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Coal-fired plants in China cause smog that killed 9,900

Tuesday, 18 June, 2013, 12:00am



Consumption of fossil fuel is biggest culprit behind early deaths and chronic diseases like asthma

Air pollution from 196 coal-fired power stations in Beijing, Tianjin and Hebei caused 9,900 premature deaths in 2011, with the province, a big coal consumer, deserving most of the blame, according to a new study.

The study looked at the health impact of burning the fossil fuel to generate electricity.

The research was co-authored by Greenpeace and American air pollution experts.[1]

It also found that coal consumption in the region had led to chronic diseases, including 11,110 cases of asthma and 12,100 cases of bronchitis.

Among the deaths, 850 were due to lung cancer linked to the carcinogenic heavy metals – including arsenic, lead, cadmium and nickel – from the burning of coal, while the rest were attributed to stroke, heart disease and chronic lung problems.

The report has added to public concern about air pollution in the wake of the choking smog that blanketed northern Chinese cities last winter. “Seriously, it’s time to consider leaving greater Beijing,” one microblogger wrote in response to the study’s findings.

Hebei is the country’s third biggest consumer of coal and was responsible for 75 per cent of the premature deaths recorded, including some in Beijing and Tianjin, the study said. It found that acid gas, soot and dust from coal-burning activities travelled across administrative borders, the study found.

Beijing was the biggest victim, with more than 80 per cent of 1,982 premature deaths registered that were caused by coal-fired plants in Hebei and Tianjin.

Beijing’s efforts to cut coal consumption in recent years had been easily offset by the enormous amount of the fuel burned by its neighbours, particularly Hebei, Greenpeace climate and energy campaigner Huang Wei said.

While Beijing is struggling to reduce its annual coal consumption from 27 million tonnes in 2010 to 20 million tonnes in 2015, Hebei alone consumed 307 million tonnes in 2011.

“The findings show that Beijing, Tianjin and Hebei are interdependent in terms of air quality as well as public health,” Huang said. “And each of the local governments should start to do something.

“It is high time for Hebei to make substantial moves to reduce its coal consumption because it bears the biggest public health loss, with 6,700 premature deaths in the province.”

New measures approved by the State Council last week did not include detailed plans to cut coal consumption nor the setting of a timetable to speed up air quality improvement in city clusters including the Beijing-Tianjin-Hebei area, Huang said.

The study also showed that average levels of PM10, large particulate matter with a diameter of 10 microns, in January had increased sharply in Beijing, Tianjin and Hebei’s provincial capital, Shijiazhuang , over the past three years, despite official claims that air quality had continued to improve.

The data, all from the Ministry of Environmental Protection’s website, showed the public was right in thinking that the smog problem was getting worse, Huang said.

“The weather can be blamed as a reason for this trend, but I think that increasing pollution emissions should be counted as a major cause,” she said.


China must be factor in review of Hong Kong’s electricity scheme

Saturday, 15 June, 2013, 12:00am

NewsHong Kong


Developments over border will be considered in the review of electricity firms’ regulation scheme, says deputy minister Christine Loh

Mainland factors will weigh for the first time in the next review of the regulation scheme that covers Hong Kong’s power firms. environment minister Christine Loh Kung-wai said yesterday that the city could not lose track of what was happening across the border when it came to energy planning.

“It will be the first time that we take into consideration China development,” Loh told a conference on environmental economics. “What’s happening in Guangdong, we can’t ignore in Hong Kong.”

She said these factors would be given weight when the government started negotiating the companies’ Scheme of Control Agreement in the next two years.

Loh did not say to what extent events in the mainland would shape the review outcome, but elaborated later that Hong Kong – which imports nuclear energy and natural gas from or via the mainland – was connected to the “mainland energy picture”.

“As Hong Kong looks at its energy policy today, we should also consider what is happening on the mainland because China is developing and implementing a vast energy-related policy programme,” Loh said.

