The launch

Sir John Houghton, former co-chair of the IPCC and former chief executive of the Meteorological Office, began by saying that there are questions regarding the extent of the Conservative party’s commitment to the fight against carbon change and then gave a quick synopsis of the current state of climate science and the massive impacts that unchecked global warming will have. He made it clear, that even excluding “basic physics”, there is a lot of evidence that global warming is occurring and made the point that the isotope signature of fossil fuels makes it relatively easy to determine the impact their burning has on atmospheric CO₂ levels. He declared that the few errors in the recent IPCC report had been exaggerated, that the mistake made concerning the melting of the Himalayan glaciers had started out as a typo and that “those who wish to discredit the IPCC should be discredited themselves.” Sir John agreed with one delegate that “actually the IPCC has been too cautious,” as it has not estimated several factors such as the extent of melting in Greenland. When queried as to the cost of the measures needed to rein in climate change, he pointed to an IEA report, that indicates that between now and 2050, the world will need to spend six per of GDP on energy, and that keeping the concentration of CO₂ in the Earth’s atmosphere at 450ppm (the level needed to reduce the chance of the earth warming above two degrees Celsius), would cost an additional one per cent of GDP, but would result in roughly the same in fuel savings, while delivering many additional benefits such as reduced pollution and enhanced energy security.

If there is one overriding theme within the bill, it is a “softly, softly approach”. Under the latest proposals, industries will not be involved in cap-and-trade scheme until 2013, with heavy industry following in 2016, while the overall emissions reductions goals are noticeably backloaded, with the vast majority of cuts scheduled to occur over the 2020-2050 timeframe. Its goal is to “reduce economy-wide global warming pollution to 95.25 percent of 2005 levels by 2013, 83 percent by 2020, 58 percent by 2030, and 17 percent by 2050.“

The bill like Waxman-Markey does include provisions designed to protect domestic industries from foreign competitors. In addition, while it will allow up to 2bnt of offsets annually, individual businesses will only be able to use offsets purchased from the international markets to account for only 25 per cent of their annual emissions and 1.25 of these offsets will have to be surrendered per ton of CO₂, compared to just one domestic credit. While this will still mean that foreign companies will be able to benefit from the proposed scheme, it will help to keep the costs of mitigation down and help create a domestic carbon offset industry, which could have significant positive implications for the environment, particularly in the form of reforestation.

An important difference between the two bills is which organisation would be given the role of overseeing the new carbon market. Waxman-Markey would place the Federal Regulatory Energy Commission in charge of oversight, while Kerry-Lieberman would give the power to the Commodity Futures Trading Commission. Of the two, the later seems to make more sense, given its natural expertise in this area.

From the perspective of power utilities, while it is clear that the American Power Act will be a game-changer, its impact will vary from company to company, depending on its particular portfolio of generating technologies. It could also be argued that it will only serve to accelerate the current trend away from coal and towards natural gas, which is being driven by increasingly vocal opposition to new coal-fired power stations and the rise of shale gas. Given that if passed, the act would replace regional carbon cap-and-trade schemes, such as the Regional Greenhouse Gas Initiative (RGGI) and the Western Climate Initiative (WCI), it could potentially alleviate headaches and unnecessary administrative expenses for the largest utilities.

The Act includes a whole section dedicated to enabling new nuclear build in the US. Measures include a boost to the funding for the Innovative Technology Loan Guarantee Program to US$54bn from US$18.5bn and an amendment to the Energy Policy act of 2005 to provide regulatory risk insurance for up to 12 reactors rather the current six. In addition, there are a range of new tax provisions, including an investment tax credit for nuclear power facilities, that would provide “a ten percent credit for certain expenditures for the construction of nuclear power facility construction”.

There is also a clause for the extension of a suspension on tax duty for “certain components used in nuclear facilities that are not available in the United States” for another 10 years, a tacit admission that the domestic supply chain is incomplete and in all likelihood cannot be ramped up in time. This is of course, a hangover from the Three Mile Island incident and the resulting absence of new nuclear build over the past few decades.

The act sets out a truly ambitious vision for carbon capture and sequestration (CCS), both in terms of scale and funding. Up to 20GW of generating capacity is envisaged to be eventually using this technology, with the first 10GW, obtaining between US$50-96 per ton of CO₂ sequestered (dependent on the proportion of the facilities emissions being sequestered), with an additional US$10 premium if submissions for a large scale commercial plant are made no later than the start of 2012. The second tranche of CCS plants would then receive between US$50-85 per ton sequestered. These proposals may seem somewhat generous, but when one considers the logistical efforts needed to pump millions of tonnes of carbon dioxide underground, even if they are successfully brought into action, might not be enough to guarantee the successful deployment of CCS in the US, at the skill envisaged by the act’s proponents.

Not much of a free market?

A pertinent question might be whether the complex apparatus required for a carbon market is necessary, given the relatively tight trading limits that the American Power Act would impose. It has set out a reserve price for 2013 allowances at US$12 in constant 2009 dollars, rising at three per cent above inflation per year, with a price cap at US$25 per ton rising at five per cent above inflation per year. In addition, as pointed out by the Natural Resources Defence Council (NRDC), the bill is proposing that only one-quarter of emission permits will be auctioned in the first few years of the scheme. Part of the issue is that a bill of this nature is inherently one of compromise, but as we have seen from the emissions trading scheme in Europe, past a certain point, there is the danger of too much slack in the market, resulting in a price collapse. While the presence of a price floor will prevent a complete price collapse, it is easy to imagine a scenario in which for many years, the price of carbon barely flutters above this level.

As a result of the above, it is hard to see what immediate advantages a cap-and-trade system would have over a flat carbon tax. The latter option would certainly provide more certainty for investors and less opportunities for speculators to make a killing. On the other hand, as the Environmental Protection Agency has pointed out, cap-and-trade has been a success in the US before and is largely responsible for bringing down SO_x and NO_x emissions to acceptable levels. The main differences are those of scale and the fact that while SO_x and NO_x are indisputably pollutants hazardous to human health, the impact of CO₂ emissions on the environment is unfortunately far less of an accepted orthodoxy, despite the weight of scientific evidence linking it to global warming.

No matter how many provisions the bill includes to benefit industry, boost carbon capture and sequestration and nuclear power, it will still be a hard sell to republicans, given that the party line has recently shifted towards viewing it as an unacceptably high tax on jobs. A key issue are upcoming congressional elections later this year, coupled with the growing popularity and power of the Tea Party, which is rapidly shifting towards outright climate change scepticism. This to some extent mirrors a similar trend in the country as a whole. A Rasmussen poll conducted in April, indicated that 40 per cent of US voters believe that the threat of global warming is not serious, with nearly half believing that it is caused by “long-term planetary trends”. In addition, there is the wider political game to consider. The opposition always has a vested interest in preventing the incumberant administration from passing legislation and this is likely to coincide with the interests of a large number of pressure groups and lobbyists, particularly from major coal producing states.

