Energy

ENERGY

FINANCIAL TIMES SPECIAL REPORT | Tuesday June 28 2011 www.ft.com/energy­june2011 | twitter.com/ftreports

West takes action on prices and supply A move by consumer nations to release oil from their strategic stocks has helped cool the market down, for now. Sylvia Pfeifer surveys the situation

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t the start of this year, US motorists were grumbling about paying more than $3 for a gallon of petrol. The culprit was the high price of oil, which was trading close to $100 a barrel.

Before last Thursday, the price of a barrel of Brent crude had soared close to $120 a barrel – having peaked so far this year at $127.02 a barrel in April – and the price at the pump was touching $4 a gallon The lesson for consumers is inescapable. Energy, from the petrol that drives our cars to the electricity that powers our homes is likely to get ever more expensive.

It is a lesson that has already been heeded by western governments, which last Thursday released the biggest amount of oil from their emergency strategic stocks since 1991.

The International Energy Agency (IEA), the advisory body for western countries, agreed to release 60m barrels of oil in the coming month to offset the daily production loss of 1.5m barrels of oil from Libya, the north African country engulfed in civil war.

The surprise announcement sent Brent crude prices tumbling to $108 a barrel on the day.

The move, only the third such in the history of the IEA, which was established in 1974 as a counterbalance to Opec after the Arab oil crisis, underlined how concerned western governments have become about the impact of high crude prices on the economic recovery.

The IEA’s twitchiness is understandable.

The two events that have dominated the energy world in the past two months, a crisis at a Japanese nuclear plant and the ongoing civil unrest in the Middle East, have driven home the point that energy is becoming more expensive.

The events in Japan and the Middle East helped trigger the short-term jump in prices that angered US drivers, and put a question-mark over long-held assumptions about the source and cost of energy supplies.

Despite the west’s attempts to curb its appetite for power, there

is no sign of global demand diminishing.

If anything, the world is becoming more hungry for power, according to Christof Rühl, chief economist at BP, with global consumption growth last year at its highest since 1973. China accounted for 20.3 per cent, surpassing the US to become the world’s biggest consumer of energy.

Bob Dudley, BP chief executive, drove the point home to an audience in London last week, noting that “on current trends, we believe the world will require about 40 per cent more energy in 20 years’ time than it consumes today”. He added: “That’s basically two more United States. Or two more China’s worth of consumption.”

The IEA forecasts that global demand will grow 36 per cent by 2035, forcing governments to diversify their energy mix and enhance sourcing security.

Questions are also being raised over the viability of some of the alternatives to fossil fuels.

The near meltdown at the Fukushima Daiichi nuclear plant in Japan after a devastating earthquake and tsunami has forced governments to re-assess their commitments to nuclear power – and how to plug any supply gaps that might result from changing course.

One of the most radical responses to the crisis has been in Germany, where the coalition government of Angela Merkel abandoned a planned extension of the country’s nuclear reactors and reverted to shutting them down by 2022.

The decision constitutes one of the biggest bets made by an advanced industrial country on renewable energy.

Under the plan, eight reactors, or 8.5GW of capacity and about 8 per cent of Germany’s annual electricity production, will be closed permanently this year.

It also commits Europe’s largest economy to doubling its energy from renewable sources to 35 per cent this decade.

Most experts believe Germany will be able to meet the energy demands of its citizens but doubt its ability to meet tough domestic climate change targets, to cut carbon emissions by 40 per cent by 2020 compared with 1990.

While more power from renewables may be the ambition, in the short to medium term, natural gas is emerging as a winner from countries’ plans to scale back their nuclear power.

Analysts at Deutsche Bank, for example, expect emissions by Germany’s power sector to rise

High cost of oil gives boost to services M&A Spare cash and tighter regulation are leading to more consolidation, says Sylvia Pfeifer

In deep again: ExxonMobil this month announced two significant oil discoveries and a gas discovery in the Gulf of Mexico

Inside this issue UK emissions Mixed reviews

Australian LNG Frantic

for coalition sustainability policies – swift progress is required if targets are to be met Page 2

investment is spurred by Asian demand Page 2

US oil recovery Hydraulic fracturing (using fracking fluid, below) and horizontal drilling are expanding supplies Page 2

Renewables policy Solar industry feels chill of UK cuts Page 2

Shale gas in Europe Regulators must balance environmental and energy supply concerns Page 3

China There is no need to be unconventional yet.

Conventional assets are still young, productive and capital­efficient Page 3

The Arctic If there is oil, it will be surprising if humanity shows the restraint not to use it Page 4

by 370m tonnes between 2011 and 2020 as a result of the increased use of gas and other fossil fuels.

The IEA has cited slower growth in nuclear power after the recent events in Japan as one of the factors behind new estimates suggesting the world could be entering “a golden age of gas”.

According to the agency, the use of natural gas could rise by

more than 50 per cent by 2035 from last year.

Industry executives have welcomed a more prominent role for natural gas in the energy mix.

Malcolm Brinded, executive director of exploration and production at Royal Dutch Shell, the Anglo-Dutch company, told a conference in the Netherlands this year that gas is “abundant, acceptable and affordable”.

Gas, he added, was a “destination” fuel, not simply a “transition” fuel on the way to a lowcarbon future.

For the world’s large integrated oil and gas companies these developments are good news. Shell, for example, will produce more gas than oil from next year.

The industry is awash with cash, thanks to high oil prices, with analysts expecting the top five international listed companies to spend $128bn on capital investment this year alone.

The one challenge for the industry is growth. The majors continue to struggle to replace their production reserves – success in exploration is vital.