Introduced in the 1960s to encourage investment in power facilities amid an industrial boom and growing population, the scheme of control ties the financial return of power firms with their investment. The existing scheme, lasting 10 years, will expire in 2018.

An additional factor that will complicate the renewal will be whether the government opens the power grid to third parties such as mainland power producers, and better integrates the Hong Kong grid with that of Guangdong.

Professor Woo Chi-keung, an energy economist and acting head of Baptist University’s department of economics, said closer grid integration had risks, including the impact of Guangdong’s power shortages.

Local electricity use had not reached the maximum capacity of the two power firms and if the grids were hooked, Hong Kong’s remaining capacity would be “used up in a second”.

Before opening up the local grid to third parties, he said, Hong Kong should consider the cost and benefits to local consumers and whether there would be any environmental impact, as letting the market decide could result in weaker regulations.

William Yu Yuen-ping, chief executive of the World Green Organisation, said Hong Kong needed to co-operate more closely with the mainland on energy issues.

“When we import energy from the mainland, no matter if it is nuclear energy or gas, we need to work with them so that they can plan earlier, too,” he said.


Christine Loh Kung-Wai

Source URL (retrieved on Jun 15th 2013, 12:08pm):

Final three named in EfW design contest

Final three named in EfW design contest

09 April 2013 by Susanna Prouse


The Energy Technologies Institute (ETI) has announced a shortlist of three companies still in competition to design ‘the most economically and commercially viable, energy from waste (EfW) gasification demonstrator plant’.

Gasification is a process that converts organic or carbon-based materials into syngas, a combination fuel of carbon monoxide, hydrogen and carbon dioxide.

Advanced Plasma Power (APP), Broadcrown Ltd and Royal Dahlman were all selected from the companies that replied to ETI’s ‘request for proposals’ launched in April 2012. The companies will now design and develop projects plants ‘to demonstrate an integrated system that would be commercial at between five and 20 megawatts (MWe)’.

ETI – a public-private partnership between BP, Caterpillar, EDF, E.ON, Rolls-Royce and Shell – has stated that the aim of this stage of the project, reportedly worth £2.8 million, is to ‘demonstrate how such a plant could create energy-from-waste efficiencies higher than previously produced in the industry at this scale’.

According to environmental consultancy AEA, current incineration plants operate at efficiency rates of 15 to 25 per cent. ETI has said that it accepts that there is a challenge with the designs, as ‘each complete system will need to operate at a net electrical efficiency of at least 25 per cent’.

The designs

The APP led consortium will design a six MWe demonstration facility featuring its Gasplasma technology, which uses a separate plasma furnace to ‘crack and clean the crude syngas from gasifier’.

Broadcrown will design a two MWe high-efficiency demonstration facility using ‘a robust yet highly scaleable concept that promotes distributed waste management and power generation’. The company is also partnering with ‘major European and American technology companies’ to demonstrate a combined cycle using syngas.

Royal Dahlman will develop a seven MWe plant using patented MILENA-OLGA technology, developed in cooperation with Energy Research Centre of the Netherlands. The company is heading a team of British, Swiss, American and Dutch partners.

The first phase of the project takes in design and will last 10 months. The winning submission will be selected in early 2014, based on cost and projected performance.

According to ETI, the plant that is selected could be designed, built, tested and in operation by 2016. The chosen plant is then expected to operate as a demonstration site for up to four years.

The competition reportedly marks the ‘first time’ a total system approach for an energy from waste gasification facility of this size has been considered in a Research and Development (R&D) project.

“The breakthrough we are all looking for”

Paul Winstanley, the ETI Bioenergy Project Manager overseeing the competition, said: “Our national modelling work shows that bioenergy could be a key component of any future energy systems mix to meet the demands of providing affordable, secure and sustainable energy.

“This analysis indicates that new plant designs at this scale could potentially operate at a net efficiency rate of at least 25 per cent, which significantly exceeds the performance of current plants in operation. Any successful design of such a plant will provide the opportunity to move towards more efficient, distributed energy conversion technologies and reduce dependency on landfill for waste management in the UK.”