The bottom line

Given that the economy is also a key concern for democrats, many senators and congressmen are starting to feel less secure in their positions as the initial gleam of the Obama administration continues to dissipate, the possibility of a delay to 2011 is not out of the question, particularly given the narrow window of opportunity that exists between now and the Independence Day national holiday. Senators Kerry and Lieberman will need a majority of 60 to make the Act filibuster-proof and prevent amendments from detractors aimed at watering down their proposals or killing it off altogether.

On the other hand, Senator Kerry argues that the backing behind the Act is “uncommon and unparalleled”, making it a “relatively easy vote” for senators to make. He and his team also seem to be happy to play “good cop” to the Environmental Protection Agency’s “bad cop”, given that the agency would probably end up with jurisdiction over CO₂ emissions if a bill failed to pass. This would undoubtedly be unwelcome given republican distaste for greater executive power, while at the same time, effectively giving many industries their medicine without the spoonful of sugar promised by the American Power Act.

One of the fiercer arguments underway is whether the Act’s positive impacts on the US economy outweigh the negative, particularly in terms of job creation. A policy brief from the non-partisan Peterson Institute for International Economics, suggests that it could lead to an increase in average annual employment in the US by 203,000, over the 2011-20 period, partly due to the significant incentives created for the construction of newer, less polluting power plants. However, it goes on to argue that as the US economy is expected to return to full employment after 2020, this additional demand for workers, coupled with the gradual move towards full auctioning of carbon allowances is likely to add to inflationary pressures, so that “The net effect is that after 2025, some of the employment gains in the first decade of the program are clawed back, bringing the 2011-30 average back in line with business as usual (average annual employment is 6300 jobs higher than business as usual across the full two decade period modeled). It also indicates that it would push US oil imports by 33-40 per cent below current levels and 9-19 per cent below a business as usual scenario by 2030, effectively cutting US spending on imported oil by US$51-93bn per year. It would also result in a 2-5 per cent increase in energy prices for households over the 2011-2020 period and a 3-7 per cent increase between 2021 and 2030.

While there remains consider doubt as to whether the Act will pass in anything approximating its current form, particularly given the messy cross-over process between Senate and Congress that is an integral part of the US legislative system, it does give considerable insight into what the future pay hold for the US energy sector. Hopefully, a climate change bill in its final form will deliver the framework America desperately needs if it is to wean itself off foreign oil and start to rein in its greenhouse gas emissions.

In this article, IFandP considers the potential impacts of a tightening water demand/supply balance in many key regions and the potential impact of new technologies

It is a fundamental truth that in today’s world, energy and water are inextricably linked. But with increasing demands for agriculture, natural gas extraction and power generation, water management is becoming increasingly important, to the extent that in future, power utilities may find themselves increasingly having to work to reduce their water footprint to receive the go ahead for new build.

As can be seen from the table below, there are some real issues. While wind and PV solar offer substantially lower water usage than thermal power generation, the same cannot be said for concentrating solar power (CSP) and there are concerns that carbon capture and sequestration systems will significantly boost waste usage at coal and natural gas-fired power plants. However, there are some technological solutions that might be able to improve the situation.

A case in point is Solar Millenium LLC, which is looking to use advanced dry-cooling systems for its two CSP projects to be located near Las Vegas, each requiring an investment of over US$1.5bn. The system requires significantly less water than conventional water-cooling systems. As far as CCS is concerned, there exists significant potential for greater water efficiency. For example, Fluor’s Econamine FG Plus system features a patented flue-gas-conditioning system that recovers combustion water for reuse in the power plant, potentially recovering around 1500gal per day per kW.

After an introduction and welcome by Michael Manley, Assistant Secretary at the Ministry of Science, Technology & Innovation and Natural Resources, and Professor Nicholas Canny, the academy’s President. Scott Brocket of the European Commission gave the European context for CCS. In the last two years, the EU has made progress in CCS policy as it adopted a regulatory framework in the form of CCS Directive 2009/31/EC as well as providing for a stimulus in CCS demonstration projects.

Ken Macken of Ireland’s Environmental Protection Agency and J Owen Lewis of the Sustainable Energy Authority of Ireland added further context as they discussed climate change, mitigating action and CCS in a low-carbon future, focusing mainly on Ireland.

The Royal Irish Academy assembled a variety of expert speakers: Emile Elewaut (TNO The Netherlands), Richard Vernon (SLR Consulting), RIA President Nicholas Canny, John Barry (Shell), Peader McArdle (GSI).

The morning’s session was rounded off by Dr John Morris of the Geological Survey of Ireland who gave an overview of carbon storage options.

In the second session of the day, keynote speaker Dr Jens Hetland of SINTEF Energy Research, Norway, discussed the three main routes for CO₂ capture and the status of technologies as well as mapping out various CCS projects around the world by technology, size and timeline. He also touched upon the typical cost of CCS related to early commercial projects in Europe.

Pat Naughton of ESB Power Generation explained the role of CCS in power generation. ESB’s vision is for the organisation to have a net carbon neutral generation fleet in Ireland by 2035. Mr Naughton pointed out the need for stable regulation and licensing, appropriate support mechanisms and public acceptability and stressed the importance of collaboration between industry, academia, policy makers and other stakeholders.

After the coffee break, Dr Robert Finley (University of Illinois), Professor Stuart Haszeldine (University of Edinburgh) and Emile Elewaut (TNO, The Netherlands) gave examples of strategies and technology relating to carbon storage, each from their perspective. Robert Finley took the listeners through permitting and developing the 1Mt geological sequestration test in a deep saline reservoir at Decatur, Illinois, USA, while Stuart Haszeldine gave a UK overview on storage. Currently, work is underway to evaluate selected aquifer stores in detail and researching a more specific capacity evaluation of all UK offshore sites. Emile Elewaut closed the day’s sessions with an interesting presentation regarding North Sea strategies and explained how the Dutch are considering the storage potential of their depleted gas fields. However, for this to be a viable solution, the country’s regulatory framework would need to be adjusted as well as solving problems relating to the timing between closure of some gas fields, connecting trunk lines and CO₂ storage potential.

In a session sponsored by the Irish Times, Jeff Chapman of the CCS Association, Stephan Singer (WWF) and Dick Ahlstrom, the Irish Times' science editor debate the issue of carbon capture and storage in Ireland.

