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SCMP: Hong Kong plans to get mainland electricity without counting cost in carbon emissions

by Cheung Chi-fai and Ernest Kao of the SCMP:

As the city ponders drawing a third of its electricity from the mainland power grid, it also plans to disassociate itself from the resulting carbon emissions, environmental authorities say.

Carbon emissions related to the imported electricity would be left out of the city’s emissions count, the Environmental Protection Department said yesterday. It is unclear if that is common practice when transferring energy across borders.

The shift of responsibility should help the city achieve runaway success in its carbon reduction targets, set at 50 to 60 per cent below the 2005 emissions level. Frances Yeung Hoi-shan, from Friends of the Earth, said environmental officials were “playing tricks” in seeking to meet the targets.

Dr Luk Bing-lam, chairman of the Nuclear Society and a member of the Environment Bureau’s energy advisory committee, added: “This is self-defeating. The whole thing is about reducing emissions, but it turns out that the emissions will be ‘shifted’ to the mainland.”

All the electricity the city now gets from across the border is nuclear energy.

Under fuel-mix proposals for 2023, mainland company China Southern Power Grid may export up to 15 billion kilowatt-hours a year to Hong Kong – an option that Secretary for the Environment Wong Kam-sing has claimed can help the city outperform its targets.

That same amount of energy can be generated locally by coal- or gas-fired plants, but Wong said the city would then be able to meet only basic benchmarks.

The fuel mix of China Southern is one-third hydro power, 6 per cent nuclear energy and more than 60 per cent coal and natural gas.

Clean Air Network chief executive Kwong Sum-yin said sourcing more energy from the firm’s Guangdong plant was not necessarily a greener way, as more than half of its supply came from coal. Kwong feared greater energy demands imposed on the province would in turn spawn more coal-fired plants.

Luk urged the government to clarify why it believed nuclear energy was a costly option.

World Green Organisation chief executive Dr William Yu Yuen-ping said that if the city decided to obtain electricity substantially from the mainland, it should pay attention to storing enough back-up power in case the supply was disrupted.

20 Mar 2014

SCMP Letters: HK biofuels company makes case for biofuels advantage

Anthony Dixon, CEO of ASB Biodiesel, writes in to SCMP to counter the lack of consideration given to biodiesel by Hong Kong official officials:

There are some encouraging signs that the government is beginning to recognise our local waste-to-biodiesel industry as an excellent already-working model of what it hopes to achieve more broadly for recycling and food waste in Hong Kong.

But I must disagree with the Environmental Protection Department’s ongoing assertion that the introduction of biodiesel will have little impact on roadside emissions (“Biodiesel maker pushes product use in market”, October 28). Surely, given the World Health Organisation’s recent pronouncement that air pollution is a leading cause of cancer, no government can afford to ignore any positive incremental impact.


Difficulties of establishing biofuels exposes poor thinking of HK policymakers

In 2011, Eric Ng of the SCMP wrote an article about a biofuels plant in Tseung Kwan O Industrial Estate that had to suspend construction, likely due to a lack of funding. At the same time, the article shed light on the difficulties faced by current biofuels producers in Hong Kong: stiff competition on the waste oil market, import levies for feedstocks, lack of mandatory legislation to promote biofuels use, and so on.

One of the main advantages of using biofuels is that it achieves more than some 85% reduction in greenhouse gas emissions. The European Union has already mandated a policy of fuel blending: at least 5.75 per cent of all fuel sold has to be biofuel, with the percentage to increase further in the future, and other countries in Asia also have policies encouraging biofuel consumption. Hong Kong lags behind in such initiatives, and it is not difficulty to see why: Eric Ng, in a recent update on the issue, reports official Mok Wai-chuen of the Environmental Protection Department as saying in 2007 that “biodiesel did little to improve roadside air quality”, backed up by 2002 reports from the US National Biodiesel Board and the US Environmental Protection Agency that “suggested the use of biodiesel would result in a relatively modest reduction in roadside emissions”. The irrelevance of such an analysis – blending 5% biofuel into Euro V standard diesel containing 0.001% sulphur could never have meant reducing roadside pollutants – escapes officials; much of the roadside pollutants are carried by prevailing winds from shipping lanes and industries across the border.