Rolf Stein, CEO of Advanced Plasma Power, voiced his delight at being given the opportunity to demonstrate the ‘Gasplasma waste to energy technology’ as it “improves competition in the market for the generation of electricity from syngas”.

Broadcrown Ltd’s co-founder and Managing Director, David Borgman said the commission was a “welcome endorsement of [Broadcrown’s] commitment to providing the best engineering expertise and delivering systems to the highest possible standard”.

Jan-Willem Könemann, Renewable Technology Executive at Royal Dahlman, added: “In the current economical situation it is hard to finance innovative and therewith risky projects launching new technology. This ETI project, resulting in a technical and commercial successful waste to energy plant, will be the breakthrough we are all looking for.”

Read more about The Energy Techologies Institute’s shortlist

Memory effect driven emissions of persistent organic pollutants from industrial thermal processes, their implications and management: A review

Department of Resources, Energy and Tourism has made aviation fuel a strategic priority

Department of Resources, Energy and Tourism has made aviation fuel a strategic priority

Scientists are looking at a variety of ways to create biofuels for use in aviation, including using algae as a feedstock. Picture AP/Kirsty Wigglesworth Source: AP

AUSTRALIA has the building blocks of an advanced aviation biofuel industry with the advantage of airlines keen to buy it if it can be made economically.

But it will need international investment, including from Big Oil, and continued government involvement to get it through the risky emerging industry stage, according to one of the nation’s top biofuel experts.

“We have to bring in international investors, which is not a bad thing because they’re good strategic partners and increase the discipline of the whole commercialisation process,” said Susan Pond, chairwoman of the Australian Initiative for Sustainable Aviation Fuels. “Much of the capital we require to invest in and build bio refineries will come from international sources.”

The AISAF is a public-private partnership between the Department of Resources, Energy and Tourism and the industry, which aims to advance sustainable aviation fuel in Australia.

Professor Pond, of the United States Studies Centre at the University of Sydney, believes a two-day biofuel conference at the Australian International Air Show at Avalon in Geelong last week that attracted 10 international speakers demonstrated the interest in Australian biofuels. They included representatives of biofuel companies, aircraft manufacturers and government agencies, including defence.

“In Australia, we’ve done our strategic planning, we know we’ve got opportunities, in the form of our biomass and our capacity to complete large-scale projects,” Professor Pond said.

One challenge, Professor Pond said, was a lack of long-term financing. It was here that there was a place for government and overseas investors. Oil companies also would have to bring their assets to avoid the need to rebuild refineries.

Professor Pond said the Department of Resources, Energy and Tourism had made aviation fuel a strategic priority and understood it would take government involvement at the proof-of-concept and early commercialisation stages.

Government involvement in biofuels centres on the Australian Renewable Energy Agency, set up in 2011, and its renewable energy venture capital fund, Southern Cross Venture Partners. There is also the $10 billion Clean Energy Finance Corp, which might not survive a change in government.

“It’s a new industry,” Professor Pond said. “It’s risky and it won’t be bankable in the conventional sense at this early stage.”

On the private side, both of Australia’s big airlines are keen to develop a sustainable jet fuel industry and have their irons in several biofuel fires.

Qantas has been working with Solena Fuels since early 2011 to investigate the feasibility of building a commercial jet biofuel plant in Sydney similar to a British Airways plant in London.

The aim would be to convert commercial waste to biofuel using a $300m plant based on the Fischer-Tropsch process that makes jet fuel from coal in South Africa and gas in Qatar.

The British Airways plant is due to come online next year and will convert up to 500,000 tonnes of waste a year into 73 million litres of “green” jet fuel, enough to power 2 per cent of BA’s Heathrow base. It will use food scraps and other household material, such as grass and tree cuttings, as well as agricultural and industrial waste, as a feedstock for the fuel.