In the evening, RIA teamed up with the Irish Times to play host to Jeff Chapman of the CCS Association and Stephan Singer of WWF for a thought-provoking debate on the impact of CCS on climate change.

The following day, Richard Vernon of SLR Consulting kicked off the CCS as a business session, outlining the Irish regulatory and business environment for CCS. His presentation was followed by Frank Convery, University College Dublin, who gave a European viewpoint to the carbon market. Shell’s John Barry represented the energy company’s perspective. Donnchadh Irish of ESB International, shared his experiences of his trip to China as he gave a Chinese perspective on carbon capture.

The Sleipner project came under close scrutiny as Andy Chadwick of the British Geological Survey kick-started the session on monitoring, regulation and research. The issue of monitoring is a crucial one in the success of CCS as reliable monitoring processes will help to get CCS accepted by the public as a viable option in reducing atmospheric carbon dioxide. Chris Bean of the University College Dublin appraised the audience of the latest advances in research on monitoring and verification. Peter Croker of the Department of Communications at Energy and Natural Resources brought attendees back to Ireland and the opportunities and constraints of offshore CCS while Michael Tutty of the Commission for Energy Regulation touched upon the issues of regulation and long-term stewardship.

In the afternoon, the organisers had lined up four more speakers which would shed light on the challenges facing Ireland in implementing CCS. John Ludden of the British Geological Survey brought the audience up to speed regarding CCS research opportunities. Richard Tol of the Economic and Social Research Institute detailed CCS economics in an Irish context. David Reiner (Judge Business School, University of Cambridge) gave an informative and highly entertaining talk on public awareness of CCS issues, stressing the importance of public acceptance of the technology in its successful implementation.

The final session of the conference was given to Bob Hanna of the Department of Communications, Energy and Natural Resources, who suitably rounded off two days’ presentations by clarifying the Irish position on CCS and looking into the future.

Successful implementation of CCS will have to overcome a number of barriers. There are not only technological challenges, but also economic and political ones. As for now, raising awareness on the issue of CCS appears a key element in its progress and RIA’s conference has been a step in the right direction.

On June 19, 2008, at a media event held at the Port of Long Beach, test results were announced regarding the cleaning of diesel emissions using Cloud Chamber Scrubber (CCS) technology developed by Tri-Mer Corporation, Owosso, Michigan. The emissions tests covered all sources originating from ships at dock, including auxiliary engines, boilers, and on-board power generators. Barry Wallerstein, executive director of the South Coast Air Quality Management District (AQMD) was a prominent speaker at the meeting. The roster included Wayne Nastri, Region 9 administrator for the US Environmental Protection Agency (EPA).

The Cloud Chamber Scrubber (CCS) achieved reduction rates that effectively establish a new standard for the treatment of high-volume diesel emissions. Performance efficiencies of the CCS, detailed at the event, were high for all target pollutants:
• particulate matter: 98 per cent reduction
• SO₂: 99 per cent reduction
• NO_x: 99 per cent reduction

The Tri-Mer CCS uses patented, “charged droplet” technology to remove particulate matter (PM) and SO₂ pollutants. Diesel particulate is less than 0.1 micron in size and is one of the most difficult particulates to control. The CCS employs a special pre-conditioning process that allows particles to ‘grow’ through adsorption and agglomeration and subsequently be captured in the next stages of the CCS by the charged droplets. The pre-conditioning stage simultaneously removes the SO₂.

NO_x is treated by a selective catalytic reduction (SCR) module which is a factory-integrated option of the CCS system. PM and sulphur that might impede catalyst efficiency and service life are removed prior to NO_x treatment, so exceptional results are consistently achievable.

Tri-Mer Corporation provided all the air pollution control technology, including controls and integration of the SCR. Equipment engineering and manufacturing were completed at its Michigan factory. Tri-Mer also helped coordinate installation and demonstration of the technology. Advanced particulate characterisation equipment was used to calibrate the CCS system. The government agencies and other stakeholders at the port contracted with an independent third-party testing company and laboratory to provide standard testing and analysis of PM, SO₂ and NO_x for independent verification. The ship exhaust was brought to the dock-side CCS system using a capture device that fits over a variety of ship smokestack configurations and was developed by ACTI (Rancho Dominguez, CA), the environmental company that funded the demonstration projects and is offering complete dock-side solutions, including its Advanced Maritime Emissions Control System (AMECS), which is composed of capture equipment coupled with CCS treatment technology.

With the successful demonstration test at the Port of Long Beach, and a similar demonstration on diesel locomotive emissions at Union Pacific, Roseville, California, CCS is now regarded as the first technology to prove consistently-high removal efficiencies when operating at the flow volumes typical for large diesel engines.

The CCS provides a solution to a long-standing problem in controlling diesel emissions near ports, rail yards, and other sources of high-volume diesel emissions. In 2007, The Port of Long Beach, California, handled more than 7.31m containers, and more than 87Mt of cargo. The ports of Los Angeles and Long Beach together account for more than 40 per cent of all containers entering the US.

Idling ships accounted for 1.8stpd of diesel particulate matter (PM) state-wide in 2006, according to the California Air Resources Board, while cargo ships, some of which can emit more diesel exhaust per day than 12,000 automobiles, are responsible for much of the air pollution in the region. They are a leading source of NO_x, SO_x and PM, which have been linked to premature deaths, respiratory illnesses and global warming in many port areas. Moreover, commercial ships, en route and at port, release more SO₂ and particulates than all of the world’s cars, trucks and buses combined, according to a study released in March by the International Council on Clean Transportation, and quoted in a Wall Street Journal article on November 27, 2007. The study further found that ships produced an estimated 27 per cent of the world’s NO_x emissions.

In November 2007, a study in the American Chemical Society’s journal Environmental Science and Technology estimated that under-regulated air pollution from ships results in 60,000 deaths from lung cancer and cardiopulmonary disease each year, primarily along trade routes in Asia and Europe.

CCS technology

The cloud chamber scrubber treats PM2.5, fine, submicron, ultrafine, and condensable particulate as well as PM10 and more coarse particles. It removes any gas treatable by a wet scrubber, including HCl, NO₂, SO₂, Cl₂, NH₃ as well as HF, H₂SO₄, HNO₃, ammonia and amine compounds. This is important because, for the first time, one device can handle particulates and corrosive fumes simultaneously.

CCS is based on new patented discoveries in electrofluidics. It offers proven submicron performance at efficiencies typically greater than 99 per cent thanks to its capability to efficiently ‘grow’ and capture particles smaller than 0.1 micron. It is also highly energy-efficient, requiring just 10W/1000cfm to charge the water droplets, plus moderate pump power for water recirculation. It operates with ultra-low water usage. CCS generates less than 1.5in wg pressure drop across the system. Gas temperature, particle solubility, resistivity, and reactivity have minimal affect on performance. CCS accommodates heavy loadings and is not sensitive to load flux.