If public policy on biofuels is to be decided on this factor alone, then the real benefits of biofuel would be ignored: once the biofuel industry is established, it can process the city’s waste and convert it to fuel; as mentioned before, biofuels hugely reduce greenhouse gas emissions; more importantly, by helping biofuel operations purchase waste cooking oil, the practice of smuggling waste cooking oil across the border to be converted into ‘gutter oil’ and re-used as cooking oil can be stemmed – which would happen to be quite the moral thing to do, given that such usage of recycled oil is carcinogenic and harmful to human health when ingested.

Click here to read the coverage from SCMP:

Beijing to switch from coal to natural gas for power; hopes to improve air quality and quiet civil unrest

In recent years, China’s major cities have been regularly hit with smog, severely impacting air quality and the health of its citizens. With Beijing the hardest hit of all cities, the city is now set to replace its coal-fired power plants with new ones that use natural gas. From SCMP/Reuters (Beijing):

China will replace four coal-burning heating plants in the capital Beijing with natural gas fired ones by the end of next year as it steps up efforts to clean up pollution, the official Xinhua news agency reported on Saturday.

The report, citing the city’s Municipal Commission of Development and Reform, said the four plants and some 40 other related projects would cost around 48 billion yuan (HK$60.1 billion) and cut sulphur dioxide emissions by 10,000 tonnes. It did not detail the related projects.

The plan is the latest step by authorities to deal with a persistent smog crisis in China’s big cities that is fuelling public anger. The capital has been shrouded in thick hazardous smog for several days during the ongoing seven-day national holiday.

China has been under pressure to tackle air pollution to douse potential unrest as an increasingly affluent urban populace turns against a growth-at-all-costs economic model that has besmirched much of China’s air, water and soil.

Last month the government announced plans to slash coal consumption and close polluting mills, factories and smelters, though experts said implementing the targets would be a major challenge.

The new plants will replace four coal-fired ones that provide heating for homes in the city’s central urban area as well as generating electricity, Xinhua said.

The four burned 9.2 million tonnes of coal in 2012, or 40 percent of the 23 million tonnes the city consumed in the year, it added.

5 Oct 2013

The project was initially met with objections, since natural gas would be much more expensive to source in coal-rich China. The city is expecting huge financial losses if heat and electricity generated from natural gas plants are charged at current rates. But with pictures of smog-filled Beijing splashing international front pages, as well as increasing unrest over pollution in general, it seems that high-ranking government officials stepped in to ensure the project will go through as proposed. (A more in-depth story on this is available on

A coal-fired power plant in Zhejiang, China. Switching to natural gas may be a luxury only Beijing can afford. (China Guodian Corporation)

No mention is made, though, of other sources of pollution, such as vehicle emissions. Once a city of bicycles, Beijing is now home to more than 5.2million motor vehicles and a road network endemic with chronic jams, making a major contribution to the city’s air pollutants. More work would be needed if the city is serious about improving its air quality.

Gasification CO2 emissions are carbon neutral

Biomass is a form of stored solar energy – containing both water and carbon dioxide absorbed from the atmosphere and converted through photosynthesis.  When the energy stored in biomass is converted to heat or fuels through gasification, the carbon dioxide is released back into the atmosphere.  An amazing advantage of this process is that its net carbon balance is almost zero!

Biomass fuels minimize green house gas emissions, whereas natural gas emits 10 times the carbon dioxide that biomass does and coal produces twice as much as natural gas!