The flying kangaroo, which staged biofuel flights last year, also has been working with US company Solazyme, which produces oil using single-cell algae as a biocatalyst in industrial fermentation process treating feedstock such as sugarcane bagasse.

Virgin Australia has partnered with Renewable Oil Corporation, GE and the Future Farm Industries CRC to develop a renewable jet fuel derived from West Australian mallee trees using a technique called fast pyrolysis, through which feedstocks are liquefied and broken down to basic organic building blocks under high temperature to produce crude biofuel.

It also has teamed with NSW biofuel company Licella on its unique one-step catalytic hydrothermal reactor technology to produce high-quality bio-crude oil from a biomass such as farm waste.

While the airlines are keen to parade their environmental credentials, they readily admit they are not just driven by a desire to cut greenhouse emissions.

“Airlines see the possibility of another fuel source as a way to hedge their bets on costs,” Professor Pond said. “If they can have long-term stable off-take agreements from another fuel provider, they have bargaining power with fossil fuel providers.

“Also, a long-term contract at known prices gives them a more predictable future in contrast to the volatile oil market.”

While hydro-treated renewable fuels and those produced by the Fischer-Tropsch process have been approved for use in aircraft by certifying agency ATSM International, other processes yet to get the nod such as alcohol-to-jet and fast pyrolysis could prove a big boost for Australia.

Alcohol-to-jet, which Professor Pond believed was likely to be certified by late next year or early 2015, allows a company to take a waste or renewable feedstock through to an alcohol such as ethanol or butanol, then remove the oxygen atoms and produce longer chain hydrocarbon fuels such as jet fuel. Whichever process is used, the potential pay-off is considerable if the industry can bridge the gap between small demonstration plants and commercial production facilities.

The CSIRO’s Flight Path to Sustainable Aviation report in 2011 estimated that an Australasian bio-derived jet fuel industry could generate 12,000 jobs across the next two decades and reduce the nation’s reliance on fuel imports by $2 billion annually.

The report said the industry could decrease aviation sector greenhouse gas emissions by 17 per cent and that there was enough biomass in Australia and New Zealand to supply 46 per cent of the industry’s fuel needs by 2020 and all of it by 2050.

Professor Pond pointed to the set of figures that underscored the need for a concerted global push on biofuels. The world last year consumed a staggering 89 billion barrels of liquid fuels a day or about 1032 barrels per second.

About 60 per cent of that fuel was used for transport, which accounted for 23 per cent of greenhouse gas emissions. About 10 per cent of the transport fuel was used for aviation.

“Australia consumes about 1 per cent of the global supply of petroleum but a proportionately higher percentage of transport and aviation fuels.

“Unsurprisingly in Australia, because of the distances involved, aviation fuels consume relatively more of our transport fuel mix than in other countries.

“In 2010, aviation accounted for about 13 per cent. This is projected to rise to about 20 per cent by 2030 because other modes of transport will take up alternative energy options such as gas and electricity.

“The aviation sector will be dependent on the same liquid jet fuel for many decades. If the sector is to grow as projected, it has to turn its mind to renewable fuels, which don’t have the same carbon footprint as fossil fuels.”

The carbon footprint of fuel refers to the full life-cycle footprint that covers planting and growing the crop through to harvesting and transportation, the production process and burning it in an aircraft engine.

This raised another can of worms, Professor Pond said, “because you have to get your metrics, methods and facts right to meet what will be quite stringent environmental criteria before you can market it as a sustainable fuel”.

“You have to make sure that the energy cost of converting low-energy dense materials into liquid fuel is not unfavourable.”

The biofuel expert believed there was a huge potential for algae in Australia and said this was the focus of many of the local companies. Other promising feedstocks include lignocellulose, such as wood waste; and wheat straw and technologies such as fast pyrolysis show potential.

Professor Pond said the places where biomass could be aggregated most easily would determine where biofuel plants were located and that a state-by-state approach to biomass production systems would be the best way to establish reliable supply.

Ultimately, she said, it all came down to economics and life-cycle greenhouse gas emissions.