Industrial boilers

Tri-Mer’s CCS also lends itself to industrial boilers, particularly those with flow rates of 200,000acfm or lower. In the US, the EPA requires all boiler units with a greater than 10mBtu/h heat input located at major sources of hazardous air pollutants, to be compliant with boiler Maximum Achievable Control Technology (MACT) standards. These dictate limits for PM, HCl, CO, SO₂, Hg and other heavy metals. The current MACT standard was vacated by the courts in 2007.

The situation has been complicated by a tug-of-war between the National Association of Clean Air Agencies (NACAA) and the Council of Industrial Boiler Owners (CIBO). The former represents air pollution control agencies in 53 states and territories and over 165 major metropolitan areas in the US. NACAA has been seeking to have the EPA adopt its model rule, which was released on June 10. This requires tougher standards than those currently required by MACT, but removes the need for case by case reviews. Because the MACT system requires the EPA to set a floor determined by the top 12 per cent of sources, the NACAA has said that if its model is adopted, then the next MACT will be forced to use the stricter limits as its emissions floor. The move attracted criticism from CIBO as the organisation believes the standards are unachievable for the vast majority of sources. This claim has been contradicted by the Institute of Clean Air Companies, which represents the interests of pollution control equipment manufacturers.

Due of the above, a new boiler MACT standard is expected in the summer of 2009 and is widely believed to place more stringent limits on emissions.

As can been seen from Table 1, Tri-Mer’s CCS system reduces the levels of these pollutants to far below that required by current MACT standards for both existing and new industrial boilers. As a result, it is anticipated that existing CCS users will be not be inconvenienced by the introduction of tighter air quality standards.

For more information on the CCS and other emissions reducing technologies, consider visiting www.tri-mer.com or contact Kevin Moss at: kevin.moss@tri-mer.com

The news surrounding carbon trading these days is increasingly dominated by the EU ETS, the rapid growth of the industry along with a tidal wave of warnings, dire proclamations and opinion pieces about the effect Australia’s proposed carbon trading scheme will have on its economy. Meanwhile, the UN’s Clean Development Mechanism (CDM) has been quietly getting on with the business of incentivising the use of clean technologies in the developing world. It has now registered some 1170 projects in 49 countries.

The mechanism exists as an arrangement under the Kyoto Protocol and allows OECD countries which have committed to reducing their greenhouse gas (GHG) emissions (known as Annex 1 countries) to invest in projects in developing countries which have not signed up to any limitations on their emissions. The difference in GHG emissions can then be banked as Certified Emission Reductions (CERs) and can subsequently be sold to parties looking to offset their own emissions. The cost of mitigating GHG emissions via CDM projects is typically lower than attempting to make similar savings in developed countries for a variety of reasons. These include the cost of labour and the fact that many of the easy and relatively inexpensive measures to mitigate emissions have already been taken in Annex 1 countries. To prevent nations from relying completely on the CDM and CERs to meet their obligations, a provision in the Kyoto Protocol dictates that CDM can only be used to supplement domestic measures.

The CDM is overseen by the United Nations Framework Convention on Climate Change (UNFCCC) and the CDM Executive Board. The latter has the task of setting and revising the methodologies used to determine whether a proposed project qualifies for support under the scheme. All projects must demonstrate additionality. This is currently interpreted by the CDM Executive Board as meaning that the proponents of a project must show that in the absence of inclusion within the CDM, more polluting alternatives would be more favourable economically.

The process by which a project acquires approval is quite complex. First, a country in need of CERs (the applicant) obtains permission from the developing country that will host the project. The applicant must then establish the case for additionality and has to generate a baseline for future emissions in a scenario where the project does not go ahead. A third-party agency, known as the designated operational entity, then validates the project. The CDM Executive Board then decides whether it will register/approve the project.

The CDM is, to some extent, becoming a victim of its own success. The World Bank issued a report in June, highlighting that of the 3188 projects in the pipeline, 2022 were awaiting validation and that it took an average of 80 days to go from the project registration request stage to actual registration, while it also took participants up to six months to engage a designated operational entity. The UNFCC is therefore looking to further streamline the process by introducing an approach called programmatic CDM, which would clear a number of related projects at the same time.

Figure 1: A) CDM projects by sector. B) CDM projects by sectors expressed in terms of CERs issued. Source: UNEP Risø centre, October 1, 2008

As can be seen from Figure 1, there are many different types of CDM projects. Interestingly, although the majority (63 per cent) employ renewables, these result in only 13 per cent of the mitigated emissions. Yet at the same time, HFCs, PFC and N₂O reduction projects make up only two per cent of the projects currently registered by the CDM but are responsible for a massive 74 per cent of all CERS issued.

This phenomenon has attracted fierce criticism of the CDM. HFCs (hydrofluorocarbons) are extremely potent greenhouse gases and are a by-product of refrigerant factories. The issue is that destruction of HFCs is extremely cheap, and the costs pale in comparison to the potential profits from the sale of CERs, leading many to question as to whether the CDM is really providing value for money. The situation has also created a perverse incentive to open new refrigerant plants. Fortunately, the UNFCC amended the rules, so that only existing plants can benefit from the scheme. In terms of geography, four countries dominate the market in CDM generated CERS. These are China, India, Brazil and Mexico. At the start of the scheme, they accounted for around 50 per cent of all projects, but this figure has now risen to around 75 per cent. While China hosts slightly more projects than India, it supplies over three times as many CERs. This is for one very simple reason: the cost of mitigating emissions in China is lower than in any other country.

China’s dominance is demonstrated by the fact that all of the top 10 projects registered in the past year, in terms of GHG emissions mitigated, are located within its borders. They fall into two main categories: N₂O/HFC reduction and fuel switching from coal to natural gas. One of the quirks about the latter is that the CDM is thought to be one of the reasons why the Chinese government has not pressed for tighter environmental standards. However, this has still happened in other areas; coal bed methane being a prime example. Since the government introduced measures making the use of coal bed methane and gas from landfill mandatory, projects based on exploiting these resources can no longer fulfil the additionality clause as set out by the CDM Executive Board.

As far as the whole of the CDM is concerned, 2008 has see a large increase in coal to gas fuel switching. Over 4400MW of Asian power capacity was registered under the scheme in 1Q08, compared to 1741MW registered in the same period in 2007 and the 7538MW registered over the whole of last year. Of the 1Q08 total, more than 80 per cent was natural gas-firing.