In some cases their spending is paying off. ExxonMobil announced this month it had made two significant oil discoveries and a gas discovery in the deep water of the Gulf of Mexico. “We estimate a recoverable resource of more than 700m barrels of oil equivalent combined in our Keathley Canyon blocks,” said Steve Greenlee, president of ExxonMobil Exploration at the time.

The likely reliance on fossil fuels in the medium term means targets for the reduction of carbon dioxide emissions will be harder to achieve. The jump in gas usage will help reduce air pollution in many cities, in particular in China, and cut the use

of coal, but it could lead to a global temperature rise of 3.5C, according to the IEA. “While natural gas is the cleanest fossil fuel, it is still a fossil fuel,” says Nobuo Tanaka, chief executive of the IEA. “Its increased use could muscle out low-carbon fuels such as renewables and nuclear, particularly in the wake of the incident at Fukushima . . . An expansion of gas alone is no panacea for climate change,” he adds.

Mr Rühl says strong demand and increased use of fossil fuels is “bad news” for carbon dioxide emissions from energy use.

Today, renewables account for only a small proportion of supply. According to BP, wind, solar, geothermal and biofuels used for power generation and transport contributed about 1.8 per cent of global primary energy supply last year. China became the largest windpower generator, overtaking the US and accounting for 48 per cent of all new capacity.

However, there is room for optimism, as more of the energy coming onstream is from renewables. “Over the past 10 years, their share has almost trebled,” says Mr Rühl. “Over the past five years, their contribution to the growth of primary energy was almost 10 per cent, higher than the growth contribution of petroleum-based products.”

Third pipeline from Canada awaits crucial US decision Oil sands Sheila McNulty on concerns over leaks and the impact on the environment Building a pipeline to the US from Canada to bring fuel from that northern neighbour’s vast tar sands operations should be an easy feat to accomplish.

Not only is the US desperate for fuel, but Canada is stable and friendly.

Its fuel will be cheaper to import than that of far-off nations and its stability would ensure a steady source of supply. On top of that, two such pipelines from Canada already have been built.

Indeed, Jim Vines, partner in the energy environmental practice at King & Spalding, an international law practice, believes it will be tough for the US Department of State to say this third pipeline, Keystone XL, is so different.

“Denial of this permit by the US would be vulnerable

to a serious challenge in the World Trade Organisation,” he says.

But the Keystone XL pipeline is not only subject to criticism by environmentalists about the import of the high carbon fuel.

A series of spills from the first Keystone pipeline led US authorities to suspend its operation temporarily this summer. The timing could not be worse for TransCanada, the pipeline operator, which is waiting for the state department to decide by year-end whether to let it progress with its Keystone XL extension pipeline.

“TransCanada needs to ensure the pipeline is safe, secure and can operate without the risk of leaks,” says congressman Edward Markey, the top Democrat on the Natural Resources Committee of the House of Representatives.

“These concerns need to be fully addressed, as the administration and state department evaluate the Keystone XL project.”

TransCanada was able to obtain approval to restart its Keystone pipeline in a

few days and points out that the last incident, at a pumping station in Kansas, had involved less than 10 barrels of oil.

“Almost all the oil releases over the past 12 months on Keystone have been minor – averaging just five to 10 gallons of oil,” says Russ Girling, TransCanada’s president and chief executive.

‘The protests are not going to stop tar sands development’ “The vast majority of that oil was confined to our property and in all cases was cleaned up quickly.

None of the incidents involved the pipe in the ground – the integrity of Keystone is sound.”

But that the first Keystone has suffered 11 spills in its first year is a worry for environmentalists.

Susan Casey-Lefkowitz, director of the international programme at the Natural Resources Defense Council,

an environmental group, notes the highly corrosive nature of bitumen, which is what the tar sands are composed of.

This is a concern, she says, because Keystone XL is to cross the Ogallala Aquifer, a freshwater source for eight states.

The Keystone XL is a 2,673km, 0.9m crude oil pipeline that would start in Alberta and extend southeast through Saskatchewan, Montana, South Dakota and Nebraska.

It would incorporate a portion of the Keystone Pipeline that runs through Nebraska and Kansas to serve Oklahoma, before continuing, to serve the Port Arthur market in Texas.

Ms Casey-Lefkowitz says the Keystone XL pipeline is redundant, because there are already the first Keystone and the Alberta Clipper pipelines bringing tar sands fuel into the US. “It’s not necessary for energy security,” she says.

“Bringing this oil across US heartland, farms and the Ogallala Aquifer is a real danger for communities.”

Line from the sands: Canada is stable and importing from there cheaper

A growing number of environmentalists and local officials also object to the higher carbon content of tar sands fuel.

The mayors of 25 towns and cities wrote a letter on March 24, to Hillary Clinton, secretary of state, expressing grave concerns about expanded tar sands oil imports.

“Specifically, we are concerned about the impacts of the proposed Keystone XL pipeline that would transport tar sands oil from Alberta to Texas, increasing our dependence on this high carbon fuel for decades to come, at a time when we, as local governments, are working hard to decrease our dependence on oil.”

Nonetheless, some supporters of Keystone XL say the carbon footprint will be less if fuel is exported to the US in a pipeline rather than shipped in a tanker across the ocean to China.

Kenneth Medlock, energy expert at Rice University, says there is a project under way to export the fuel to the Pacific Basin.

“The protests are not going to stop tar sands development,” Mr Medlock says. “You have to think of the world as one big bathtub. It doesn’t matter which end of the tub you fill from, as long as you are adding supply. The oil is going to flow.”

That said, it is uncertain whether that oil will flow

TransCanada

through the planned Enbridge Northern Gateway pipeline system aimed at taking some to alternative markets.