“So if you’re in Sydney, the feedstock will be landfill rather than an agricultural crop,” Professor Pond said.

“In regional areas, forest waste or wheat straw, for example, will feed into a bio-refinery located within a 50km radius for processing at least to the first stage of a more energy-dense bio-crude.

“The bio-crude could then be transported to a centralised refinery that can produce a range of products including liquid fuels.

“Renewable aviation fuel will be marketed to distribution centres that service airports. Some regional feedstocks will not be available for aviation fuels because of the economics.”

Professor Pond said airlines would be looking for a 50 per cent reduction in carbon emissions but she suspected this would take some time to achieve.

Current certification allows for up to a 50:50 mix of biofuel and conventionally derived jet fuel. It is likely to a considerable time before the industry has enough scale to meet even that mix.

“The percentage of renewable aviation fuel will probably start at 1 per cent and increase as more bio refineries come on line,” Professor Pond said.

Pros and cons of shale gas for China

By Asit Biswas and Julian Kirchherr
China Daily

Shale gas in China could become a game changer. With recoverable resources of up to 36.1 trillion cubic meters, China has the world’s largest deposit of shale gas, and if accessed properly, it could turn its energy problem on its head.

China’s economy runs on coal. In 2011, China produced 3.8 billion tons of coal, almost half of the world’s total. But coal’s carbon footprint is devastating in terms of global warming – 1 ton of coal produces up to 2.86 tons of carbon dioxide. Shale gas emits about 45 percent less per unit of energy and could thus help China to reduce its carbon footprint significantly.

China’s shale gas exploitation is still at a nascent stage and its drillings are mostly exploratory, and it has not yet started large-scale commercial production. But it released its first five-year plan for shale gas exploitation in March 2012, which has ambitious goals. By 2015, the country aims to produce as much as 6.5 billion cubic meters of shale gas a year, which would be equivalent to 3 percent of China’s total gas production in 2015. And by 2020, it intends to produce up to 100 billion cubic meters of shale gas.

A major obstacle in accessing shale gas is technology. Shale gas is produced through hydraulic fracturing, commonly known as fracking, which is highly sophisticated and complex. Only the United States has been able to exploit shale gas commercially on a large scale, which means China has to enter strategic partnerships with foreign governments and/or companies, at least in the initial years, to acquire the technology and skills necessary for rapid shale gas exploitation.

Indeed, the US and China launched a joint shale gas initiative in 2009, PetroChina entered a long-term partnership with BP in July 2010, and Shell signed its first production-sharing contract for shale gas with China National Petroleum Corporation in March 2012. Besides, Statoil is in initial talks with Shenhua Geological Exploration to jointly develop shale gas projects, and Chevron and ConocoPhillips are engaged in Chinese shale gas joint ventures.

These partnerships are likely to boost China’s technological capability significantly. But even with mature and competitive equipment, China may not be able to duplicate the American shale gas revolution because of shortage of water. Producing shale gas requires massive amounts of water, which become heavily contaminated. And water is scarce in China, especially in regions that have the largest shale gas reserves. For example, the Tarim Basin in the Xinjiang Uygur autonomous region holds some of the largest shale gas deposits but it is also among most water-scarce areas of China.

What role does water play in the shale gas production? Large amounts of water, fine sand and chemical substances have to be injected into the ground under high pressure to break shale rocks to release the gas trapped in them. The International Energy Agency estimates that fracking may require up to 20,000 cubic meters of water per well. Therefore, shale gas rigs usually operate near large reservoirs, not in water-scare areas.

The water problem, however, could be solved by setting up closed loop systems. Depending on the geology, between 20 and 50 percent of the water injected in the ground flows back to the surface. Simply re-injecting this wastewater may reduce a well’s total water requirement significantly. In western Texas, the average water use per well has decreased from about 18,500 cubic meters to 13,600 cubic meters because of increased re-injection of wastewater.