Biomass provides a unique recycling opportunity for many waste streams.  The following materials can be converted into energy:

  • Wood and paper industry by-products
  • Agricultural residues after harvest (e.g., corn stover)
  • Manure
  • MSW


CO2 as a Carbon Neutral Fuel Source via Enhanced Biomass Gasification

Heidi C. Butterman and Marco J. Castaldi *

Department of Earth and Environmental Engineering (HKSM) Columbia University, 500 West 120th Street, 927 S.W. Mudd, New York, N.Y. 10027

From: Tech

Sent: 13 February, 2013 01:54

To: ‘James Middleton’

Subject: RE: CTAlettPanelEAFeb2013

Just for your information, the McCusker article is a nice overview, but one mistake he makes is comparing the volume of CO2 produced by incineration processes with gasification processes. The mistake is that he treats the CO2 produced from each as equal, which is not the case.  CO2 emissions from coal are new volumes to be added to the atmosphere, whereas those from the gasification plant are recycled CO2 emissions. For this reason, CO2 from a gasification plant are considered to be carbon neutral.  Regarding our work with British Airways in the UK, it should be noted that BA is so pleased with our work that it has asked Solena to build three more biofuels plants—two in Spain and one more in the UK.

Best regards,


Garbage in – Power out

Transportation Energy Futures Study Reveals Potential for Deep Cuts to Petroleum Use and Carbon Emissions

Collaborative NREL and ANL project reveals opportunities for 80% reductions by 2050

Friday, March 15, 2013

The U.S. Department of Energy’s (DOE) National Renewable Energy Laboratory (NREL) and Argonne National Laboratory (ANL) today announced the release of the Transportation Energy Futures (TEF) study, an assessment of avenues to reach deep cuts in petroleum use and greenhouse gas (GHG) emissions in the transportation sector.

“Transportation is an engine of our economic strength, but it also represents a key challenge for the future of U.S. energy use,” NREL Senior Analyst Austin Brown said. “Transportation accounts for 71 percent of total U.S. petroleum consumption and 33 percent of our nation’s total carbon emissions. It presents significant opportunities to cut oil dependence while taking a bite out of greenhouse gas emissions.”

The study revealed strategies to potentially reduce petroleum use and GHG emissions in the transportation sector by more than 80 percent by 2050. However, each of these opportunities faces significant challenges.

The TEF study also confirmed that there is no “silver bullet” for decreasing carbon emissions and petroleum use in transportation. Instead, deep reductions would involve an inclusive approach, combining strategies to:

  • Increase fuel economy for all types of vehicles
  • Reduce use of transportation while providing comparable service
  • Expand use of low-carbon fuels, including biofuels, as well as electricity and hydrogen

“The finding that there are many options increases our confidence that a clean transportation solution is possible in the long term,” Brown said.

The purpose of the TEF study was to address critical questions and inform domestic decisions about transportation energy strategies by identifying possible paths to a low-carbon, low-petroleum future for transportation, as well as the barriers that may block those paths. It can help inform decisions about investments in transportation energy research, and can also help policymakers if they choose to expand the role of advanced transportation technologies and systems. The study focuses on identifying opportunities related to energy efficiency and renewable energy in transportation.

Three major strategies were explored in the study: reduction of energy use through efficiency and demand management; increased use of electricity and hydrogen from renewable energy; and expanded use of biofuels.

It was found that energy efficiency improvements and measures to reduce transportation demand, without compromising service, have the potential to stop – or reverse – the growth in national transportation energy use, making it possible for competitive renewable energy supplies to provide an increasing share of energy.

Focus areas of the nine reports that are part of the TEF study include:

Light Duty Vehicles (personal cars and light trucks)

  • Deployment pathways issues including the development of, transition to, and challenges to advanced technology.
  • Non-cost barriers such as range anxiety, refueling availability, technology reliability, and lack of consumer familiarity.

Non-Light-Duty Vehicles (trucks, rail, aircraft, and other modes)

  • Opportunities to improve non-light-duty vehicle efficiency, including that of medium- and heavy-duty trucks, off-road vehicles and equipment, aircraft, marine vessels, and railways.
  • Opportunities for switching modes of transporting freight, such as moving freight from trucks to rail and ships.


  • Infrastructure expansion required for deployment of low-GHG fuels, including electricity, biofuels, hydrogen, and natural gas.
  • Balance of biomass resource demand and supply, including allocations for various transportation fuels, electric generation, and other applications.

