions.

In an interview earlier this year with The Wall Street Journal, Minister of Petroleum Rilwanu Lukman said the Nigerian government had consulted fully with oil companies.

"Of course we expect reservations [from the oil companies] because it's a new situation and things have been done differently over the past 50 years," said Mr. Lukman, a former head of the Organization of Petroleum Exporting Companies who was brought out of retirement by President Yar'Adua to draft the legislation. "Some of the provisions in the old law are archaic, out of date. It's only fair, and they know it, that some of these things should be rediscussed and renegotiated."

"Naturally they will be anxious to make sure that that they did not lose in the process," Mr. Lukman said. "Our intention is not to make them lose. We want to create a win-win situation for everybody. If our new terms and conditions are too harsh it doesn't help us. We don't think we put anything in the bill that will bother them."

At Tuesday's public hearing, company officials aired their concerns before lawmakers.

Chevron's managing director in Nigeria, Andrew Fathrop, said deep-water oil fields in Nigeria would fail under the proposed legislation due to ill-advised fiscal terms. He also said the proposed terms would "give the government a bigger share of a smaller pie."

Chevron is investing $3 billion a year in existing and new oil and gas projects in Nigeria, Mr. Fathrop said.

Exxon Mobil's managing director in Nigeria, Mark Ward, said the legislation would threaten the company's plans to invest $60 billion in Nigeria over the next several years, and would hamper growth and impede investment by Exxon Mobil and the entire industry.

Mr. Ward said Exxon Mobil supports industry reform but the current bill is flawed.

All future projects would become "uneconomic," under the new bill, Mr. Ward said, and "companies will be unwilling to invest in Nigeria."

Mutiu Sunmonu, managing director of Shell Petroleum Development Company of Nigeria, said proposed fiscal and tax changes in the bill make the legislation "not viable."

"They must think it will still be profitable to invest in the oil and gas industry once this bill is passed," said Basil Omiyi, head of Shell Operations in Nigeria and chairman of the Oil Producers Trade Services, which represents foreign oil firms in Nigeria. "We think otherwise."

An Eni official representing the company's Nigeria managing director said if the bill becomes law, the company wouldn't meet its goal of increasing production by 70,000 barrels a day in Nigeria by 2012.

"The bill will not work," the official told the Senate panel. "It is putting our future production at risk."

Eni's 2008 oil and gas production was 122,000 barrels of oil equivalent a day.

Nigeria has lost hundreds of billions of dollars in oil revenue over the past four decades to corruption, weak infrastructure and militant attacks in the Niger Delta.

Shell, for example, is currently producing less than 30% of its total onshore capacity in Nigeria due to a lack of funding and insecurity in the Niger Delta, Mr. Sunmonu said, adding that Nigeria had lost $47 billion in oil revenue since 2006 due to the company's production shut-downs.

Many analysts say they believe a vote on the petroleum-industry bill is still months off.

The Iraqi cabinet Tuesday approved a law providing for the establishment of a national oil company for the first time in decades, a government spokesman said.

Ali al-Dabbagh said that the cabinet submitted the new draft law to the country's parliament for final approval. He didn't provide any details about the content of the new law.

The Iraqi National Oil Co., or INOC, was set up in 1964 but ousted leader Saddam Hussein scrapped the company in late 1987.

The reinstated national oil company would act as the parent of the existing three major Iraqi oil operators - the South Oil Co., Iraq's largest petroleum company in Basra; North Oil Co. in Kirkuk; and Missan Oil Co. in Ammarh in southern Iraq.

Thamir al-Ghadhban, an energy adviser to Prime Minister Nouri al-Maliki, confirmed that the law was passed by the cabinet Tuesday and would be sent to the parliament for approval.

Ghadhban told Dow Jones Newswires that the new draft law was prepared by a committee set up by the cabinet last year, which consisted of the Minister of State for Parliamentary Affairs Safaaeddine al-Safi, himself and other senior officials.

He said the law stipulates that the new company consist of a board of directors headed by a chairman with ministerial powers. "We have prepared a modern law that gives the new company wide powers," Ghadhban said.

The new legislation won't become a law until it is approved by the parliament, which is expected to begin a six-week recess at the end of this week.

Previous legislation for a national oil company, which was included in an overall hydrocarbons law, has been long delayed by a bitter dispute among the parliament's Shiite, Sunni and Kurdish factions over the sharing of Iraq's oil wealth.

Unlike that legislation, the new draft law avoids naming the fields that the company would operate in order to avoid disputes among the country's political parties and lawmakers. Kurdish officials had rejected the earlier legislation, fearing it gave the national oil company wider powers to run most of the country's oil fields, including those inside Iraq's northern region of Kurdistan.

"In the new draft law we didn't mention the fields that the new company would run," Ghadhban said. "The fields to be operated by the company would be determined by a federal oil and gas council yet to be established," he said.

The previous law stated that the INOC would have authority to conclude service and management contracts with international oil companies to improve oil recovery from producing fields. It isn't known if that provision was retained in the new law.

Iraq sits atop the world's third-largest proven crude reserves after Saudi Arabia and Iran, but is desperate for oil revenue to rebuild its war-shattered economy, especially with global prices down.

Iraq's pre-U.S.-led-invasion production ceiling was about 3 million barrels a day, but it now produces only 2.4 million barrels a day, of which 1.8 million is for export, according to Oil Ministry figures.

Crucial to improving Iraq's broken infrastructure and returning production to pre-2003 levels are security guarantees that major international oil companies' operations won't be disrupted by sectarian power struggles.

Last month Iraq held its first licensing auction, offering six oil and two gas fields to international companies. Only one, the giant Rumaila field in southern Iraq, was awarded to an alliance of BP PLC (BP) and China National Petroleum Corp. The country is planning to hold a second licensing auction by the end of this year, covering 10 groups of oil and gas fields.

Hedge-fund managers, oil traders and oil companies will meet with Britain’s Financial Services Authority next week to examine the efficiency of commodities regulation.

The private meeting on Aug. 5 will discuss whether any changes need to be made to FSA regulations. The meeting follows a hearing by the U.S. Commodity and Futures Trading Commission on whether to impose limits on oil trades -- something the FSA doesn’t do.

The FSA, the Treasury and oil industry representatives from banks, producers, brokers and hedge funds will discuss “market efficiency and transparency as part of our regular process of engagement with market participants in these markets,” the regulator said in an e-mailed statement today.