That pipeline, which would run 1,170km from Alberta to a new port in Kitimat, on the coast of British Columbia, has also met fierce opposition.

Mr Vines focuses his comments on Keystone XL: “In the US, big energy projects tend to go through a lengthy regulatory process and a lengthy litigation process.

“If the Canadians have the perseverance to work through these two processes, which I think they do, the pipeline will get built.’’

In December last year, General Electric announced it was buying Wellstream, the world’s second-largest supplier of flexible pipes for the oil and gas industry, for about £800m ($1,300).

The deal capped months of pursuit by GE of the UK company during which it was twice rebuffed.

For GE, which has identified energy services as a key area for investment, its dogged pursuit was worth it, as Wellstream had two attractions: its technology and a significant presence in Brazil, one of the new frontiers of oil exploration.

The acquisition, among a flurry of others in the oil and gas services sector over the past 12 months, signalled not only that there is ample growth in the sector but that, despite BP’s spill in the Gulf of Mexico, deepwater drilling had not suffered a prolonged downturn, as many analysts had feared would happen.

The search for resources is taking big oil companies into the deep water in countries such as Brazil, as well as other areas that involve complex drilling.

Unconventional drilling techniques are also in focus in the wake of the development of shale gas in North America.

The demand for better technology, combined with an industry that is flush with cash because of high oil prices – analysts expect the five largest publicly listed oil companies alone to plough a record $128bn into capital investment this year – means service companies are in demand.

Tighter regulation and increased costs after the BP accident are also expected to increase demand for these companies’ services, in particular those with modern fleets of deep-water rigs, such as Pride International of the US and SeaDrill, the Norwegian drilling company, which command higher rates than shallowwater rigs.

The new regulations could make it harder for some smaller service companies to compete.

Christopher Pilot, managing director, head of EMEA oilfield services coverage at Goldman Sachs says: “As long as the oil price remains above $70-$80 a barrel for Brent crude, service companies should do well – as the price dips below these levels, international oil companies start debating capex versus dividend reductions . . . capex tends to lose out.”

The increasing demand and high crude prices are underpinning merger and acquisition activity.

In February, Ensco proposed to buy Pride International for $7.3bn in cash and stock to create the world’s second-largest offshore driller after Transocean.

The deal followed a string of smaller transactions, including GE’s purchase of Wellstream, Seadrill’s acquisition of Scorpion Offshore and Noble Corporation’s of Frontier Drilling.

Mark McComiskey, managing director at First Reserve Corporation, the private equity group that has invested more than $3bn in oilfield services over the past five years, says there is “strong demand for rig businesses and equipment and services businesses”.

Last year, First Reserve sold Dresser, a Texas-based maker of gas engines used to power oil and natural gas production, to GE. First Reserve, adds Mr McComiskey, is looking at several areas to invest, including unconventional gas in North America, in particular companies with service expertise that can Continued on Page 4

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FINANCIAL TIMES TUESDAY JUNE 28 2011

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Energy

Mixed reviews for sustainability policies UK emissions There must be swift progress if targets are to be met, says Pilita Clark If you had only been reading international newspapers, you would probably be quite impressed at the UK coalition government’s environmental credentials.

“A striking example of a government committing to big environmental initiatives while also pursuing austerity measures,” is how the New York Times described the UK’s May announcement it would halve its greenhouse gas emissions from 1990 levels by 2027.

In Britain, however, the government has had far more mixed reviews.

Environmental campaigners were broadly supportive of the emissions targets, although industry groups

such as EEF, the manufacturers’ organisation, said the move was a “bad decision” that would threaten UK competitiveness.

More broadly, the coalition’s environmental commitment has been the subject of considerable debate.

Plans to sell off public forests prompted such an outcry that the government ended up retreating in February.

Ministers have also sparked criticism from the solar industry for slashing subsidies for large solar panel installations (see article right).

And, as the government’s first year in power ended in May, the claim that David Cameron, the prime minister, made within days of taking office that he wanted to lead the “greenest government ever” was dismissed as “vanishingly remote” by Jonathon Porritt, former head of the UK Sustainable Development Commission.

Mr Porritt, whose com-

mission was axed in an early round of budget cuts, audited more than 70 policies in a study for Friends of the Earth, the environment organisation, and found little or no progress on more than three-quarters of them.

In line with other environmental groups, he was disappointed by a refusal to allow the new “green investment bank” – which aims to invest in lowcarbon infrastructure – to borrow funds until 2015 and by the abandonment of plans to make airlines pay a per plane duty, rather than a per passenger tax.

The government has backed several initiatives that Mr Porritt and green groups have praised, including a move to roll out “smart meters” – to help make electricity use more efficient – to 30m homes and businesses from 2014, and schemes such as the renewable heat initiative, which encourages technologies such as ground or

water source heat pumps.

But if the UK is to meet its long-term target of reducing greenhouse gas emissions by 80 per cent from 1990 levels by 2050, it will have to make serious progress on its renewable energy ambitions.

At present, only about 3 per cent of total UK energy use – for electricity, transDavid Kennedy: at the moment there is a lot of investment uncertainty

port and heating and cooling – comes from renewable sources.

Chris Huhne, the energy secretary, has pointed out this puts the UK ahead of only Malta and Luxembourg in recent European Union rankings. The proportion has to go up to 15 per cent by 2020 under an EU directive the UK has signed up to.

The challenges are especially acute when it comes to electricity – some 30-40 per cent will have to come from renewable sources by 2020 to meet the government’s targets, up from about 7 per cent in 2010.

For nearly a decade, the government has encouraged investment through its Renewables Obligation Certificate (ROC) scheme, which requires suppliers to present certificates to prove that a certain amount of their energy comes from renewable sources.