Re-injection could also solve the second water problem associated with shale gas: contaminated wastewater. The wastewater contains not only the chemicals originally injected into the ground, but also heavy metals and minerals from shale rocks. Scientists disagree whether it is possible to recycle all the wastewater that fracking generates, but re-injection could solve this problem to a large extent.

Re-injection, however, may not solve the third water problem. If water is not injected into the ground properly, it could cause the injected fluids and chemicals to seep into groundwater and surface water. A study undertaken by Duke University in Pennsylvania shows shale gas production could seriously contaminate groundwater, and that methane concentrations in drinking water were 17 times higher within a 1-km radius of an active shale gas well than those farther away.

Methane is a dangerous and inflammable gas, and consuming water with high levels of the methane can lead to a variety of health implications such as nausea and dizziness. Also, being a dangerous greenhouse gas, methane traps 20 times more heat in the atmosphere than carbon dioxide.

Since shale gas production in China is in its infancy, there is no comprehensive regulatory system in place. But with the country now auctioning exploration blocks, a sound shale gas regulatory system is needed to ensure long-term exploitation.

Moreover, China must manage its water resources carefully because it is already facing serious water scarcity. For example, the Water Resources Group, led by McKinsey & Company, projects that if China continues with its business as usual practices, its demand for water will soon outstrip supply by 199 billion cubic meters.

A regulatory framework for shale gas should be established to set strict standards for the maximum amount of water that can be used by a well, and measures have to be taken to prevent the shale gas industry from competing with Chinese citizens for water. Steps should be taken to compel companies to adopt the most water-efficient technologies and disclose the amount and toxicity of the wastewater they generate. And the companies should be encouraged to re-inject as much wastewater as possible and obliged to reveal the names and quantities of chemicals they use.

More importantly, baselines for key environmental indicators such as groundwater quality before fracking should be established so that water quality can be monitored reliably.

Only when such regulations are in place can exploitation of shale gas in China benefit the current as well as the future generations.

Asit Biswas is a distinguished visiting professor at Lee Kuan Yew School of Public Policy, Singapore, and founder of Third World Centre for Water Management, and Julian Kirchherr is a graduate student on public policy and management at the London School of Economics and National University of Singapore.


Click to download

Howarth et al. 2012. Methane Emissions from Natural Gas Systems. Background paper for The National Climate Assessment (NCA)

Learn more about the NCA here

Venting and Leaking of Methane from Shale Gas Development: Response to Cathles et al.

Online Supplemental Material Quick Link (pdf)


Howarth, R. W., R. Santoro, and A. Ingraffea. 2012. Venting and Leaking of Methane from Shale Gas Development: Response to Cathles et al. Climatic Change. In Press.

Should Fracking Stop? Point:Yes, It’s too high risk.

read Point & Counterpoint on ACSF blog


Howarth, RW and A Ingraffea. 2012. Should Fracking Stop? Point/Counterpoint Nature, DOI:10.1038/477271a

Methane and the greenhouse gas footprint of natural gas from shale formations

Online Supplemental Material Quick Link (doc)


Howarth, R. W., R. Santoro, and A. Ingraffea. 2011. Methane and the greenhouse gas footprint of natural gas from shale formations. Climatic Change Letters, DOI: 10.1007/s10584-011-0061-5

Indirect Emissions of Carbon Dioxide from Marcellus Shale Gas Development. A Technical Report


Santoro, R. L., R. W. Howarth, and A. Ingraffea. 2011. Indirect Emissions of Carbon Dioxide from Marcellus Shale Gas Development. A Technical Report from the Agriculture, Energy, & the Environment Program at Cornell University. June 30, 2011.

Experts want HK$3b gas stabilisation fund to keep lid on power costs

Submitted by admin on Aug 31st 2012, 12:00am

News›Hong Kong


Phila Siu

Two City University energy experts want the government to set up a natural gas stabilisation fund to offset a likely big increase in electricity prices.