Transatlantic differences in commodity-trading regulations have been highlighted by both U.S. and U.K. lawmakers in the last year. FSA Chairman Adair Turner told a parliamentary committee last July that supply and demand, not speculation, was responsible for then-record oil prices. That contradicted some U.S. lawmakers. A former CFTC official said last year the FSA’s lack of limits led to excessive speculation.

PVM Oil Futures Ltd., a London-based unit of the world’s biggest broker of over-the-counter crude oil derivatives, said earlier this month that a rogue trader lost almost $10 million. The trades may have caused London oil prices to jump almost $2 a barrel to an eight-month high, according to exchange data.

U.K. Prime Minister Gordon Brown railed against volatility in oil at a July 6 press conference with French President Nicolas Sarkozy. Crude rose to more than $72 a barrel on the New York Mercantile Exchange last month after selling for less than $34 in February. It traded as high as $64.06 a barrel today in New York.

Oil futures are also bought and sold on the London-based ICE Futures Europe exchange, including North Sea Brent crude.

CFTC Chairman Gary Gensler, a former Goldman Sachs executive, said July 28 that the agency should “seriously consider” setting strict federal position limits to curb speculation in commodity markets.

Competition between the world’s two top energy exchanges on Tuesday spilled into the regulatory arena in a vital US hearing on limiting the size of speculators’ market footprint.

The Commodity Futures Trading Commission, the US regulator, is considering how to curb speculators’ influence in energy markets after last year’s rise in oil prices brought accusations that a bubble had been created.

Concessions to the regulator were agreed on Tuesday. CME Group, owner of the New York Mercantile Exchange, offered for the first time to put “hard” limits on certain kinds of energy speculators’ positions, while arch-rival IntercontinentalExchange said the CFTC regulator should have power over position limits.

Gary Gensler, the CFTC chairman, praised the chief executives of both companies for making “tangible, real steps” towards addressing public concerns.

However, both exchanges also included caveats that could dilute the strength of the CFTC’s proposals.

Jeffrey Sprecher, chief executive of ICE, said stiff limits should apply only to those commodity contracts that were about to be delivered, not those pegged for delivery months or years into the future.

Craig Donohue, chief executive of the CME, said Wall Street banks and investors in commodity indices should remain eligible for exemptions from position limits.

Existing trading limits in most US energy futures are mostly used to alert exchange operators to the possibility of unwieldy positions. Mr Gensler said in US crude, heating oil, gasoline and natural gas futures markets, 69 parties exceeded these levels over the past year.

The bulk of benchmark West Texas Intermediate crude futures is traded on Nymex.

Intercontinental’s UK-based ICE Futures Europe exchange offers a lookalike WTI contract with about 15 per cent of global trading.

Under an agreement with the regulators last year, ICE follows trading limits in WTI that are set by Nymex.

The CFTC proposes to tighten these trading limits aggressively in a crack-down on “excessive speculation”, applying them both to oil traded on exchanges and in over-the-counter markets.

Mr Sprecher said that the CFTC, not Nymex, should set and manage any new position limits.

Letting one large exchange administer position limits across its market and other venues would be “rife with potential conflicts of interest”, said Mr Sprecher.

Mr Donohue, said that the CME was ready to adopt hard limits on energy futures but insisted that the exchange operator was best suited to set and manage them.

Crude oil prices dropped by more than $1 a barrel on Tuesday as the dollar strengthened. Nymex September West Texas Intermediate fell $1.15 to $67.23 a barrel, while ICE September Brent retreated $0.93 to $69.88 a barrel.

Gold sank below $940, falling 1.7 per cent to $936 a troy ounce as the dollar recovered.

Traders said that bullion had been driven mainly by fluctuations in the dollar as interest from jewellery makers and inflows into exchange-traded funds remained quiet.

Fuel oil, the waste left after making gasoline and diesel, is becoming as valuable as crude for the first time in six years.

Prices have doubled this year to the equivalent of $66.47 a barrel in Singapore, approaching the $70.30 of Arab Light crude, which has been more expensive since July 2003. Fuel oil output at refineries in the developed world fell 18 percent in April from a year earlier, the International Energy Agency estimates. China’s imports climbed 46 percent in June from a year earlier, Barclays Capital said in a July 22 report.

The increase is squeezing Hamilton, Bermuda-based Frontline Ltd. and A.P. Moeller-Maersk A/S, the world’s biggest shipping companies, while rewarding Exxon Mobil Corp. and Reliance Industries Ltd., owners of the largest refineries in the U.S. and Asia. The shortage is growing as the oil industry builds new plants that obtain more gasoline and diesel from each barrel.

“I don’t expect the situation to change any time soon” in fuel oil, said Christian Laurenborg, a Copenhagen-based trader for Maersk, the operator of more than 500 container ships. “We are suffering a bit.”

Frontline, the world’s biggest operator of oil tankers, has ordered captains to slow their ships to conserve fuel, said Chief Executive Officer Jens Martin Jensen. The average vessel consumes about $40,000 of the fuel, known as bunker, a day.

“With bunker prices going up, it has a strain on the bottom line,” Jensen said in a telephone interview. “We are slow steaming, it makes sense to slow down.”

Refinery Leftovers

Fuel oil is what remains after propane, jet fuel, gasoline and diesel are distilled from crude. Refiners can build plants that take that residue and process it again to strip out more fuels for cars, trucks, trains and airplanes.

Every 42-gallon barrel of Arab Light crude yields 19 gallons of fuel oil when run through a typical refinery, according to New York-based Energy Intelligence Group. Plants equipped with so-called cokers and hydrocracking units produce almost no fuel oil.

Fuel oil cost $10.15 a barrel less on average than crude during the past five years. The discount to Persian Gulf benchmark Dubai oil narrowed to $1.56 a barrel July 24 from $30.46 in June 2008, according to data compiled by Bloomberg.

The price in Singapore may exceed crude within three months, said Harry Tchilinguirian, a senior oil markets analyst at BNP Paribas SA, France’s largest bank.

Fuel oil may surpass crude “for quite some time, six months is possible,” JPMorgan Chase & Co. vice president of energy strategy Vima Jayabalan said in a phone interview from Singapore.

World War II

Refineries are limiting production as the first global recession since World War II curbs oil consumption by 2.8 percent this year, the fastest decline since the early 1980s, according to the IEA. Crude oil dropped 78 percent to a low of $32.40 a barrel on Dec. 19 in New York from a record $147.27 on July 11, 2008.