Top 10 projects

1. PetroChina’s N₂O decomposition project, Liaoyang
Estimated GHG reductions: 10.017Mta
This is by far and away the largest CDM project registered this year. PetroChina is looking to install a catalytic decomposition facility to reduce the N₂O emissions generated from the production of adipic acid, which is used both as a food ingredient and in the production of polyurethane. The company argued in its application that given the lack of a market for N₂O and the absence of regulations governing its release in China, without CDM registration, there was no economic rationale for the development to proceed. Indeed, PetroChina calculated that without the ability to sell CERs, the net present value of the project would be -US$48.33m.

2. Changshu Haike HFC23 decomposition project
Estimated GHG reductions: 3.473Mta
Changshu Haike, a Sino-French joint venture, was looking to install a thermal oxidation facility from VICHEM, a French technology supplier, in order to reduce the HFC23 emissions from its HCFC22 production plant, in Changsu City, Jiangsu Province, which has been in operation since May 2000. The process requires heating to above 1200^oC, but as HFC23 is such a potent GHG, the emissions produced by fuelling the facility are more than outweighed by the elimination of HFC23. According to project documentation, 65 per cent of the revenues from the sale of CERs will go to the Chinese government to support its sustainable development facility.

3. Baotou Iron & Steel Blast Furnace combined cycle power plant project
Estimated GHG reductions: 1.871Mta
This 300MW power plant will run off blast furnace and coke oven gas. In the absence of the plant, 30 per cent of the gases from the blast furnace would be flared. By using them to produce electricity, less coal has to be burnt in existing power stations.

Also part of the rationale behind the inclusion of the project within the CDM, is that as an iron and steel company, Baotou’s investments typically have to generate a 13 per cent rate of return, compared to the eight per cent required by power generation projects and the 10.06 per cent projected for the project in the absence of CDM finance. This would rise to 16.46 per cent with CDM approval. In addition, the use of blast furnace gas poses significant technical barriers, which the company argued would be reduced by CDM registration. The resulting expertise could then be transferred to similar projects.

4. Beijing Taiyanggong CCGT trigeneration project
Estimated GHG reductions: 1.516Mta
Beijing Taiyanggong Gas-fired Thermal Power Co is seeking to install and operate a 780MW grid-connected natural gas CCGT power plant, which would supply power to Beijing’s electricity grid and provide waste steam for heating and cooling to the surrounding area, allowing the removal of 78 low-efficiency boilers. The major selling point was that it offered substantial savings in GHG and other pollutant emissions compared to a business-as-usual, coal-fired generation approach. As with the project at Baotou, the relatively poor internal rate of return (IRR) was also given as a reason for CDM assistance. The project document indicated that there were three other natural gas-fired power plants in the Beijing area applying for CDM registration and argued that this a sign that additional finance is needed for gas-fired generation in China.

5. Shanghai Baoshan grid-connected natural gas combined cycle power plant
Estimated GHG reductions: 1.43Mta
This project intends to build three 400MW CCGT units to boost Shanghai’s peak-load balancing capacity by 10 per cent. Again, the baseline scenario involved the building of a coal-fired power plant and the low IRR in the absence of CDM funding was highlighted. Estimates for the power station included a rated thermal efficiency of 57.21 per cent and a 92 per cent load factor. GE has been selected as the equipment supplier for the plant. The application made it clear that the Shanghai market is adequately supplied with gas currently and this is expected to remain the case for the foreseeable future.

6. Zhenhai Provincial Energy Group’s natural gas generation project
Estimated GHG reductions: 0.937Mta
and
7. Zhejiang Southeast Electric Power Co’s natural gas power plant in Xiaoshan
Estimated GHG reductions: 0.937Mta
Both these projects are for the construction of natural gas power plants to be owned by the Zhejiang Southeast Electric Power Co and will supply the East China Power Grid (ECPG), which provides electricity to the provincial grids of Shanghai, Jiangsu, Anhui and Fujian. The first project will install two CCGT units with a total rated capacity of 795.6MW, while the second is for two 403MW CCGT units.
In addition to reducing GHG emissions, the project’s backers made the case that they would also reduce the levels of other pollutants compared to a business-as-usual scenario, improve the peak-load balancing of the grid and provide employment for the local people. Again, coal-fired generation was used as the baseline and the poor IRR was used as the rationale for CDM financing, in both cases.

8. Liuzhou Chemical Industry Co’s N₂O abatement project
Estimated GHG reductions: 0.902Mta
The aim of this project is to reduce N₂O emissions from five nitric acid plants, which produce 454,080tpa of acid and currently emit around 3250tpa of N₂O. Liuzhou is looking to use equipment provided by Sumiko Eco-Engineering and NE Chemcat, to decompose over 90 per cent of the emissions. Their technology has yet to be fully commercialised, even in developed countries. The project is sponsored by another Japanese company, Mitsubishi Corp. Like project number two in our list, the Chinese government will receive 30 per cent of the CER revenues generated by this venture. Due to the low temperature of the tail gas, some additional heating is expected to be needed and this will come from burning purge gas (methane and hydrogen) from an ammonia plant within the factory.

9. Yuyao natural gas power project
Estimated GHG reductions: 0.805Mta
Zheijang Guohua Yayo Fuel Gas Power Generation Co, is also seeking to build more peaking capacity for the ECPG. According to the project documents, the ECPG is expected to install 40GW of capacity in order to meet the region’s rising demand for electricity.

The company is looking to do its part by installing and operating a 780MW CCGT, supplied by GE. This project, along with numbers 7 and 8 on our list, highlights that the area is unsuitable for stored hydropower due to the lack of water resources. In addition, what potential does exist in the region for economically viable hydro projects has already been utilised, while nuclear is not an option for peak demand-balancing plants.

10. Henan Zhengzho grid-connected natural gas combined cycle plant.
Estimated GHG reductions: 0.692Mta
This is another peak load-balancing gas-fired proposal. Zhenghzhou Combined Cycle Power Co intends to build two 390MW CCGT units, which will serve the Henan provincial grid and through it, the Central China Grid. The equipment is being provided with Siemens, which also has a maintenance service agreement to ensure that the plant achieves optimal performance during the project operation.

Value for money?