Transportation Demand

  • Opportunities to save energy and abate GHG emissions through community development and urban planning.
  • Trip reduction through mass transit, tele-working, tele-shopping, carpooling, and efficient driving.
  • Freight demand patterns, including trends in operational needs and projections of future use levels.

The TEF project was funded by DOE’s Office of Energy Efficiency and Renewable Energy. The study’s steering committee included the Environmental Protection Agency, the Department of Transportation, academic researchers, and industry associations. Additional input was provided by transportation consultants from Cambridge Systematics, Inc. For more information, visit the TEF Website.

NREL is the U.S. Department of Energy’s primary national laboratory for renewable energy and energy efficiency research and development. NREL is operated for DOE by The Alliance for Sustainable Energy, LLC.


Visit NREL online at

Media may contact:

Heather Lammers

Biomass Incineration | Energy Justice Network

See how much CO2 MSW incineration creates

Trash and biomass incineration are far worse for the climate than coal, per unit of energy produced.

Trash incineration releases 2.5 times as much CO2 as coal, and 55% more if you pretend that the biogenic* part doesn’t count.  Biomass is nearly 50% worse than coal.  This is based on the latest U.S. EPA eGRID 2012 data (2009 data, released in May 2012).
Please note that, especially with the practice of fracking, natural gas is actually worse than coal for global warming, if you count all of the methane leakage from extraction to pipelines to end uses.  This chart is just for smokestack emissions, but for the whole picture on global warming pollution from gas vs. coal, see:

* The “biogenic doesn’t count” (a.k.a. “carbon neutrality”) argument relies on the assumption that the extra pulse of carbon pollution is instantly sucked up by trees grown specifically to offset the emissions from the trees burned. In reality, it takes centuries to become “zero” and about 40 years for biomass to become only as bad as coal. That figure, from a study done for the Commonwealth of Massachusetts, caused that state to adopt the strictest limits on biomass incineration in the nation, making it basically ineligible for renewable energy credits. Studies on this can be found in the links on the right sidebar on our biomass page:

EPA publishes first-ever carbon dioxide emissions standard for new power plants with future implications for existing sources

On April 13, 2012, the U.S. Environmental Protection Agency (“EPA”) published its first-ever carbon dioxide emission standards for new fossil fuel-fired power plants (“Draft Rule”).[1] The Draft Rule essentially requires all new fossil fuel-fired power plants to meet the carbon dioxide (“CO2″) emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal plants can be constructed without carbon capture and sequestration (“CCS”) capabilities. Litigation is expected over the Draft Rule due to the novel nature of the Draft Rule in regulating CO2 and EPA’s departure in several instances in the Draft Rule from its usual method of setting new source performance standards (“NSPS”) on a source category by source category basis.

The Draft Rule applies only to new fossil fuel-fired power plants, but we note that the Draft Rule will trigger a requirement under the Clean Air Act for the EPA (in coordination with the states) to address CO2 emissions from existing sources. With approximately 600 existing coal plants in the U.S., this future action to regulate CO2 emissions from existing sources is arguably more significant than the Draft Rule itself.

Below we provide highlights of the Draft Rule. For a more in-depth analysis of the Draft Rule and its implications for your business, please contact Richard Saines, Marisa Martin or Daniel De Deo. Full contact details provided in the left-hand column.


The Draft Rule is the result of litigation that commenced in 2008 between the EPA and several environmental groups, states and the City of New York.[2] The plaintiffs in that litigation challenged a 2006 EPA rule setting NSPS for electricity generating units (“EGUs”) that did not address greenhouse gases (“GHGs”). To resolve the litigation, the EPA and plaintiffs entered into a settlement agreement in December 2010 that required the EPA to take certain actions relating to NSPS for electricity generating units.[3] The EPA agreed to issue a proposed rule under Section 111(b) of the Clean Air Act that includes performance standards for GHGs for new and modified electricity generating units. The EPA also agreed to issue a proposed rule under Section 111(d) of the Clean Air Act setting emission guidelines for GHGs from existing electricity generating units. After nearly a year of delay, the EPA issued the Draft Rule in order to comply with the first requirement in the settlement.[4]