The Organization for Petroleum Exporting Countries agreed since October to reduce output by 4.2 million barrels a day, or 14 percent, to support prices. Members cut sales of the lowest- quality crudes, which cost the least and yield the most fuel oil, Asian refinery officials said.

Saudi Arabian Oil Co., OPEC’s biggest producer, will supply 20 percent less than contracted volumes to Asian refiners in August, with the deepest cuts in heavy and medium crudes, according to a survey of refinery officials on July 9.

SK Energy, Nippon

SK Energy Corp., South Korea’s biggest refiner, ran its refineries at 72 percent of capacity in the second quarter, and the country’s fuel oil production in May was down 46 percent from a year ago, according to the Joint Oil Data Initiative, a data collection agency for international groups including OPEC and the IEA. Nippon Oil Corp., Japan’s largest processor, planned to cut output 24 percent this month from July 2008 levels, Director Masahito Nakamura said on June 29.

Across Asia, 3 million barrels of daily refinery capacity has been idled, said John Vautrain, a senior vice president at Purvin & Gertz Inc., a consulting firm in Singapore. “When that kind of capacity cuts back, it has an outsized impact on fuel oil supply,” he said.

Bunker inventories in Singapore, Asia’s biggest trading center and fueling port, fell last week to 14.1 million barrels, 19 percent below the two-year average, according to International Enterprise, a government agency. In the Amsterdam, Rotterdam and Antwerp region, Europe’s oil-trading hub, inventories dropped 24 percent in the past year to 567,000 metric tons, according to PJK International BV in Oosterhout, the Netherlands.

Hydrocrackers, Cokers

Exxon and Reliance can increase production of gasoline and diesel by putting fuel oil through hydrocrackers, catalytic crackers and cokers. A refinery with these units can make $1.38 from each barrel of Dubai crude, compared with the 91 cent-a- barrel profit from a plant without them, data compiled by Bloomberg show.

BNP Paribas estimates that refinery units capable of breaking down an extra 1.4 million barrels of fuel oil are being built in Asia that will come on line by the end of 2011.

Refiners “think fuel oil is low so they are cracking more,” said Simon Neo, a deputy managing director at Singapore- based Equatorial Marine Fuels. “This means higher costs for the marine industry.”

The fuel expense of running the biggest oil tankers is $40,280 a day, based on the $424 a metric ton costs in Singapore. That’s more than three times the $12,270 that London-based Drewry Shipping Consultants Ltd. estimates for paying crew, insurance, repairs and related operating expenses.

‘Really Hurting’

“It’s really hurting” ship owners, said Parul Bhambri, a Singapore-based analyst at Drewry.

Maersk said May 12 that falling demand for freight hobbled its ability to pass on fuel costs to customers in the first quarter, when its shipping line lost $559 million after taxes, compared with an $80 million profit a year earlier. The shares are down 40 percent in the past year in Copenhagen trading.

Unlike most shipping lines, Maersk owns bunker-fuel storage facilities and trades cargoes, protecting the company’s profits as prices rise, Laurenborg said. It is also has crude oil production, which acts as a further hedge.

Frontline shares fell 59 percent in Oslo during the past 12 months. The company said in May it canceled one of every three new ships on order and that net income in the first quarter plunged 65 percent to $76.6 million.

Output Incentive

As fuel oil prices climb, the incentive to boost production increases, said Vautrain at Purvin & Gertz.

“If fuel oil rose above crude, then that implies you start getting some decent profitability for simple refining,” he said. “There are too many of those units sitting on the sidelines and they can come back at any time.”

Fuel oil production is also falling as Saudi Arabia and the rest of OPEC cut output of the lowest-quality crudes. Saudi Arabia’s Arab Heavy yields 22 gallons of fuel oil per barrel, three more than what comes from Arab Light.

Saudi Arabia has reduced production this year by about 400,000 barrels a day, or 4.5 percent, to about 8 million barrels a day, according to data compiled by Bloomberg.

“There are availability issues with fuel oil,” said Amrita Sen, an analyst at Barclays Capital in London. “The Chinese are switching to products with a higher margin like diesel and gasoline. Products like fuel oil are suffering.”

China’s bunker output dropped 10 percent to 375,000 barrels a day in May from a year ago, according to the Joint Oil Data Initiative.

Asia’s appetite will increase over the next five years, according to the IEA. Supplies in the region are expected to be 1.2 million barrels a day below demand by 2014, the group said.

“You have to consider fuel oil up until now a byproduct,” said BNP’s Tchilinguirian. “With the additions that we see to existing refineries of conversion capacity, and the new refineries coming on, refiners are aiming to reduce that.”

It was meant to be the world's first demonstration of a technology that could help save the planet from global warming – a project intended to capture emissions from a coal-fired power station and bury them safely underground.

But the German carbon capture plan has ended with CO2 being pumped directly into the atmosphere, following local opposition at it being stored underground.

The scheme appears a victim of "numbyism" – not under my backyard.

Opposition to the carbon capture plan has contributed to a growing public backlash against renewable energy projects, raising fears that Europe will struggle to meet its low-carbon commitments. Last week, the Danish firm Vestas blamed British "nimbies" opposing wind farms for its decision to close its turbine factory on the Isle of Wight.

Many countries continue to use coal for generating power as it is the cheapest and most readily available fuel in the world. It will probably power the development of China and India. But coal is also seen as the dirtiest fuel. So, Vattenfall's Schwarze Pumpe project in Spremberg, northern Germany, launched in a blaze of publicity last September, was a beacon of hope, the first scheme to link the three key stages of trapping, transporting and burying the greenhouse gases.

The Swedish company, however, surprised a recent conference when it admitted that the €70m (£60.3m) project was venting the CO2 straight into the atmosphere. "It was supposed to begin injecting by March or April of this year but we don't have a permit. This is a result of the local public having questions about the safety of the project," said Staffan Gortz, head of carbon capture and storage communication at Vattenfall. He said he did not expect to get a permit before next spring: "People are very, very sceptical."

The spread of localised resistance is a force that some fear could sink Europe's attempts to build 10 to 12 demonstration projects for carbon capture and storage (CCS) by 2015. The plan had been to transport up to 100,000 tonnes of carbon dioxide from the power plant each year and inject it into depleted gas reservoirs at a giant gasfield near the Polish border.

Scientists maintain that public safety fears are groundless: the consequences of escaping CO2 would be to the climate, not to public health. Many big environmental groups support CCS, both off and onshore, as a necessary evil in the battle against climate change.