That is set to change under electricity reforms that ministers are now considering, which have been described as the biggest shake-up of the power market since the industry’s restructuring and privatisation in the early 1990s.

David Kennedy, chief executive of the Committee on Climate Change, the body that advises the government on how to meet its carbon targets, says the move is necessary because

the existing system did nothing to encourage investment in low-carbon sources of energy such as nuclear, or new technologies such as carbon capture and storage.

The changes create uncertainty. Mr Kennedy says: “Investors need to feel confident and at the moment there’s a lot of uncertainty, because of the move from the ROC regime – which investors are comfortable with – to the EMR, [electricity market reform bill], where we don’t really know any of the details.”

The government is planning to issue a white paper setting out its reforms in July, but Mr Kennedy worries about whether it will give investors all the detail they need.

That will be a problem, he says, because: “You cannot expect people to take investments forward or boards to approve funding of projects, when they don’t know what market they’re going to be selling into.”

Permian Basin sees reversal of fortune US oil recovery Hydraulic fracturing and horizontal drilling are expanding supplies, writes Sheila McNulty

J

oe Moroles recalls when business was so bad in the Permian Basin – two years ago – that restaurants were virtually empty.

The Halliburton project co-ordinator for Chevron, the oil group, says servers were able to attend to the every need of the few customers. “You couldn’t have half a glass of iced tea without someone filling it up,” he says.

Now those same restaurants in this west Texas oil region are struggling to keep staff from leaving for the oil patch, where business began picking up with the price of oil in 2010.

Demand for workers has attracted waiters, teachers, and even police officers to set pipes, transport rigs and truck out oil in the 110°F heat.

“All of a sudden, drilling turned around; we were short on equipment, short on employees,’’ Mr Moroles says.

Producers began applying technology that had enabled a tripling of US natural gas supplies to the oilfields in the Permian, the largest oil producing basin in the US. The goal is to increase production in an area that already produces 1m barrels a day and is believed to contain a quarter of the 20bn barrels of US oil reserves considered recoverable.

Oil companies have been snapping up acreage or returning to fields that they had long held on

Contributors Sylvia Pfeifer Energy Editor

to, in the hope of such a boom.

“Everybody is looking for anything they can get right now,” says Jerry Mathews, production foreman for Devon Energy, an oil and gas group.

A couple of years ago, Devon was only drilling when it had to, on contracts that required activity to hold leases.

Now it is determined to drill 300 wells – for between $1m and $8m a well – across the dry flatlands of brush and cactus.

With 1,000 companies operating in the Permian, drilling crews cannot keep up with demand.

Companies are desperately seeking truck drivers to take the crude from these far-out fields to refineries.

There are no pipelines where the new drilling is taking place – just oil pumps bobbing up and down on otherwise abandoned flatlands as far as the eye can see.

“Anyone in this part of the world who wants to work can have a job,’’ says Don Mayberry, production superintendent in the Permian for Devon Energy.

The same horizontal drilling and multi-staged hydraulic fracturing process – pumping water, sand and chemicals into rock at high pressure – that has increased domestic gas supplies to more than 100 years’ worth at current usage rates is starting to expand oil supplies too.

US production rose last year to its highest level in almost a decade, thanks to these “unconventional” production techniques.

According to the US government’s Energy Information Administration, domestic production of crude oil and related liquids rose 3 per cent last year to an average of 7.51m b/d – its highest level since 2002.

This has increased investor

Ed Crooks US Energy & Industry Editor Leslie Hook Beijing Correspondent Sheila McNulty US Energy Correspondent Peter Smith Australia­Pacific Correspondent Ursula Milton Commissioning Editor Steven Bird Designer Andy Mears Picture Editor For advertising contact: Liam Sweeney on: ++44 (0) 20 7873 4148; e­mail: liam.sweeney@ft.com

interest, with the number of rigs actively drilling at 1,860; up 321 year on year, according to Baker Hughes, the oil services company.

Most of them – 1,808 – are on land and use the new technology,

‘People have been drilling through [shale rock] for years; now we’re finding out how productive it can be’ which enables drilling down 10,000 feet or more and then turning the drill bit so it pushes horizontally, as much as 10,000 feet, to expose a much wider area to extraction from a single well.

The pipe pushed down this way is set for a series of small

explosions along its length.

Water laced with fine sand and chemicals to kill bacteria and help the sand flow is then pumped through, in a series of stages, at high pressures, to fracture the rock surrounding the explosion sites.

The sand keeps the new passageways open so the oil can escape.

While the industry has been using hydraulic fracturing and horizontal drilling for years to extract gas, the technology has become better and cheaper.

It is now economical to use the process to extract more from existing oil wells and from rock such as shale, which the industry long ignored as too hard for extraction.

“Shale is something people didn’t think about as productive,” Mr Mayberry says. “People have

Alamy

been drilling through it for years; now we’re finding out how productive this stuff can be.’’

The Permian Basin covers 100,000 square miles, in west Texas and south-east New Mexico.

It was originally believed to hold 106bn barrels of hydrocarbons.

Since the first commercial well was drilled here in the 1920s, about 40bn barrels of oil equivalent have been produced, 30bn of which were oil. That leaves some 60bn in the ground.

“This is a huge basin with a tremendous amount of oil and gas down there,” says Mitch Mamoulides, Chevron’s manager for the Permian South. “The challenge is getting it out.”

This year, Chevron is planning to drill 350 wells there, up from 200 last year. It operates 11,000 wells in the area, some of them 70 years old.

Renewables policy Feed­in tariffs for big schemes to fall sharply in August, writes David Blair Until this month, scores of farmers in the south-west of England were planning a new business model.