CO2 Emissions Standard & Covered Electricity Generating Units

The Draft Rule establishes a NSPS equal to a single output-based CO2 emission limit of 1,000 lb CO2/MWh (“CO2 Standard”) that is applicable to new electricity generating units (referred to as “Covered EGUs”, defined below). The CO2 Standard is equivalent to the CO2[5] emissions from a natural gas combined cycle power plant. The EPA determined that the CO2 Standard constituted the “best system of emission reduction” (“BSER”) which has been “adequately demonstrated”, which is the definition of “standard of performance” under Section 111(a) of the Clean Air Act.

Notably, the EPA proposes a new TTTT category of “new sources”[6] subject to the CO2 Standard (deemed “Covered EGUs”) that includes both coal and natural gas power plants in one category. Generally, the EPA sets a NSPS based on the type of technology used and does not combine sources into one category with one NSPS. The new TTTT category combines boilers and integrated gasification combined cycle (“IGCC”) units (currently included in the Da category) and combined cycle units that generate electricity for sale and that meet certain size criteria (currently included in the KKKK category). The Draft Rule defines a “Covered EGU” as “any fossil fuel-fired combustion unit that supplies more than one-third of its potential annual electric output and more than 25 MW net-electrical output (MWe) to any utility power distribution system for sale” with some exceptions. Based on this definition, Covered EGUs include electric utility steam generating units (“boilers”); stationary combined cycle combustion turbines and their associated heat recovery steam generator (“HRSG”) and duct burners; and IGCC units, including their combustion turbines and associated HRSGs. Covered EGUs do not include stationary simple cycle combustion turbines (e.g., peakers) or EGUs located in non-continental areas. Also, solid waste incineration units subject to emission requirements under Section 129 of the Clean Air Act are not subject to the Draft Rule.

New coal-fired EGUs would need to capture approximately 50% of the CO2 at the exhaust stream at startup to meet the CO2 Standard. Alternatively, the EPA is proposing a 30-year averaging compliance option that would be available for coal- and pet coke-fired Covered EGUs that did not install carbon capture technology at startup. Under this option, coal- and pet coke-fired Covered EGUs, with EPA’s approval, could comply with a less stringent CO2 annual limit for the first ten years of operation and a more stringent CO2 limit for the last twenty years such that on a 30-year basis, the facility would meet the CO2 Standard. The initial ten-year limit would be 1,800 lb CO2/MWh, which is the best demonstrated performance of a coal-fired facility without CCS. The CO2 limit for the following twenty years would be 600 lb CO2/MWh and beyond the 30th year, the source would be required to meet the CO2 Standard (i.e., 1,000 lb CO2/MWh).

  • Trading of Emission Credits to Meet the CO2 Standard

After the federal cap-and-trade program proposal failed on the national level in 2010, there has been speculation whether the EPA could allow for the trading of emission credits under the existing Clean Air Act. Some commentators interpreted the NSPS provisions in Section 111 of the Clean Air Act to allow EPA to authorize the trading of emission credits to meet a NSPS for greenhouse gases. This is based on the language of Section 111 as well as the fact that the EPA has explicitly determined that a cap-and-trade program constituted BSER for other non-greenhouse gas pollutants (e.g., mercury).[7] Without significant discussion, the Draft Rule states that no averaging or emissions trading among Covered EGUs would be allowed for the CO2 Standard and that each Covered EGU would be required to meet the CO2 Standard. As discussed below, whether trading may be authorized for regulating CO2 from existing power plants (either directly or through state equivalency determinations) remains an open question.