But Jim Footner, a Greenpeace climate campaigner, said the German protests were "a stark warning to those that think CCS is an easy solution to the huge climate problems of coal-fired power stations".

The first wake-up call came in March, when a Dutch council objected to Shell's plans to store CO2 in depleted gas fields under the town of Barendrecht, near Rotterdam.

This was despite a successful environmental impact assessment and the enthusiastic backing of the Dutch government, which, in September, must decide whether to give Shell the green light, despite the council's opposition.

Wim van de Wiel, a Shell spokesman, said: "For Shell the only suitable location for the tender was, and still is, Barendrecht, because of the safety and the depleted status of the [gas] field."

Jeff Chapman, chief executive of the the Carbon Capture & Storage Association, said Vattenfall should study the example of Total, which made great efforts to engage the local community when it launched its CCS pilot project in Lacq, southern France.

Stuart Haszeldine, a CCS expert at the University of Edinburgh, warned of the danger of opposition towards CCS snowballing into a "bandwagon of negativity" if too many early projects were rejected. "Once you've screwed up one or two of them, people are going to think 'if they rejected this in Barendrecht, there must be a reason'," he said.

In the UK, CCS is one of the four "pillars" of the government's decarbonisation strategy. A spokeswoman for the Department of Energy and Climate Change said: "We plan to store the CO2 from CCS plants offshore, for example in depleted oil and gas fields in the North Sea. We are one of the first countries to have legislation … to regulate environmental and safety risks."

Like a giant in winter, Schwarze Pumpe, a 160-metre-tall power plant near Berlin, breathes out a steady fog of steam and carbon dioxide, making a modest but visible contribution to global warming.

Yet in the shadow of that hulking facility, engineers from Vattenfall, the Swedish energy company, are testing a new technology that promises power without pollution.

An engineer at a German plant of Vattenfall, a Swedish energy company

Pipe dreams: Swedish energy company Vattenfall is testing a new technology in this plant near Berlin that traps carbon dioxide produced by coal-fired power plants

Known as carbon capture and storage (CCS), it involves a complex tangle of pipes, valves and filters that burn coal and lignite in such a way that the carbon-dioxide exhaust can be separated in a highly purified form. That gas can then be piped away for use in soft-drinks factories and fire extinguishers, or buried underground.

The small-scale, 30-megawatt test plant has so far captured about 1,000 tonnes of carbon dioxide since it began operation last September. Vattenfall is hoping to build a much larger 400MW facility. “The technology will function. I’m sure. I’m absolutely sure,” said Reinhardt Hassa, the chief executive of Vattenfall Europe Generation, exuding an engineer’s confidence.

But if capturing carbon is one thing, deploying a wide-scale CCS programme that is cost-effective and commercially viable is another. Both the challenges and possibilities of CCS are coming into greater focus as world leaders prepare to meet in Copenhagen in December to discuss a global climate-change treaty.

They are already apparent in the European Union, which has made CCS a central part of its effort to contain global warming. To succeed, companies and member states will have to bridge a multi-billion euro funding gap, work out technological kinks, draft new regulations to govern the transport and storage of carbon dioxide and win acceptance from a public worried about safety.

They will have to do all this quickly: the EU is hoping to have a dozen or so demonstration plants running by 2015 so that a variety of CCS technologies can be tested and the best made commercially available by 2020. That means construction must begin in little more than a year.

“It’s the urgency that creates the scale of the challenge,” said Dr Graeme Sweeney, a Shell executive vice-president who chairs the Zero Emissions Platform (ZEP), a CCS advocacy group that includes companies, scientists and non-government organisations.

The pay-off could be vast: the International Energy Agency has estimated CCS could account for one-fifth of the emissions reductions required in the energy and industrial sectors by 2050 to avoid the worst effects of global warming. Achieving those reductions without CCS would cost 70 per cent more, the IEA found.

For companies such as Alstom, Siemens, Shell and Hitachi, CCS also represents a lucrative green industry of the near future. “Will this be a multi-billion dollar industry if it’s brought to commercialisation? Absolutely,” said Dr Sweeney.

But the months ahead may determine whether CCS emerges as an effective tool in the struggle to halt climate change or a costly disappointment.

“It might be the single most effective – but also controversial – contribution to fighting global warming,” said Niels Peter Christensen, the chief geologist at Vattenfall.

That controversy derives in large part from a fundamental argument embraced by CCS supporters: that even with advances in wind and solar technology, coal and other fossil fuels will power the world for decades to come – particularly with the rapid industrialisation of China and India.

That might cheer energy companies, but environmentalists are more conflicted. Some, such as Greenpeace, remain wary of CCS and its corporate patrons; others are now reluctant supporters.

“It’s clear that the energy system as a whole has to undergo a revolution to become low-carbon or zero-carbon by 2050. We don’t think that can be done in time with only efficiency measures or renewables,” said Mark Johnston, an analyst at WWF, explaining its decision to join the ZEP.

But developing CCS will be expensive. The added cost to build and operate each CCS demo plant could exceed €1bn ($1.2bn, £862m) apiece – far more than the companies are willing to shoulder on their own.

Finding money for the demo plants will be crucial because CCS still needs work. With current technology, it costs about €80 to €100 per tonne to capture carbon dioxide, according to Dr Sweeney. He estimates engineers will have to drive that number below $50 per tonne by 2020 to make the technology viable.

“These are real challenges, which need to be resolved by the demonstration programme,” Dr Sweeney said. “But is it do-able? Yes, I believe it’s do-able.”

One cause for optimism is that current CCS facilities have been patched together with components largely designed for other applications. Oil companies, for example, have been injecting carbon dioxide into fading wells for decades in order to enhance recovery. Efficiency should improve with increased testing on power plants and the possibility of designing new CCS plants from scratch.

Inevitably, success will also depend on the future price of carbon in the EU’s emissions trading system. It is currently hovering at around €15 per tonne, pushed down by the economic slowdown. It will have to recover to €30 per tonne to make CCS economical for companies and utilities, according to Dr Nicolas Vortmeyer, chief executive of Siemens Energy Fossil Power Generation.

“These two factors will decide whether or not this succeeds,” he said, referring to the efficiency of CCS-fitted power plants and the price of carbon.

Even if CCS backers can solve the technical and financial puzzles, they may still face a more daunting challenge: winning public acceptance. In order to build demo plants, storage sites and thousands of kilometres of pipelines across Europe, they will first have to persuade the public that the technology is not only necessary but also safe.