William Chung Siu-wai, director of the Energy and Environmental Policy Research Unit at City University, forecasts that CLP Power could raise its tariff by up to 13 per cent next year, while Hongkong Electric could lift its tariff by up to 5 per cent.

The forecast was made in light of the price of fuel, especially natural gas, increasing dramatically since last year.

Chung said CLP Power had paid HK$48.60 for a unit of natural gas last year, while Hongkong Electric paid HK$87.

The big difference was because CLP Power’s natural gas comes from Hainan Island, while Hongkong Electric sources its supply from Australia.

Chung said the market price for a unit of natural gas had soared to HK$113.10 this year and he expected China to cash in on the increase.

Assuming that both companies had to pay this much next year, they would have to increase tariffs by up to 13 per cent and 5 per cent next year.

The firms have not made public how much they paid this year.

Chung urged the government to inject HK$3 billion into a natural gas stabilisation fund to offset the higher prices Hongkongers would have to pay for electricity.

“The government can set up a seed fund first and then reinvest the money in, for example, the energy market,” he said. If it did, Hongkongers would have to pay only 4 per cent more next year.

An Environmental Bureau spokesman said it would consider the proposal.

Chung brushed off criticism that setting up the fund would be like giving away taxpayers’ money to the power companies.

This was because the two companies did not make any money from the actual cost of the fuel but, for example, from operational charges.

The research unit’s associate research director, William Yu Yuen-ping, said the fund only required HK$3 billion, which was much lower than the HK$4 billion in tariff subsidies the government had granted in the past.

“Natural gas is also a much cleaner energy as it emits half the pollutants burning coal produces,” Yu said.

About 24 per cent of the total energy CLP Power produces is generated from natural gas, while the figure is 27.9 per cent for Hongkong Electric.




Hongkong Electric Company

Source URL (retrieved on Aug 31st 2012, 5:48am):

City ‘stuck with outdated power deal’

Cheung Chi-fai
SCMP Aug 27, 2012

Hong Kong is stuck with outdated rules governing the amount of profit that can be made by power firms, the government’s new energy adviser says.

The total revamp required is impossible before the current deal expires in 2018, despite an interim review next year, said Professor Raymond So Wai-man, a financial expert from Hang Seng Management College who has been appointed chairman of the Energy Advisory Committee.

He warned people not to assume the review would lead to cheaper power bills.

The profits of power firms are tied to the amount of money they invest in fixed assets. The permitted rate of return is set at 9.99 per cent, down from the previous 13.5 per cent before 2009.

So, who replaced Edmund Leung Kwong-ho as chairman, said: “The system is a by-product of the industrial boom in the 60s where the government wanted the firms to boost power supply by rewarding the investment made.

“What the power firm earned under that system was not that much compared to the fast economic growth. But it is clearly too much in the matured economy we have now.”

He said next year’s review of the system by both the government and power firms would not produce the overhaul needed.

“There are going to be some patchwork changes, fixing this and that. But definitely a total revamp is out of question as we have to abide by the contractual spirit of the existing agreement,” he said.

The committee used to be a low-profile advisory body, but that changed when CLP Power (SEHK: 0002) raised its tariffs last year and was criticised by members.

Of the 24 members, 13 were kicked out during the recent committee reshuffle, including one lawmaker. The 11 new members include bankers, an accountant and a chief financial officer of a listed company. There are now no legislators on the committee.

So said the composition reflected the need to focus more on the financial and business aspects of energy suppliers rather than their technical issues. But he warned the public not to have “unrealistic expectations” of the committee, stressing it had no role to adjudicate in any power tariff dispute.

“It is a real challenge to prevent the public from having unrealistic expectations,” he said. “It will be a big problem if we, the energy advisory committee, are mistaken by the public as assuming the role of judge. But I am worried that this is the situation we are facing.”

So said public anger over power tariffs could have its roots in seeing pollution rise along with fuel bills.

He added: “Honestly, the power tariff is not that high in the Asia region, but the public has already formed an impression that it is high and needs to be cut. This is a perception difficult to change.”