Sources Excluded from the Draft Rule

  • Modified Sources & Reconstructed Sources

Covered EGUs undergoing modifications that increase CO2 emissions and reconstructed sources are not required to meet the CO2 Standard under the Draft Rule. The EPA notes that it had insufficient information to develop a proposal for reconstructed sources or sources that undergo “modifications” that would normally trigger NSPS and subject the source to the CO2 Standard. The EPA states that most modifications that would increase the maximum achievable hourly rate of CO2 emissions would likely be related to the installation of pollution control equipment, which is an action specifically exempted from the definition of modification. Sources undergoing modifications or reconstructed sources would be subject to any future CO2 standards that are issued for existing sources (see further discussion below).

  • Transitional Sources

Notably, the EPA creates a new category of power plants – deemed “transitional sources” – in the Draft Rule. A transitional source is defined as a power plant that has received approval for its Prevention of Significant Deterioration (“PSD”) construction permit by April 13, 2012 (i.e., the date of Federal Register publication of the Draft Rule) and has commenced construction by April 13, 2013. The EPA justifies its exclusion of transitional sources from the Draft Rule based on gaps in information regarding the extent such sources have sunk costs and material commitments such that the CO2 Standard would not be considered BSER.

Approximately 15 power plants are expected to be considered transitional sources and thus not subject to the Draft Rule. The Draft Rule specifically notes that although transitional sources are exempted from the CO2 Standard, they would be subject to the requirements the EPA will promulgate for existing sources under Section 111(d) of the Clean Air Act, which is discussed in more detail below. In addition, a transitional source’s PSD permit may also contain CO2 limits.

Application of CO2 Standard to Existing Sources

The EPA projects in the Draft Rule that most new power plants in the U.S. will be natural gas-fired and thus not required to install any add-on technology to comply with the Draft Rule. Any new coal plant built in the U.S. will be required to install CCS in order to comply with Draft Rule but new coal plants that are not considered “transitional sources” (and exempted from the Draft Rule) are expected to be few, according to the EPA. Because there are hundreds of coal fired-power plants already constructed and operating without CCS, a significant issue will be the extent to which the Draft Rule will affect existing power plant sources.

  • Emission Guidelines for Existing Sources

The EPA emphasizes that the Draft Rule, promulgated pursuant to Section 111(b) of the Clean Air Act, does not affect existing power plant sources. While technically accurate, Section 111(d) of the Clean Air Act requires the EPA, after promulgating NSPS under Section 111(b) for pollutants like CO2 that are not regulated under the National Ambient Air Quality Standards (“NAAQS”) or as a hazardous air pollutant, to issue standards of performance for “existing sources”.[8] Specifically, Section 111(d) states that the EPA “shall prescribe regulations which establish a procedure under which each State shall submit . . . a plan which establishes standards of performance for any existing source for any air pollutant . . . to which a standard of performance under this section would apply if such existing source were a new source.” Because the EPA set NSPS for CO2 for new sources in the Draft Rule, it is obligated under Section 111(d) to set performance standards for CO2 from existing sources.

Under Section 111(d), the EPA issues regulations known as “emission guidelines” that establish binding requirements that the states must address in the development of their state plans. For the CO2 Standard, existing sources would include transitional sources as defined by the Draft Rule, modified sources, reconstructed sources and any other sources that are not new sources. Because many pollutants are regulated under the NAAQS or are hazardous air pollutants, there is little precedent for EPA’s actions under Section 111(d). When it has acted, the EPA has generally issued a model rule that can then be adopted by the states. For instance, for mercury emissions the EPA determined that a national cap-and-trade program was BSER for existing sources and issued a model rule establishing the program for adoption by the States.[9]

States must adopt the emission guidelines for existing sources through a state rulemaking action with EPA review and comment similar to the State Implementation Plan (“SIP”) process. The states and EPA may set less stringent standards or longer compliance schedules for existing sources considering cost of control; useful life of the facilities; location or process design at a particular facility; physical impossibility of installing necessary control equipment; or other factors making such variances appropriate. If the state fails to submit a satisfactory plan, the EPA has the authority under Section 111(d)(2) to prescribe a plan and to enforce the provisions of such plan.

If the EPA fails to address CO2 emissions from existing sources as required by Section 111(d), it could face additional litigation under the Clean Air Act as well as an enforcement action in connection with the 2010 settlement agreement, which required the EPA to issue emission guidelines for existing fossil fuel-fired sources.