That is proving more challenging than many engineers anticipated. Germany recently put off legislation to govern CCS storage and transport due to concerns from regional officials. Because of regulatory delays, Vattenfall has so far been unable to pump into the ground any of the 1,000 tonnes of carbon dioxide its test plant has captured.

“I think it has the potential to be quite difficult,” said Joan McNaughton, a senior energy adviser for the UK government before she joined Alstom.

But, if Mr Hassa is correct, companies, governments and the public may have no choice but to find a way to make CCS work. “We will use fossil fuels in the coming years – not just 10 years, but 50, 60, maybe 70 years,” Mr Hassa said. “We can’t do it without CCS.”

U.K. utilities may need to mothball power plants and cut investment plans as the country faces the biggest electricity glut in almost 20 years.

National Grid Plc, the manager of Britain’s power network, predicts this year’s 6 percent drop in consumption may leave some plants unneeded to meet demand. The oversupply will increase because the country’s six biggest energy suppliers, led by Centrica Plc and Scottish & Southern Energy Plc, are developing more natural gas-fueled stations.

From Didcot in Oxfordshire to Longannet in Scotland, power generators are shuttered. Profits from gas-fed plants may fall by 30 percent in the winter heating season that starts in October 2010, compared with the same period this year, futures markets show. The result will be cheaper energy for U.K. consumers and an earnings squeeze for utilities including E.ON AG and RWE AG.

“What a difference 12 months make,” said Nick Campbell, an energy analyst at Lancashire, England-based Inenco Group Ltd., which buys power for companies including Marks & Spencer Group Plc. “At the start of last winter everyone was scrambling to find generation from anywhere and talking about blackouts. Now we’re up to our ears in spare capacity.”

Utilities will complete generators approved before the economy went into recession, adding capacity this year at the fastest pace in almost a decade. Scottish & Southern is testing its Marchwood gas-fueled plant and ConocoPhillips and Centrica plan to fire up new gas-fed stations. Wind turbines are also being built on government plans to cut carbon-dioxide emissions.

Winter Power

Electricity for delivery this winter fell 1 percent to 41.40 pounds ($67.84) a megawatt-hour as of 5 p.m. in London today, according to broker data compiled by Bloomberg. It’s fallen 28 percent this year. Working day-ahead baseload power traded near a two-year low at 30.65 pounds a megawatt-hour today as the margin of spare production capacity widened to 31 percent of peak demand, the most on a working day so far this year.

So-called spark spreads show generators may earn 5.40 pounds a megawatt-hour of electricity produced in the six-month winter contract period starting October 2010.

The drop in power prices has cut the earnings outlook for generators including Drax Group Plc and Scottish & Southern. Utilities is the worst-performing industry group this year in Europe’s Dow Jones STOXX Index.

Drax Coal

Drax, the owner of western Europe’s biggest coal plant, fell to a record in London trading after selling shares to ensure it kept its investment-grade credit rating. Scottish and Southern is under review at Moody’s Investors Service Ltd. for possible downgrade because its “ambitious” spending and dividend-growth policies may reduce flexibility.

Spare generation capacity is headed toward 40 percent, compared with less than 30 percent in all bar one year since 1990, according to National Grid forecasts. Electricity demand may not reach pre-recession levels for 10 years, the London- based company said.

“We’ve got what looks like some very healthy margin developments,” Chris Train, National Grid’s director for network operations, said of the excess above peak demand.

Already this year some of the country’s largest coal-fed power units have been idled for more than three months.

“With current wide margins in the market, it is difficult to see why the owners would bring plants back,” a report published last month by Eclipse Energy AS said. The Oslo-based company provides price forecasts and predicts 2,000 megawatts of capacity will be mothballed this winter.

Delay Plans

There’s a “danger” the utilities and government will treat slowing demand as a reason to delay plans to increase energy efficiency and build renewable energy plants, said Tony Ward, a partner in Ernst & Young LLP’s power and utilities team.

He predicts utilities will need to ax 35 billion pounds of investment plans because of the slowdown in energy demand. That will reduce expenditure to 199 billion pounds through 2025, the accountant said in a report published July 21.

The oversupply may linger for six years because the slump in energy use is prolonging the lives of 12,000 megawatts of capacity that is allowed to run for a maximum 20,000 hours, or about 29 percent of the time, between 2008 and 2015. By spacing out their operations rather than using up the hours immediately, producers are leaving the market saturated for longer.

Coal Cap

Use of coal-fed generators with a cap on their remaining operations dropped 30 percent in the five months through May compared with the year-earlier period, according to the England and Wales Environment Agency.

The U.K. Nuclear Decommissioning Authority is also extending the operating life of its oldest atomic reactors, and EDF’s British Energy division got approval on July 1 to extend the use of its Hartlepool and Heysham-1 plants for another 10 years.

All the U.K.’s six biggest energy retailers cut their rates for end-users this year after the drop in wholesale rates. Prices for households tend to trail the wholesale market because utilities buy supplies in advance to fix their costs.

Europe's largest onshore windfarm project has been thrown in severe doubt after the RSPB and official government agencies lodged formal objections to the 150-turbine plan, it emerged today.

The setback adds to the problems facing the government's ambition to install 10,000 new turbines across the UK by 2020 as part of its plan to cut the carbon emissions causing climate change.

The proposed 550MW windfarm, sprawling across the centre of Shetland's main island, would add almost 20% to existing onshore wind capacity. But the objectors say the plans could seriously damage breeding sites for endangered birds, including a rare wader, the whimbrel, which was unexpectedly discovered by the windfarm developer's own environmental survey teams. Other species at risk include the red throated diver, golden plover and merlin.

The RSPB heavily criticised the proposal from Viking Energy after initially indicating it could support the scheme. The RSPB also claims now that installation of the turbines could release significant carbon dioxide from the peat bogs affected, undermining the turbines' potential to combat global warming.

The group's fears have been endorsed by the government's official conservation advisers, Scottish Natural Heritage, and SNH has also objected to the "magnitude" of the scheme, claiming it could kill many of these birds through collisions with the 145-metre-high structures.

The Scottish Environment Protection Agency (Sepa), which oversees pollution and waste laws in Scotland, has also formally objected, making it inevitable the scheme will now go to a full public inquiry and intensifying pressure on the developers to alter the scale of the project.

In a detailed critique of the proposal, Sepa has asked Viking Energy to significantly rethink its plans to cut out and dump up to 1m cubic metres of peat during construction, and asked ministers to impose tough conditions to protect local water quality and freshwater species .