Instead of using their land solely to grow crops, they decided it would make more commercial sense to turn over large areas to the renewable energy industry.

Fields across Cornwall were rented by solar power companies, with the aim of installing large systems capable of generating up to 5MW of electricity.

Most of these schemes are now in jeopardy.

In February, the government proposed to reduce the subsidies, known as “feed-in tariffs”, paid to schemes capable of generating more than 50kW. After a period of consultation, Greg Barker, the climate change minister, announced on June 10 that this decision would become policy, with the cuts taking effect from August 1.

The UK’s nascent solar industry now faces radical change. Any schemes aside from the smallest will have a much-reduced level of government support.

Subsidies for the most ambitious – defined as those generating from 250kW to 5MW – face a 72 per cent cut in feed-in tariffs, reducing payments from 30.7p to 8.5p a kW hour.

The government says that reform was necessary to prevent large schemes from “soaking up” funds that were intended to encourage solar power for households and small businesses.

“Without action, the scheme would be overwhelmed,” says Mr Barker.

The coalition inherited a solar power subsidy system from the previous government predicated on a series of assumptions that turned out to be false.

The return on solar power generation was forecast to be about 5 per cent, well below the level required for commercial interest.

Meanwhile, the government assumed that any planning applications for big schemes would make slow progress across the bureaucratic hurdles set by local councils.

In fact, improved technology has reduced the cost of photovoltaic solar arrays, doubling possible returns to at least 10 per cent.

Meanwhile, Cornwall’s council, in particular, decided to encourage these schemes by processing planning applications much faster than expected.

The government argues that without its changes, the £400m ($650m) set aside for feed-in tariffs would have been absorbed by the largest schemes.

Left unspoken is another vital reason for the reform.

Last year’s spending review cut 10 per cent off the sum for the subsidies by 2014-15.

The changes were, in effect,

forced by the need to reduce the cost of the feed-in tariffs.

Critics say the UK will pay dearly for a shortsighted decision, taken largely for reasons of pragmatism over principle.

If big schemes are robbed of their commercial viability, the country will be unable to develop an upstream supply chain with sufficient economies of scale.

This could leave a choice between two unpalatable options.

Either the country will lose the option of building large-scale solar schemes, or it will rely on other countries, notably Germany, for the components and technology, thereby missing out on the industrial benefits.

The Solar Trade Association has given warning that the new policy will “effectively kill the UK solar industry for all installations over 50kW”. Howard Johns, chairman of the STA, says the decision had been forced by budget cuts.

“Crushing solar makes zero economic sense for ‘UK plc’, because it will lose us big manufacturing opportunities, jobs and global competitiveness. It also risks locking us into more expensive energy options,” he says.

In general, energy policy has been a subject of crossparty consensus. The solar feed-in tariff cuts are an exception.

Howard Johns: ‘Crushing solar makes no economic sense’

Huw Irranca-Davies, the shadow energy minister, says the decision “hammers a nail into the coffin of many modest, medium-scale community, school and hospital schemes, risking thousands of jobs in an industry that was beginning to flourish”.

But more than 90 per cent of the UK’s solar installations are on the roofs of individual households – and will be unaffected.

However, Daniel Guttman, director of renewables for PwC, the consultancy, points out that a “large scale system is significantly cheaper than a rooftop installation”.

He adds: “The structure of the tariff bands means the most expensive, inefficient part of the market is being stimulated, while systems on social housing, factories and large retail sites will slow down or halt.”

Meanwhile, new solar companies that have invested on the basis of the previous system face an agonising choice. They must either abandon their plans, or rush to complete them before the cuts come into effect on August 1.

Privately, industry figures say they will be reluctant to take investment decisions on the basis of government assurances ever again. Yet, in the present budgetary climate, the coalition can reasonably argue that it had no choice.

Frantic investment spurred by Asian demand

David Blair Energy Correspondent Pilita Clark Environment Correspondent

With 1,000 companies now operating in the Permian Basin, drilling crews cannot keep up with demand

Solar industry feels chill of UK cuts

Australian LNG Peter Smith looks at the prospects for ambitious projects On a remote and ecologically sensitive island off Western Australia, one of the world’s most ambitious energy projects is being built. It is hoped it will transform the country into a natural gas exporter to rival market leader Qatar.

The Gorgon liquefied natural gas (LNG) project on Barrow Island, operated and half owned by Chevron with large minority stakes held by ExxonMobil and Royal Dutch Shell, is being developed at cost of A$43bn ($45.5bn) making it Australia’s largest singleresource project.

Gorgon may be the big-

gest but there are at least a dozen more LNG projects, including Browse, Prelude and Wheatstone that are either under construction or in advanced planning.

The frantic pace of investment in the Australian gas industry by many of the world’s biggest energy groups has been spurred by rising energy demand in Asia, led by China, Japan and South Korea.

“We have a resource base in a really good neighbourhood,” said John Gass, president of Chevron’s gas unit, on a recent trip to Australia. “Australia is the epicentre for Chevron’s natural gas portfolio.”

“That is important because the Asia-Pacific market has the highest growth. It is expanding at several times the rate of other regions,” he adds.

The latest World Energy Outlook from the Interna-

tional Energy Agency forecasts that China’s demand for natural gas could rise by 5.9 per cent a year between 2008 and 2035, compared with a 0.5 per cent annual rise over the same period for nations in the Organisation for Economic Co-operation and Development.

At that rate, China will account for 8.7 per cent of global gas consumption by 2035, compared with 2.7 per cent in 2008.

Australia is regarded as a safe investment destination in spite of Canberra’s highprofile battle last year with mining groups over a resources rent tax.