It is clear that as far as China is concerned, the CDM is working to encourage cleaner forms of power generation. However, its efficiency is somewhat questionable, given the fact that CDM financing propels power projects well above the benchmark set by the Chinese government (see Table 1). In addition, one can’t help but wonder how the situation would change if the government were to relax its control on electricity prices. There is also the problem that the CDM offers a compelling financial incentive for the government to not introduce tighter environmental regulations, such as a ban on the release of HFC23 and N₂O as this would eliminate the additionality required by the CDM. Such a move would, however, be by far the cheapest way to improve the environment in this arena.
As for the future of the CDM as a whole, a very great deal depends on the successor to the Kyoto Protocol, which expires at the end of 2012. The negotiations over what form it will take are likely to be extremely heated, with the US expected to press for China to commit to some form of hard target, a move which the Chinese government has bitterly opposed. The US itself is also important to the future of the CDM, as it could well become its biggest customer, if a cap-and-trade scheme is introduced by the next president.

The World Bank has predicted that the uncertainty regarding the future of the CDM will lead to slowing growth in a sector which has rapidly increased in value, doubling in the last year to US$13bn. It expects the number of projects under the scheme to barely grow in 2008, before reaching almost zero in 2010. Let’s hope then that the sequel will make up for any lull and at the same time overcome many of the more glaring problems from which it currently suffers.

For more information, consider visiting the following websites:
http://cdmpipeline.org/
http://cdm.unfccc.int/index.html
http://cdmbazzar.net/

Part of the growing pressure on the industry as a whole comes from the recent announcement that CO₂ emissions from shipping are almost three times higher than previously thought. The UN report, which was leaked to the UK’s Guardian newspaper, indicated that the world’s merchant fleet is already generating 1.12bnt of CO₂ a year, equivalent to almost 4.5 per cent of the world’s CO₂ emissions. In addition, the report predicts that this figure, as well as the sulphur and soot emissions associated with shipping, are likely to increase by 30 per cent by 2020.

Moreover, the industry produces seven per cent of the world’s SO_x emissions and 11-12 per cent of all NO_x,according to Lloyd’s Register Quality Assurance and the German government’s scientific advisory body – WGBU 2002. Furthermore, bunker fuel, also know as heavy fuel oil (HFO) contains polycyclic aromatic compounds, which are carcinogenic in nature. Indeed, HFO is itself classified as a carcinogen and a peer-reviewed study, published in November 2007, indicated that particulate matter emissions from shipping were linked to the premature deaths of 60,000 people each year, primarily in coastal and port areas and that this figure is likely to increase by 40 per cent by 2012.

It is worth bearing in mind, however, that in comparison to all other forms of transport, shipping and freight are by far the most efficient, particularly in comparison to aviation. In addition, great strides have been made over the past 20 years. One litre of fuel on a modern VLCC (very large crude carrier), now moves one tonne of cargo more than twice the distance it once did.

A recent members’ meeting at the UK’s Chamber of Shipping has drawn attention to the possible use of market-based mechanisms in reducing CO₂ emissions from shipping. Robert Ashdown, the Chamber’s technical head, explained that the industry is becoming increasingly aware that the future expectations of regulators cannot be met by technical and operational improvements alone. A real concern is that if the International Monitoring Organisation (IMO) fails to move quickly enough then individual countries might start introducing legislation unilaterally, creating significant headaches for the industry as a whole.

In fact, this is already happening. California’s Air Resources Board (ARB) now requires ocean-going vessels within 24 nautical miles of its coast to use to low-sulphur diesel. The move carries with it heavy penalties for non-compliance and unlike an earlier attempt, does not require approval from the federal Environmental Protection Agency. Both Denmark and Japan are independently developing a CO₂ index for new ship build which will allow owners to compare their ship’s fuel efficiency against other vessels. The major difference between the two approaches is that Denmark favours a course which will reflect performance under calm conditions, while Japan prefers an index which covers actual trading conditions. Denmark has also proposed a US$30/t levy to be adopted internationally. If accepted, it could raise around US$33bn annually, allowing the industry to offset around one-third of its emissions.

The IMO is already preparing for the implementation of a CO₂-indexing scheme, which will allow more efficient vessels to pay less in terms of emission dependent charges.

Fuel efficiency

The recent surge in the price of fuel, although having fallen back in recent months, is still having an effect on the shipping industry. It is worth considering that bunker fuel represents between 50 and 60 per cent of the freight market’s operating costs and the price has risen by 100 per cent YoY according to Aseambankers Research. The hike has triggered a rush towards fuel efficiency strategies such as investing more in hull, propeller and engine maintenance.

“So far, the initial results have been encouraging, showing real fuel savings of one to four per cent,” it noted (The Edge). In addition, the rising cost of bunker fuel has sparked competition among Asian ship-builders, who are now fighting to offer the best possible fuel performance.

Hyundai Heavy Industries has recently announced that it is now looking to fit “thrust fins” onto the rudders of its ships. These recover rotational flow from behind a ship’s propeller, thereby generating additional thrust. The company claims that this can reduce fuel consumption by four to six per cent.

Meanwhile, Daewoo Shipping and Marine Engineering have released their own propeller-based systems, which promise similar gains in performance. Finn Englese of the Oslo-based broker Lorentzen and Stemoco has suggested that the high cost of fuel could lead to the development of super efficient ships, which might use advanced slow speed engines with electronic injection for deep-sea routes. Anti-fouling coatings are another way of improving efficiency and already save the industry around US$60bn a year in reduced fuel bills. They are currently seeing strong growth in the Asia-Pacific region, due to new buildings in China and South Korea, particularly. Several companies have recently released new brands, all of which have fuel efficiency as a selling point.

Another strategy which is gaining momentum is in many ways a return to the industry’s roots. Skysail, a German company, is currently developing a towing kite wind propulsion system. It offers kites for cargo vessels with effective loads of between 8-32t. The system is being tested on two ships at present. One of the vessels has reported that the skysail could temporarily substitute over 50 per cent of the main engine power under optimal conditions. The company expects the system to result in a 10-35 per cent reduction in annual fuel costs.

The Skysail is one of many innovative new technologies
being developed in order to reduce the impact of escalating
bunker fuel costs on the shipping industry. If a switch to
diesel goes ahead, they will be sorely needed.

Other operators are responding to higher bunker prices simply by slowing down. The Hapag-Lloyd shipping company in the second half of 2007, reduced the standard speed of its speeds down to 20 knots from 23-23.5 knots and is reportedly making handsome savings, despite having to add an extra ship to its route.

The high-price environment has already claimed one victim in the form of The Gold Star Line, which had been operating an Australia-New Zealand container shipping service, but was forced to suspend operations in July.

Scrubbers versus diesel

In conjunction with the pressure on vessel owners to reduce SO_x emissions, the high price of fuel is making the introduction of onboard sulphur scrubbers more appealing than to using low-sulphur distillate fuels. However, this approach will do nothing to reduce the industry’s CO₂ emissions and such scrubbers are still an expensive investment. In comparison, switching to middle distillates means that CO₂ emissions could be reduced by over five per cent, due to its higher specific energy content and the fact that such fuel does not require pre-treatment or heating prior to use.