Bill Manson, a director of Viking Energy, the community-owned company which is collaborating with Scottish and Southern Energy on the scheme, said it would be prepared to negotiate. "I believe there's a dialogue to be had, which will assuage their fears, I hope," he said.

A Scottish government consultation on the £800m scheme closed yesterday, with more than 3,600 of Shetland's 21,000 islanders signing a petition calling for the project to be scrapped.

The Shetland Amenity Trust, a local heritage and archaeological charity, and one of Scotland's major countryside access organisations, the John Muir Trust, have also objected, arguing that the proposal would have a "hugely damaging detrimental impact" on the treeless, hilly landscape.

The dispute has highlighted the conflicts arising over the siting of major windfarms on land, between the need to exploit the most windy locations and the desire to preserve the rural environment.

The government wants to have an additional 6,000 onshore and 4,000 offshore wind turbines installed by 2020 to meet its legally binding target of generating 15% of all energy from renewable sources . There are currently about 2,400 turbines.

Ed Milliband, the energy and climate change secretary, has set out an ambitious plan to transform the UK to a low-carbon economy.

But the plans to change the planning system to make windfarm approvals quicker and give priority to renewable projects in granting national grid connections prompted significant criticism on the siting and cost of windfarms.

Within a week, the newly formed National Association of Wind Action Groups pledged to campaign against the harmful impact of wind turbine developments on communities and landscapes. Another blow came from the decision of Danish wind turbine manufacturer Vestas to close the UK's only blade manufacturing plant on the Isle of Wight. The company said the UK wind market was not growing fast enough and that projects had been slowed down by planning objections.

Existing windfarms have 3,000MW of capacity, but another 9,600MW is in the planning process. A further 6,000MW has planning permission but no funding and on Monday the government announced a £1bn loan package to try to fill that funding gap. It argues that the UK has the largest potential for wind power in Europe and already has more offshore wind installed than any other country.

Miliband has said that climate change poses a greater threat to landscapes than windfarms and that opposing them should be "socially unacceptable".

Scotland is already home to more than half the UK's onshore wind capacity and Shetland is a key location. The islands reputedly experience the highest and most consistent wind speeds of any comparable place on earth. One small turbine at Lerwick, known as Betsy, is believed to be the world's most productive, reaching 59% of its potential output.

The Viking scheme, if approved by ministers, would alone generate a fifth of Scotland's domestic electricity needs and earn up to £37m a year in profits for Shetland. Manson said yesterday that the scheme had to be large-scale for the energy regulator and National Grid to agree to lay the £300m interconnector cable that would carry the electricity to the mainland. A scheme even half its current size would not be commercially viable.

But opponents claim that the scheme is far too large and that, with a further 62 miles of access roads, it would significantly affect a fifth of the main island's desolate interior and industrialise the landscape.

"We can't simply build our way out of climate change," said John Hutchison, chairman of the John Muir Trust.

"It is both cheaper and less destructive to reduce energy need and waste, rather than cover the wild landscapes that define Scotland and its people with wind turbines."

Last night I went to hear Ed Miliband, the secretary of state for energy and climate change, speak in Oxford Town Hall. About 800 people turned up, a lot of them determined to challenge him.

It started badly. His spin doctor tried to get the organisers to take down the polite banners people were holding in support of the workers at the Vestas wind turbine factory on the Isle of Wight. I asked her why she wanted them removed. She replied that it was a public meeting, not a protest. Why couldn't it be both?

"It's just my opinion; I don't like them."

The banners stayed up.

Though I didn't agree with everything he said, and though he's no orator, Miliband was good. He never tried to duck a question. He listened, answered directly, never insulted the intelligence of the audience: he appeared, in other words, to be the opposite of a New Labour politician. If the government were composed of people like him and Hilary Benn, I would vote Labour again. But what poor company they keep!

He began by responding to one of the Vestas workers (there were several in the hall). He said that he had asked Vestas whether its decision to move its plant to the US "was about money. They said no. Would [government] money make a difference? No." It was about the credit crunch and the planning system. He was trying to address both problems: by putting £1bn into wind developments and by changing the planning laws.

"But the biggest thing we can do for people like David [the Vestas worker] and his colleagues is to change people's minds about onshore wind. … There's a big, big persuasion job we'll have to do on people: that the biggest threat to the countryside is not the wind turbines; it's climate change. … The truth is that a vocal minority has stopped them going ahead and the silent majority has not done enough to ensure they go ahead. We're doing all the government can do, I hope people will also do their bit." (Well we tried, but his spin doctor wanted us to take down the banners.)

This was his major theme. He ended his talk by saying "We don't have enough of a global campaign around Copenhagen [climate talks this December] at the moment. I hope you will take part in it." It's not the first time that Miliband has pressed people to give the government a harder time, and he's right: we can't sit on our butts and expect polticians to do more than the public is demanding.

His responses to the questions were interesting, though they betrayed the strangely narrow view that cabinet ministers - so focused on the complexities of immediate policy - now seem obliged to possess. He was asked, for example, about how the UK will implement the findings of IAASTD's report that relate to global warming. This is the vast global assessment of agricultural science which was overseen by a British civil servant and published last year. It was roughly the equivalent of the Intergovernmental Panel on Climate Change's assessment reports: it is one of the most important environmental documents ever published. But Miliband had no idea what she was talking about. Agriculture belongs to another department, so even though it's responsible for a substantial portion of our greenhouse gases, he doesn't have to know anything about it.

There was a similar gap when I asked him about the stonking contradiction at the heart of his new, low-carbon transition paper. There's plenty of good in it, and for the first time it provides a clear road map for achieving the government's inadequate targets for cutting emissions. But while it spells out the means by which we might minimise our consumption of fossil fuels, it also demands that we maximise their production. This is what it says:

"The government's approach is to maximise the economic exploitation of the UK's own oil reserves, to work with other countries to ensure a well-functioning global oil market, and to improve UK fuel infrastructure."

and

"[We will] maximise the economic production of oil and gas from the North Sea".

The government has the same policy for coal. The 2007 Energy White paper says that it intends to "maximise economic recovery of the oil and gas from the UK Continental Shelf (UKCS) and from remaining coal reserves." (page 107).

He appeared to be unaware of the coal policy, denying it while I was asking the question. Has the policy changed? If so, when was this announced? And why are opencast coal mines still being given planning permission? Or could his civil servants have shielded him so effectively from the government's dodgier energy policies that he has never been exposed to this contradiction before?