It is also well placed in the Asia-Pacific region to service the needs of China and other big customers.

Japan’s strong interest in Australian LNG has increased further in the light of a review of its energy strategy after the

Fukushima nuclear accident. This could spur Japan’s Inpex to give the final go-ahead for its Ichthys project in Western Australia this year.

The world gas industry was given a further boost in May, when Germany said it

‘There is a huge upsurge in projects but it is highly unlikely Australia can deliver all to schedule’ planned to close its 17 nuclear power plants.

Craig McMahon, a Perthbased analyst with Wood Mackenzie, the industry consultancy, is sceptical whether all the projects being planned in Australia will reach fruition and

believes some competing ventures will merge.

“There is a huge upsurge in projects, but it is highly unlikely that Australia will be able to deliver all to schedule. The projects will be operating within the confines of the [national] labour market.”

The more advanced projects have the best prospects, he believes. “Gorgon has first mover advantage,” he says, “but the sheer scale of the project and the environmental provisions makes it a real challenge to deliver on time and budget.” But Gorgon’s backers believe that 18 months into its construction phase the project is on target to ship its first gas in 2014.

Chevron argues the challenges of the project, which include laying hundreds of kilometres of pipes on the ocean floor to carry gas back to the island for

processing, are on a par with the building of the Channel tunnel.

Some 90 per cent of Chevron’s share of Gorgon gas has been presold to Japanese and South Korean customers under long-term agreements, while Exxon has struck a deal with PetroChina for its portion.

“This investment is so huge that you would have to have confidence in the offtake [gas supply agreements concerning future production],” says Roy Krzywosinski, head of Chevron Australia.

In another sign of how gas is shaking up big energy groups, Chevron has also forecast that by the end of the decade natural gas will account for 40 per cent of its oil and gas portfolio, from about 30 per cent now.

“That is largely driven by what is happening in Aus-

tralia,” Mr Krzywosinski says.

To date, Australia has only two producing LNG projects, the Woodside-operated North West Shelf and ConocoPhilip’s Darwin development, with a third, Pluto – another Woodside project – due to deliver its first gas later this year.

There are also at least four coal-bed methane to LNG projects being developed in Queensland in the east of the country that have been formally sanctioned or should be soon.

As projects come on stream, the Australian gas sector should lose its reputation for not always living up to its promise.

If output grows from the current 15m tonnes a year to more than 70m by the end of the decade, as analysts expect, it will secure a position as one of the world’s leading producers.

FINANCIAL TIMES TUESDAY JUNE 28 2011

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Energy

Golden age will need golden standards first Shale gas in Europe Regulators must balance environmental and energy­supply concerns, reports Sylvia Pfeifer

O

n a recent day in June, three oil and gas companies announced their intention to list on the London market. After a dry period for flotations in the sector, the flurry underlined resurgent investor appetite.

The smallest of the three, the Aim listing of 3Legs Resources, was nevertheless significant, highlighting investor support for the exploration for unconventional gas in Europe, a trend that barely registered four years ago when the company was established.

Chaired by Tim Eggar, the former UK Conservative party energy minister, 3Legs Resources raised £62.5m ($101m) from the flotation. The money will be used to develop its shale gas licences in the onshore Baltic Basin in northern Poland where it is drilling with US partner ConocoPhillips.

The development of shale gas has transformed the North American

energy landscape and its supporters believe unconventional gas has the ability to revolutionise the European market, which is also home to vast resources.

A report this year by the US Energy Information Administration analysed 48 shale gas basins in 32 countries, and estimated the technically recoverable resource in Europe at 624,000bn cu ft compared with 862,000bn cu ft in the US. The resources hold the potential to cover European gas demand for at least 60 years, according to a study by the European Centre for Energy and Resource Security.

However, 3Legs Resources’ debut on the market comes at an uncertain time for the industry, as governments and regulators try to balance concerns about the impact on the environment of the technology used to extract the gas with the need for a viable source of energy that has lower carbon dioxide emissions than coal.

In June, France’s upper house, the Senate, adopted a bill banning exploration for hydrocarbons using hydraulic fracturing or “fracking”.

The process, which involves pumping water, sand and chemicals at high pressure into the shale rock to release gas trapped thousands of feet under-

China No need to be unconventional yet China, the world’s largest energy consumer, has a tendency to make a splash when it enters global energy markets.

In oil markets, crude prices rose along with China’s import volumes in the early 2000s, after the country became a net importer of oil in 1993.

In coal markets, its shift to being a net importer of thermal coal in 2009 pushed prices to their current record highs.

The country may soon have the same effect on natural gas, say analysts.

The government plans to promote natural gas consumption because it is cleaner­burning than oil or coal.

Under Beijing’s blueprint, gas use will more than double during the next five years to reach 260bn cu m, making China the world’s third­largest gas market after Russia and the US. But where will this natural gas come from?

Currently, China produces most of its own gas, importing 4 per cent of supply from central Asia and a further 11 per cent from LNG shipments.

A key question is, to what extent domestic supplies will be able to keep up with growing demand.

Ever since the US began producing “unconventional” gas on a large scale – from shale rock or locked in coal deposits – geologists have been looking for the next big unconventional discovery.

In addition to Europe, where some unconventional gas wells are being drilled, many eyes have lighted on China, which is geologically extremely diverse and not yet surveyed to the same extent as the US. “Unconventional gas is a dream come true for China’s energy policymakers,” notes a recent report from Jefferies, an investment bank.

However, it warns that unconventional gas in China is at least a decade away. “[China’s] conventional assets are still young, untapped, productive and capital­efficient.

“China does not need to invest in unconventional gas until the easy conventional gas is gone,” the report notes.