  • Equivalent State Programs

Due to the absence of comprehensive climate change policy on the federal level, many states have already implemented programs aimed at controlling greenhouse gas emissions from power plants (e.g., Renewable Portfolio Standards (“RPS”), cap-and-trade programs, state-based CO2 emission limits for power plants). Several states and policymakers have indicated such programs should be considered equivalent to any emission guidelines for existing sources issued by the EPA. For example, the State of California has stated that its greenhouse gas cap-and-trade program that covers power plants should be considered for the purposes of applying the CO2 Standard under the Draft Rule to existing sources. Other commentators have noted that state RPS programs could be similarly treated. Due to the lack of precedent in the area, whether state-based greenhouse gas trading programs (or other state rules that control CO2 emissions) will be considered equivalent to the Draft Rule remains an open question. The EPA could issue a model rule setting forth the necessary requirements of any state program seeking equivalency or could work individually with states to approve programs that it deems would result in equivalent emission reductions.

Next Steps

The EPA is requesting public comment on the Draft Rule, and all comments must be received on or before June 25, 2012. The EPA will hold two public hearings on the Draft Rule on May 24, 2012 in Chicago and Washington, D.C. While the Draft Rule may be changed during the comment period, any power plant constructed after April 13, 2012 is required to meet the CO2 Standard, so it is essentially in force at this time. Regarding the timing of the EPA’s emission guidelines for existing sources, any regulation of CO2 from existing sources will be controversial. It is widely expected that the EPA will not issue a rulemaking for existing sources in advance of the presidential elections in November 2012.

Warm air down and cold air up: wind farms may affect weather

Esther Han

April 30, 2012 – 7:37am

As Australia turns towards renewable sources such as wind power in a bid to reduce carbon emissions, a study from the United States has found wind farms themselves may be affecting local weather and land surface temperatures.

An analysis of land surface temperatures of regions around large wind farms in Texas from 2003 to last year shows wind turbines can produce a night-time warming trend of up to 0.72 degrees per decade, researchers from the University of Albany in New York have found.

The researchers explained in the journal Nature Cli-mate Change that wind turbines acted like fans, pulling warmer “near surface air” from higher altitudes at night.

Liming Zhou, lead author of the study, said: “Typically at night there’s a stable atmosphere with a warm layer overlying a cool layer.

“Enhanced vertical mixing brings warm air down and cold air up, leading to a warming near the surface at night.”

NASA satellite data revealed a persistent upward trend of land surface temperatures, consistent with the growth in number of local wind turbines over the same time period. Mr Zhou concedes the warming effect could reach a stable level if no wind farms are built.

Wind power is Australia’s fastest-growing renewable energy source. Late last year, there were 1188 wind turbines in 57 wind farms in Australia.

Mr Zhou described the research as “small and local”, adding therefore the results should not be applied on a global scale or over longer time frames.

“We are now expanding this approach to other wind farms and building models to understand the physical processes and mechanisms driving the interaction of wind turbines and the atmosphere boundary layer near the surface,” he said.

He acknowledges wind power is part of the solution to climate change, pollution and energy security problems.

“Generating wind power creates no emissions, uses no water and is likely green,” he said.

“The research is critical for developing efficient adapting and management strategies to ensure long-term sustainability of wind power.” Professor Steven Sherwood, the co-director of the Climate Change Research Centre at the University of NSW, said the study was solid and made sense.

“Since at night the ground becomes much cooler than the air just a few hundred metres above the surface, and the wind farms generate gentle turbulence near the ground that causes these to mix together, thus the ground doesn’t get quite as cool,” he said.

“This same strategy is commonly used by fruit growers who fly helicopters over the orchards rather than windmills to combat early morning frosts.”

The University of Albany and the National Science Foundation in the US funded the Zhou study.

Earlier this year the NSW government announced a six-month noise audit at three wind farms, despite protests from the industry.