The IMO has set a target of switching the industry to a 0.5 per cent sulphur-content fuel by 2020. In addition, the current cap of 4.5 per cent will be reduced to 3.5 per cent by 2012. Furthermore, some special sulphur emission control areas will only allow ships using 0.1 per cent sulphur fuel to operate from 2015. Questions remain as to how practical these targets are though, especially given the increasing demand for low-sulphur diesel in the European private transportation market.

Any shift towards greater diesel usage by shipping could have a dramatic impact on refiners. Bunker fuel is effectively a residue from refining, primarily from the distillation and cracking processes. If demand runs dry, then the thick black sludge cannot simply be converted into another, more desirable fuel. Current estimates indicate that around 290Mta of bunker fuel is consumed each year. To replace that with low-sulphur diesel would require colossal investment in new refineries and specialised units needed to increase the yield of diesel. In addition to the cost, the lead-time between concept and a new refinery is considerable. It should be noted that the cost of new refining capacity is still less than installing onboard SO_x scrubbers on every large vessel.

A move to low-sulphur diesel could well be the cheaper option for the shipping industry. That’s the conclusion of Intertanko, the International Association of Independent Tanker Owners. Although the organisation expects such an approach to roughly double the cost for the industry, it still argues that this would be less costly than a series of lower impact measures that would likely be less effective and eventually lead to dieselisation in any case. In addition, it would eliminate the need for shipboard HFO treatment and onboard scrubbers, reducing CO₂ emissions in the process. It has also been argued that such a move would remove the quality control problems often associated with using a residual fuel and improve the working environment for ships’ crews. Intertanko is also opposed to scrubbers on the grounds that the shipping industry should not have to be involved with waste management. In addition, onboard scrubbers are currently large, difficult-to-install, leave hazardous waste and are still being tested.

Shipping fuel to markets

As far as the oil tanker industry is concerned, it is making significant progress in terms of its own unique challenges. For example, thanks to over US$500bn of investment, the industry expects to see 95 per cent of all tankers in operation by 2010 being equipped with double hulls. This has come about in part due to increasing pressure for higher safety standards and a lower risk of spillages. The options for single-hulled vessels include refitting to double hulls or conversion to bulk carriers. Interestingly, the bulk of the single-hulled vessels in operation seem to be moving to Asia, which in 2007 had 66 per cent of the single-hulled fleet.

This programme has already resulted in dividends. Despite the global tanker fleet’s expansion to approximately 107bn tonne-miles, this decade has so far seen a 78 per cent reduction in reported oil spillages (ITOPF/Fearnleys). At the same time, the average age of oil tankers has also fallen to 11 years, down from the peak of 15 seen at the end of the last decade.

One of the challenges faced by the industry is declining oil demand in the US, triggered by US$4/gal gasoline and the economic downturn. In a presentation at Intertanko’s AGM, Henry Curra, ACM Shipping’s head of research, indicated that in his opinion, transatlantic arbitrage is likely to continue. He highlighted the lingering questions surrounding the new export-driven refineries expected to soon come online, and in particular whether or not they will supply as far afield as the US. Mr Curra later dismissed this possibility, along with the potential for new Middle Eastern refining capacity to increase long-haul capacity within the next six years, as wishful thinking.

Conclusions

It is clear that the shipping industry faces significant challenges in the coming years. Fortunately, the nature of the business means that compared to the rest of the transport sector, it is on a firmer footing, given lower price sensitivity and a stronger ability to pass on costs to customers. If a switch to diesel occurs it will have substantial consequences for the oil sector, as well as the global economy, if the necessary refining capacity fails to materialise. Fuel efficiency gains are clearly there for the taking, but it is difficult to see at this point how the sector could be completely decarbonised.

For more information, visit:
www.skysails.info
www.imo.org/
www.intertanko.com

Combined heat and power offers many advantages over traditional methods of power generation. Here, IFandP assesses recent developments within the European market and the challenges ahead.

If a stranger were to visit our planet, they might notice something rather odd. Today, we throw away as much heat as we require, due to a combination of inefficient power generation and the lack of infrastructure such as distribution networks. Typically around two-thirds of the energy generated during power generation is wasted in the form of unused heat.

However, it doesn’t have to be like this. Combined heat and power (CHP) is a tried-and-tested technology, which is currently making an appreciable difference and has a great deal of room for expansion. Put simply, it involves the simultaneous generation of heat and electricity, but unlike conventional systems, the heat is channelled to where it can be productively used, for example, in industrial processes or to warm residential housing. The utilisation of what would otherwise be waste heat means that CHP can offer efficiencies much higher than that of conventional power generation.

CHP use is now widespread in Denmark, Finland and The Netherlands. Generally, CHP systems fall into three main categories. The first includes systems that effectively deliver heat and power to a single large facility, be it a factory or a hotel. Another application involves distributing the generated heat to a large number of locations. This includes the use of a heat pipeline network to warm residential complexes. Finally, there is the concept of micro-CHP in which a small-scale CHP boiler is used to satisfy the power and heating demand of an individual home.

A matter of policy

In Germany, the regulatory environment has recently become more favourable to CHP, with the enactment of the laws for the support of cogeneration (KWKG) and an amendment to the Renewable Energies Law. In combination, the changes mean that the country is committed to doubling the proportion of CHP in its energy mix to 25 per cent by 2020. Even if this target is reached, there will be still be significant room for improvement as estimates indicate that the potential figure is over 50 per cent. The CHP sector stands to gain €750m (US1.16bn) a year in benefits and incentives from the new proposals, possibly starting as early as next year. The funding will be split into €600m for new generation and €150m for the construction of piped heat networks.

Siemens is currently leading a consortium to build a large coal-fired CHP plant in Mainz, Germany, to be completed by 2013. The 800MW plant will provide 200MW of district heating for up to 40,000 households and will supply around 30MW of process steam for use by the city’s industrial facilities. Michael Suss, the CEO of fossil power generation at Siemens AG, has said that as a consequence, he expects the plant to reach “an optimum fuel efficiency of 60 per cent” (Datamonitor).

Back in April, Norway announced that it will also increase its use of CHP to 7.5TWh by 2020. In addition, the Norwegian government is seeking to raise the tariffs for power plant grid connections from 2009 and onwards, with the goal of making online biomass CHP plants more competitive. Currently the country generates only 2.6TWh from such facilities.