Investment and drilling of conventional natural gas began in the country in earnest about 10 years ago, and reserves remain high.

Although the government has offered some incentives for unconventional production, including a special tariff

for coal­bed methane, it has yet to be produced on a large scale.

Last year, unconventional gas accounted for only about 1 per cent of China’s total production.

Because its oil and gas production is dominated by state­owned energy giants such as PetroChina, Sinopec and Cnooc, the success of unconventional gas will depend to a large extent on the appetite and profit incentives of these three companies.

Crucially, PetroChina and Sinopec own all national pipeline infrastructure.

Independent producers typically have difficulty accessing existing pipelines.

As a result, some small producers choose to truck their gas to market to avoid tough pipeline negotiations.

According to a report by Wood Mackenzie, the consultancy, last year, Chinese unconventional gas could supply as much as 340m cu m of gas a day by 2030, potentially cutting the need for imports.

Imports of LNG will fall after 2020 as a result of unconventional gas development, the report says.

However, on the ground, industry executives paint a more mixed picture.

“Shale gas in China is really different from the US – it is not as promising,” says Steve Zou, chief executive of Asian American Gas, an energy company that has coal­bed methane concessions in Shanxi province in the north of the country.

In the area of coal­bed methane, he says government support will be crucial for the sector.

“One complication for coal­bed methane is conflict with the coal miners,” he adds.

One boost for the sector was an industry reshuffle in 2009, which ended the monopoly of China United Coalbed Methane.

While the domestic supply picture may be murky for unconventional gas, the government push in that direction has prompted large Chinese oil companies to boost investment in unconventional gas overseas, partly to perfect the technical expertise needed for its production.

Cnooc, the country’s largest offshore producer, inked two deals to develop shale oilfields in the US jointly with Chesapeake Energy late last year and early this year.

And PetroChina, the listed subsidiary of China’s largest oil and gas producer CNPC, jointly invested $3.2bn together with Shell in an Australian coal­bed methane company last year.

Leslie Hook

Safety spur: valve­checking at a gas plant in south­west China

ground, has prompted concerns about the contamination of water supplies with the chemicals used. Opponents also warn that not enough is known about the effects of the process.

A study by scientists at Duke University in North Carolina published this year found that in one region of Pennsylvania, water from wells in areas with active shale gas production had, on average, 17 times more gas in it than in areas where there was no drilling.

That study has been challenged, but some industry figures admit that badly executed extraction can cause gas to leak into water supplies. The Duke study also provided some support for the industry, by finding no evidence that the chemicals used in fracking – which are pumped deep underground – were leaking into water wells, which are much shallower.

The adoption of the bill by the French Senate means that it should soon become law and the government has also temporarily halted all shale gas and oil drilling.

In the UK, Cuadrilla Resources, the first company to explore for shale gas, has suspended the use of fracking pending a review by the British Geological Survey after possible links

Cuadrilla Resources in the UK has suspended ‘fracking’ on the north­west coast after two small earthquakes

between the activity and two small earthquakes near Blackpool. The government, however, continues to support the process.

Despite the controversy, Mark Miller, chief executive of Cuadrilla, believes shale gas has a future in Europe.

It could take several months before the company can return to fracking at its British site, but it hopes to drill its third well in July. It owns its own fracking equipment, which means it could move it to another project.

Other executives such as Peter Clutterbuck, chief executive of 3Legs Resources, argue the future for shale gas in Europe depends on where you are looking, as it is “country specific”.

Poland, site of the company’s big-

gest investment and where some of the world’s largest oil and gas companies, including ExxonMobil and Chevron, have bought up acreage to explore for shale gas, has a different attitude, he says.

“The government’s reaction and that from the local communities is very positive,” he says, adding that the country “wants to be rid of its dependence on imports of Russian gas”.

In Germany, where the government recently announced it would phase out all nuclear reactors by 2022 in the wake of the Japanese crisis, the country will need to make a decision about how it will meet the supply gap.

Many analysts believe natural gas, including shale, will be the winner.

Alamy

Nevertheless, companies face other hurdles in Europe before shale gas becomes a commercial reality.

Unlike in the US, where the owner of the land also owns the subsoil, in most European countries the state owns the rights and receives the royalties, giving landowners less incentive to allow drilling on their land.

Fatih Birol, the chief economist of the International Energy Agency, warned in June that if companies wanted to see a golden age for natural gas they would need to come up with “golden standards of practice” for developing unconventional resources.

It is a point not lost on the companies. “The industry has a lot to do in terms of public relations,” admits Mr Clutterbuck. “It needs to respond.”

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FINANCIAL TIMES TUESDAY JUNE 28 2011

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Energy

Ice­bound, little known, and highly controversial US offshore Arctic If oil is there, it will be surprising if humanity shows the restraint not to use it, says Ed Crooks

T

he Arctic seas north of Alaska are one of the three great remaining oil and gas prospects in the US, along with the onshore shales and the deep waters of the Gulf of Mexico. They are the least known and hence the most intriguing. They are also the most controversial.

The prospect of oil drilling in the as-yet barely touched Arctic, with its unique ecosystem and wildlife, has outraged environmentalists.

The fact that exploration has been facilitated by the shrinking Arctic ice, thought to be a consequence of global warming caused by burning fossil fuels, is an irony that has made the protests even fiercer.

Royal Dutch Shell, Europe’s largest oil company, which hopes to be a pioneer in developing the US Arctic, has been repeatedly frustrated in its plans, first launched in 2007, to explore the Beaufort and Chukchi seas off Alaska.

Yet in spite of opposition and delays, it is likely that sooner or later the resources of the region will be developed.