In any case, he decided to concentrate on gas.

"The less we produce from the North Sea, the more we will import. Gas is a transition technology and it's a long transition. I agree that we have to wean ourselves off fossil fuels, but it is a transition and gas is part of the transition."

Maximising production doesn't look like weaning ourselves off it; nor does his explanation make sense of the government's policy on coal and oil. This is one I won't drop.

I agreed with what he said about population, however.

"There's no question that population growth is part of the reason why we have growth in carbon emissions… but I'm not sure that there's an easy or necessarily desirable solution once you've stated that fact."

Here's what he said in response to a question about flying:

"Domestic flights have got to become more expensive. There are perverse incentives. We have argued strongly for aviation to be included in the European Emissions Trading Scheme. Personally I think aviation is undertaxed. We are the only country in the world to have said we will keep carbon levels from aviation to current levels by 2050. But here's a difficult thing about aviation: we have an 80% reduction target. If we cut aviation emissions by that by 2050, we'd go back to 1974 levels of flying. But the world is getting closer together, not further apartt… we will have to do a lot more in other areas if we're going to carry on flying."

What this means of course is that we'll have to make cuts of greater than 80% in emissions from heating, electricity, other forms of transport and farming in order to accommodate current levels of flying. Where's the vision here? Why can't the government announce a study, for example, on how it might best phase out business flights, replacing them with enhanced video conferencing and all the other brilliant virtual technologies we now enjoy?

The other thing that struck me about the meeting was the great enthusiasm for wind farms. The Vestas people were cheered to the rafters, and even the government's draconian new planning laws were popular. On this issue Miliband is right: the surveys show that there really is a silent majority in favour of onshore wind, but we've failed to mobilise in its defence.

It's a simple idea: cure Europe’s addiction to fossil fuels by connecting its electricity-hungry consumers to the deserts of north Africa that are rich in solar energy.

Simple, but surely this is straight out of science fiction? There may be plenty of sun power in the Sahara, but the cost and political problems in creating an infrastructure to harvest it are daunting.

Some serious players, however, have joined together to see if the obstacles can be overcome. Munich Re, the world’s largest reinsurance group and a leader among financial institutions on climate change, brought together 12 finance and energy companies in Munich a fortnight ago to seek a solution.

The reinsurer, which has had to make high payouts in recent years for damage caused by erratic weather, believes solar power in north Africa could deliver 15% of Europe’s electricity by 2050.

The concept of harnessing solar power from the deserts has long been promoted by Desertec, a European network of scientists and engineers, but this is the first time that commercial companies have come together to discuss how to turn it into reality.

Deutsche Bank, Eon, Siemens and ABB attended the meeting, along with representatives from Desertec, the European Union and the League of Arab States.

Delegates agreed to fund a three-year feasibility study and set up a consortium, with all 12 members having pledged to contribute to the $2.5m (£1.5m) running costs for the first year.

So what is the likely price tag for a scheme that would provide the 15% specified by Munich Re? $560 billion.

“We believe that the technology is available but we want to see if the concept can be realised from a political and economic point of view,” said the reinsurer.

The plan would depend on an enormous expansion of concentrated solar power (CSP) plants in countries such as Algeria, Tunisia and Morocco. CSP plants use mirrors to direct sunlight into a small area and generate heat. That creates steam, which drives a turbine to generate electricity (see graphic above).

The advantage over photo-voltaic solar panels is that it does not need expensive silicon to generate power. CSP needs lots of direct sunlight, making it unsuitable for European countries but ideal for deserts.

Power generation can continue at night, using spare heat that has been held over from the daytime and stored in tanks filled with melted salts such as sodium nitrate or potassium nitrate, or in blocks of concrete. This enables generators to offer a constant power supply and match the peak demand that occurs in the evenings.

Desertec claims that the world’s present electricity needs could be met by covering just 1% of the world’s deserts with CSP. Cost is a problem. Electricity generated by CSP costs about €0.15 per kilowatt, compared with €0.06 per kilowatt for electricity generated from coal or nuclear stations.

Supporters of the Desertec plan believe the price of CSP can be brought down to the same level as fossil fuels if European governments provide subsidies for 10 to 15 years.

These would probably take the form of feed-in tariffs, which would give CSP generators a guaranteed price above market rates for a fixed time.

These subsidies would cost anything between €50 billion (£43 billion) and €250 billion, according to a study by the Vienna-based International Institute for Applied Systems Analysis, which presented its findings at the Copenhagen global warming conference in March.

At least another €200 billion would be needed to build the CSP plants and invest in a transmission grid that could bring the power to European countries.

The institute’s Anthony Patt believes that north African countries are cautiously supportive of the Desertec concept, provided local energy needs are also met. “I’m confident that a deal can be struck that is good for north Africa,” he said.

Munich Re insists the money can be found: “We believe the Desertec concept can be financed by the capital markets if the right companies are involved and there is a regulatory framework that offers good investment opportunities,” it said.

The project would also provide an economic boost to the Sahara region, with Desertec estimating that about 2m jobs would be created by 2050.

Spain so far leads the world in CSP, with six plants already operating and at least 12 more under construction. It offers feed-in tariffs that are guaranteed for 25 years, which has encouraged investment.

Two CSP plants have been operating in California since 1990. Small CSP plants are also being built in Algeria and Morocco.

Despite the size of the challenges, Gerry Wolff, co-ordinator of Desertec in Britain, said he was increasingly optimistic the scheme would succeed. “People are beginning to throw their weight behind this. The logic of the idea is almost inescapable and I’m sure it will happen,” he said.

The plan is not without its critics. Hermann Scheer, head of the European Association for Renewable Energy (Eurosolar), has said the initiative is unviable, claiming its proponents have underestimated the technical and political challenges and the likely cost.

“We could invest the €400 billion here,” said Scheer. “Nothing will ever come of it.”

British forces remaining in Iraq will withdraw to Kuwait by the end of July, at least temporarily, after lawmakers broke this week without passing a deal allowing them to stay to help protect oil platforms.

"Unfortunately, owing to procedural delay, the Iraqi parliament has not yet ratified our agreement," said Jawwad Syed, a spokesman for the British embassy in Baghdad.

"As our existing permissions expire on 31 July, we are withdrawing the Royal Navy trainers to Kuwait while we discuss the position with the Iraqi authorities," he said.