NSW Planning Minister Brad Hazzard announced the audit of Capital, Cullerin Range and Woodlawn wind farms, all in southern NSW, because of complaints from residents. The audit will also involve a questionnaire, meetings and a public information line, and will also consider other impacts such as “visual amenity, flora and fauna impacts, blade flicker, community contributions and electromagnetic interference”.

Read more:

Carbon capture ‘viable with long-term support’

18 April 2012 Last updated at 23:12 GMT

Gas-fired power station

The government’s new CCS competition allows entries relating to gas as well as coal generation

Continue reading the main story

Related Stories

Capturing and burying the greenhouse gas carbon dioxide from power stations is viable – but long-term government support will be needed, a report says.

Specialists in technology and economics spent two years researching the issue for the UK Energy Research Council.

The government recently announced a £1bn fund to help carbon capture and storage (CCS) develop; but the report says wider support is needed.

CCS is widely seen as an important part of a low-carbon electricity system.

“CCS is seen as the key to many scenarios of how to mitigate climate change, whether that’s the UK meeting its targets on cutting emissions or global targets that keep warming below 2C,” said the report’s lead author Dr Jim Watson, director of the energy research group at Sussex University.

“But unlike other low-carbon technologies, CCS doesn’t exist at the commercial scale. We don’t know when they will be technically proven at full scale, and whether costs will be competitive with other low-carbon options.

“So it is vital that the government’s commitment leads to several full-scale CCS projects as soon as possible; only through such learning by doing will we know whether it is a serious option for the future.”

Continue reading the main story

“Start Quote

Levels of interest from business are phenomenal, despite the years of prevarication”

End Quote Matthew Spencer Green Alliance

Other countries including Germany, Norway, the Netherlands, the US and China are also exploring the technology.

The government opened its first competition for CCS funds in 2007, but abandoned it four years later when the last contender – the Longannet coal-fired power station near Edinburgh – withdrew, saying the economics did not work out.

The new government scheme is far more flexible over what types of technology are eligible for funding, which the report says is the right approach.

Equally, it says, the single £1bn fund will not be enough to take the industry from its current fledgling state to the government’s target of having 10GW of UK generation capacity equipped with CCS by 2030.

Leadership chance

Equipping coal- and gas-fired plant with CCS makes them considerably more expensive to run.

The plant itself becomes less efficient, meaning more fuel has to be burned to produce the same amount of electricity.

CCS-fitted stations could form part of a low-carbon mix alongside nuclear and renewables

The CO2 must be transported to its resting place – probably in liquid form through a pipeline – and a disposal site must be properly explored beforehand and monitored afterwards to make sure nothing escapes.

The report says the economic incentives for this extra investment will have to come from reforms to the electricity market that the government is working out at the moment, designed to supply additional and enduring support through guaranteeing prices for low-carbon electricity.

It also says the UK is well placed to lead the global market in skills and technology, and perhaps even sell some of the copious storage capacity that exists below the UK seabed to other countries.

“The UK has a huge amount of potential storage, amounting to about 700 years worth of emissions,” said another of the report’s authors, Prof Stuart Haszeldine from Edinburgh University.

“But that is as yet unproven; and no commercial company is going to go ahead and build a CCS facility costing maybe £1bn if they don’t know they’ll be able to inject CO2 for 30 years into that site.”

Proving that a site is suitable for CO2 storage needs the same type of exploration needed in oil and gas exploration, he said – and investigating a single site could cost hundreds of thousands of pounds and take five to 10 years, meaning that a programme for doing it should be developed soon.

The government will also have to work out rules on liability for leakage, he said, that are fair to both companies and the public purse.

Matthew Spencer, director of the Green Alliance, which produced its own analysis of CCS recently, agreed that investors needed support and confidence.

“Levels of interest from business are phenomenal, despite the years of prevarication,” he told BBC News.

“We’ve lost a lot of time, and investors have to have much more certainty now if we’re not to lose them; but we do have a good story in the UK of a rapidly growing industry.

“If the government pulls out the stops, we think 10GW is feasible.”