US political opinion, which was encouraged to be suspicious of drilling by BP’s Deepwater Horizon disaster in the Gulf of Mexico in April 2010, has been swinging back in favour, driven by persistently high unemploy-

ment and petrol prices that have come close to $4 a gallon.

Victories of the generally more pro-oil Republican party in the midterm elections last November have given fresh impetus to the campaign by the oil companies to be allowed to drill in more parts of the US, including the Arctic.

The administration of President Barack Obama has been unenthusiastic about Arctic drilling, but the strength of its scepticism has wavered.

In March 2010, while proposing to open up other areas of the US coast, it was cautious about allowing more exploration in the Arctic, although companies that bought licences in sales under George W. Bush, the preceding president were still allowed to drill.

After the BP spill, drilling was banned for the year, but last month Mr Obama sounded more positive, talking about streamlining the permitting process for Arctic exploration. Republicans in the House of Representatives have been pushing for legislation to put that into effect.

After giving up on drilling in the summer of this year because it could not secure the air pollution permits it needed, Shell now hopes to drill five wells in the summer of 2012 – five years after it began trying and having spent $2.2bn on leases.

Its persistence and investment of time and money are justified by the scale of the potential prize. The US sectors of the Beaufort and Chukchi seas are estimated to hold about 25bn barrels of oil and 127,000bn cu ft of gas; respectively about 81 per cent and 47 per cent of proved US reserves.

Large discoveries offshore could prolong the life of

High oil prices give boost to services Continued from Page 1

Snow flow: producers say that oil from new offshore Arctic fields would help keep the Trans Alaska pipeline system working

Alaska’s oil industry, which is threatened by the decline of its mature onshore fields discovered in the 1960s and 1970s.

Volumes flowing through the Trans Alaska Pipeline system, which carries oil from the North Slope field across the state to a terminal on the south coast, have been dropping steadily as the reservoirs decline, meaning that the oil is becoming steadily colder and more sluggish.

Eventually, it may not flow at all, companies say, and the pipeline will be useless.

Additional production, for example from new offshore Arctic fields, would provide enough oil to keep the system working.

Against those benefits of increased oil development in the region, there are some unique risks attached to the threat of a BP-style spill.

First, there is simply the remoteness of the area. To fight the Deepwater Horizon spill, BP and the US Coast Guard

deployed dozens of aircraft, thousands of vessels, and tens of thousands of people. None of these would be accessible in farflung northern Alaska to anything like the same extent.

Second, the behaviour of spilt oil in Arctic waters would be different from in the Gulf of Mexico. In colder temperatures, digestion by microbes and evaporation, which seem to have cleared up a large proportion of the BP spill, will work more slowly.

Third, ice could make the clean-up more difficult. Tackling oil trapped under it, for example, could be a particular problem.

Shell says that it is addressing all these concerns, and notes some of the issues in the BP spill do not apply in Alaska.

For example, its wells will be in only about 140 feet of water, compared with the ill-fated Macondo well in the Gulf, which was in 5,000 feet of water.

Pete Slaiby, Shell’s Alaska vice-president, says the company has also been investing to rectify any problems that the BP disaster exposed, such as the need to have equipment to catch oil leaking from a burst well on the seabed.

Shell could have containment deployed in just one hour, he says. However, assurances from the company are unlikely to be accepted by environmentalists.

Cairn Energy, a British independent oil group, has been the subject of action by Greenpeace, the environmental group, with protesters boarding a rig used for drilling exploration wells off the Greenland, another little explored Arctic region.

When drilling in the US Arctic finally goes ahead, Shell can expect to run up against similar protests. Though the objections will undoubtedly be ferocious, they will not change one simple fact: if the oil is there, eventually is will be extracted.

Alamy

With fossil fuels expected to provide the majority of the world’s energy for decades to come, no large-scale alternative to oil for transport fuel on the horizon, and development in emerging economies creating hundreds of millions of consumers, demand for crude is set to grow for the foreseeable future.

Yet the sources of new oil production – the deep waters of Brazil and west Africa, Canada’s tar sands, Iraq, maybe Saudi Arabia – all have drawbacks in terms of technical or political difficulty, or both. Seen in that context, the challenges of the Arctic do not look insuperable.

It is still not known for certain that the oil is there; the first wells will be important for shaping views about the accuracy of estimates.

If Arctic oil does live up to its promise, however, it will be surprising if humanity collectively shows the forbearance not to use it.

be taken to countries such as China, which is hoping to develop its own shale gas resources. Current hot spots include unconventional gas in the US, offshore west Africa, Brazil and Australia.

First Reserve is not alone in targeting companies with drilling techniques for unconventional resources.

One of the recent deals, for example, was the purchase of a 70 per cent stake in Frac Tech Holdings by Singapore’s Temasek, the state-owned investment firm, and RRJ Capital, a newly formed private equity fund launched by Richard Ong, a dealmaker.

Texas-based Frac Tech is an important provider of pressurepumping equipment for the US oil and gas industry. When the deal was announced in April, analysts suggested the new investors were likely to target the Asian market, in particular China.

A report issued by the US Energy Information Administration, part of the Department of Energy, in April estimated China’s recoverable shale gas reserves could exceed those of the US by 50 per cent.

In addition to the M&A activity, experts believe many of the companies that were taken private in 2007-2008 will return to the market in the next couple of years, as investors look to exit.

Although the industry is cyclical, given the almost militaryscale build up of capital by big companies in countries such as Brazil, most analysts expect consolidation to continue.

“In the post-BP Macondo world, if you are an international oil company, you want someone you can rely on with a relatively big balance sheet,” says Keith Morris of Evolution Securities. “There is also a greater tendency among the international companies to take service companies and use them globally,” he adds.