On Monday, parliament adjourned until the end of the Muslim holy month of Ramadan, around September 20, leaving behind a mountain of unpassed legislation, including the Iraqi-British agreement that would allow up to 100 British troops to stay in Iraq beyond a previously agreed withdrawal date.

Under the deal, the British troops would focus on helping Iraqi naval forces protect valuable oil platforms.

Under a separate agreement negotiated last year, Britain was due to pull out its troops by June 30.

Britain, which sent 46,000 troops to the Gulf for the 2003 invasion, had already withdrawn its soldiers to the airport in the southern city of Basra, Iraq's southern oil hub, by 2007.

The holdup in parliament put the status of remaining troops in doubt even after a one-month extension to the June 30 date.

A vote on the new pact was blocked several times in recent weeks by opposition from lawmakers close to leading Shi'ite cleric Moqtada al-Sadr, who reject the presence of any foreign troops, and the lack of a quorum.
"We are happy to hear that the British will withdraw because we want to see Iraq clear of occupation forces," said the head of parliament's Sadrist bloc, Aqeel Abdul-Hussein.

He said there was not sufficient threat to such oil facilities to warrant the troops' presence.

Other lawmakers suggested the Iraqi government might devise another deal that did not require parliamentary approval to allow the British troops to stay without interruption.

"The Iraqi government now must look for another formula to deal with this situation," Ayad al-Samarai, speaker of the Iraqi parliament, told reporters on Tuesday.

Syed said he hoped Iraq's parliament would endorse a legal basis for the presence of British troops "as soon as possible".

Iraq, which has the world's third largest oil reserves, is looking to overhaul ageing and dilapidated oil facilities, including those around the southern port city of Basra.

Editing by Ron Askew

Prince Andrew, who is the UK's special representative for trade and investment, told politicians from the Central Asian nation this week that Britain would be willing to provide "substantial support" to help the country pipe its gas to Europe.

The country used to pipe its Caspian gas to Russia, but recently stopped following a row over contracts. It is now hoping to send gas to Europe through a pipeline funded by the European Union.

"The prospect of sending Turkmen natural gas to European markets, including Britain, is fully in line with Turkmenistan's plans to diversify its exports to world markets," Gurbanguli Berdymukhamedov, the country's president, said.

Britain will become increasingly dependent on expensive imports over the coming years.

However, utility companies are anxious to source gas from more politically friendly regimes than Russia, which has the one of the world's most plentiful supplies.

Other European countries were hit by gas price rises during the row between Ukraine and Russia over a pipeline last winter.

The UK gets the majority of its gas from the North Sea and Norway, plus cargos of liquefied natural gas from countries such as Qatar. Domestic gas production is dropping by 5pc per year.

Turkmenistan, which sold 70bn cubic meters of gas last year, already supplies Iran and is currently working on a pipeline to China expected to come online soon.

However, there remain question marks over the reliability of the Turkmen supplies, with some experts casting doubt on whether it has the resources to supply the European market.

A week before Wednesday’s repeat parliamentary elections in Moldova, China signed an agreement to loan $1bn (£600m, €700m) to this cash-strapped, resource-poor country, nearly tripling Moldova’s external debt and issuing a direct challenge to the US and Russia for economic and political influence in this last outpost of elected Communist rule in the former Soviet Union.

Beijing’s move comes after Russia’s recent agreement-in-principle to loan $500m to Moldova and as payments from the US Millennium Challenge Account have yet to reach $25m. The Chinese loan is double the planned Russian credit and beats by $300m the maximum that the MCA could offer.

Moreover, the Chinese terms are highly favourable: a 3 per cent annual rate over 15 years with a five-year grace period on interest payments, and no human rights strings attached.

The money will be funnelled through Covec, China’s largest construction company. It will ostensibly be put towards infrastructure and projects such as energy modernisation, water systems, treatment plants, the industrialisation of agriculture and the creation of high-tech industries, which Moldova sorely needs.

Chinese-Moldovan negotiations since February help explain the snub that President Vladimir Voronin gave the International Monetary Fund as he showed its team the door in June. The IMF is gone at least until a new Moldovan government is formed, and maybe longer if coalition talks deadlock after Wednesday’s vote. In what looks like a classic case of sovereign “subprime” lending, Covec has even suggested that Moldova’s credit need not be limited to $1bn and that “China can guarantee financing for all projects necessary and justified by the Moldovan side.” This is a remarkable statement given that Moldova’s gross domestic product is about $8bn, its budget is about $1.5bn and the country has stayed afloat, barely, thanks to remittances that are already down by a third in 2009. Covec does not seem particularly concerned about how this money will be paid back.

That is because the loan is not as much about Moldova’s fiscal health as about continuing China’s growth. Before the economic crisis, China had locked up long-term contracts across Latin America, Africa and Australia for raw materials to feed its export-driven economy. US and European demand may have fallen, but China is still obligated under those contracts. Beijing’s priority remains finding employment for the hoards of workers coming on line month after month, relentlessly, in its cities. The clashes in Tonghua between steelworkers and police are just the latest example of what could happen if China cannot keep the conveyor belts running.

Thus far China has been moderately successful in boosting domestic demand with its massive stimulus package and by doing deals around the world such as this one, which foresee the export of Chinese equipment and use of Chinese expertise (along with cheap Moldovan labour) to build Moldova’s infrastructure.

China increasingly expresses concern about its huge US dollar holdings, jangling nerves in Washington. The low interest rate on the Moldova loan suggests that in implementing this project Beijing is more concerned with risk diversification and geo-political positioning than return. China has been very active in central Asia, but there most of the projects made economic sense and were tied to extractive industries. Here, we see a subtle and interesting challenge to the US and Russia in a country where China has historically been more of an observer than a player. As Moscow and Washington discuss nuclear disarmament and joust over “spheres of influence”, we see a wealthy and confident China moving to outflank both in a most unlikely arena.

The challenge comes from below too. Russia considers Moldova well within its “near abroad”. But now we can add Moldova to a raft of former Soviet republics, such as Kyrgyzstan, Belarus and Turkmenistan, that have proven adept at playing both ends against the middle. Russia has long called for a multi-polar world, aiming to weaken American influence. But with Moscow-Beijing tensions increasing over Russia’s seizure of billions of dollars of Chinese goods at a Moscow market, the widening of the Argun River, and other irritants, China’s bold move in Moldova shows once again that for it the whole world is now a “near abroad”.

The writer is former ambassador to Moldova for the Organisation for Security and Co-operation in Europe.