Britain is throwing its weight behind small and micro-CHP systems, but seems to be ignoring the potential of city-wide, piped heat networks, presumably due to cost considerations. This is despite official estimates from DEFRA, which believes that such systems could save nearly 160TWh of energy a year, enough for the country to meet its CO₂ targets and at the same time eliminate the need for new nuclear build.

District heating systems offer several advantages. From the perspective of residents, they mean lower heating bills and independence from the price of gas, which in countries such as Britain, holds a virtual monopoly in the residential heating sector. For example, in the Danish city of Odense, the installation of a piped heat system has led to the mothballing of the city’s gas network. Of course, this kind of outcome is undesirable from the perspective of gas and electrical utilities for obvious reasons.

The amount of energy wasted by traditional centralised electricity generation
is extremely high. Most of it is in the form of heat, which could be used by
industry and residential areas via district piped heating systems.

One incentive that CHP lobbyists in Britain are keen to win is an extension of the Climate Change Levy exemption for CHP, which is worth around GBP4.41/MWh – roughly 10 per cent of the wholesale power price. Currently the exemption is set to end in 2012 and industry advocates are keen to seen an extension to 2017 or 2022.

A recent report commissioned by Greenpeace and written by Pöyry Energy Consulting, has indicated that there are nine industrial sites within the UK where CHP plants could be used to meet the energy and heating needs of local industry and potentially deliver electricity to the grid. Together, their total capacity could be as much as 13GW. All of these sites already have cogeneration facilities and the report claims that additional plants could be built.

Some of this promised capacity is already being realised. E.ON is currently building one of the world’s largest gas-fired CHP power stations at the Isle of Grain in Kent. The 1275MW plant is being built at a cost of around GBP500m. One possible flash-point, flagged by British MEP Fiona Hall, is how CHP fits into the EU’s emission trading scheme (ETS). The problem is that while CHP systems result in a net decrease in greenhouse gas emissions, they increase on-site emissions. This means less carbon credits are generated, as a business’s emissions are calculated for the production site alone. The absence of a general allocation for heat from the scheme is thought to be due to fears that such a provision could distort competition with the electricity market. Ms Hall is confident that the matter will be resolved before a final agreement on the third phase of the ETS is reached, and has promised, in conjunction with other MEPs, to table amendments seeking free allocation for CHP and microgeneration projects. Environmental policy makers have had a difficult time determining how to fit CHP into their GHG emissions trading schemes. There is also the problem that CHP projects in Europe are not currently eligible for the region’s Enhanced Capital Allowances, which have the potential to meet five per cent of the capital costs associated with newbuild. Another issue is the nature of the European energy market, with full liberalisation still some way off. Kees den Blanken, the chairman of Cogen Europe, recently said: “You sometimes get the impression that every country is drafting its own special policies on CHP. But how much are they looking at what is happening in other countries?” (Europolitics).

Compared to conventional electricity generation, CHP is significantly
more efficient, as it makes use of the heat generated by fossil fuel
combustion, which would otherwise be wasted.

Biomass-powered CHP

Due to the high efficiency of CHP systems, they already offer substantial savings in terms of fuel and carbon emissions. This can be increased by the use of biomass as a fuel. A good example is the proposed 5MW CHP plant to be built at Tesco’s Goole distribution centre in the UK. The project has already received approval and will burn straw using a steam turbine. The company expects the plant to cost GBP12m and estimates that it will have recouped its investment within six years, thanks to a combination of lower bills and the ability to sell any excess electricity to the grid.

CRE, the French electricity sector regulator, has launched a tender for three biomass-fired CHP power plants with a total capacity of 44MW. Elyo, an energy services provider has won the tender and is expected to obtain €1.15bn in revenue over a 20-year concession period, after investing some €230m. The plants will use hay and timber as feedstock.

Such CHP systems are becoming increasingly sophisticated. Wärtsilä is now offering modular, fully automated units, which operate a closed steam-feed water system, which is separate from the district heating system. Two of these BioPower plants are to be installed at breweries owned by Scottish and Newcastle in Manchester and Tadfield, UK. They are expected to come into operation in the first half of next year and will use spent grain in addition to wood chips as fuel. Spent grain is a waste product derived from the brewing process.

In a further sign that the brewing industry is starting to embrace CHP with a vengeance, a consortium of whisky distillers is looking to build a 7.2MW plant in Scotland, in the town of Rothes, at an estimated cost of GBP24m. Finally, RWE npower Cogen, has announced that it will build a 45MW biomass CHP plant at Markinch in Scotland, to supply steam and electricity to the Tullis Russel paper mill, replacing a coal-fired plant.

MicroCHP

As far as the residential market is concerned, microCHP boilers now offer a compelling case to home-owners. Although they currently cost GBP500-1000 more than a conventional boiler, according to Bob Flint of Ceres Power, a microCHP developer, “Our mCHP boilers will save the average household around 250 pounds ($489) a year,” (Dow Jones). This means that within five years, they can start generating a profit for their owners, thanks to lower energy bills and the ability to sell electricity on the national grid. The latter is particularly profitable in Germany, which commands Europe’s highest feed-in-tariffs, allowing micro-electricity producers to earn approximately €0.4/KWh, compared to retail rates of €0.18/KWh (after taxes and support fees). In addition to saving consumers money, the additional efficiency means that MicroCHP boilers can reduce a British home’s carbon footprint by 2.5-5tpa.

Energetix Genlec is in the process of developing its own MicroCHP system, which utilises an Organic Rankine Cycle, to obtain around 90 per cent efficiency. The testing and evaluation of the system was funded by E.ON’s sustainable energy solutions team, as part of an agreement between the two companies. The process is now undergoing field trials, prior to large deployment and integration within E.ON’s microgeneration portfolio.

The sums at stake are considerable. Back in 2003, the EU domestic boiler market was valued at GBP8.1bn and in 2004, Cambridge consultants estimated that sales of microCHP boilers within the EU could amount to GBP1.5bn per annum by 2010. MicroCHP systems could well be only the beginning. A biofuel-power micro-trigeneration system is in development, which will include a cryogenic-based energy storage device, allowing the system to cool the home and keep food refrigerated. In addition, the presence of an energy storage device will allow homes with solar panels or micro-wind turbines to overcome the problem of intermittency, typically associated with such renewables. The system is being developed by a collaboration between British and Chinese universities. The researchers hope to have a prototype up and running by 2011. Although aimed for home use, they believe it could be scaled up for industry.

Huge potential, but will it be realised?

It is clear that CHP offers the EU a huge opportunity to reduce its energy needs and carbon emissions. However, there are a number of barriers that may well conspire to prevent it from reaching its full potential. The most significant of which, with the possible exception of finance, appear to be psychological. Until the energy and heating sectors learn to work closer together and while governments continue to prefer large, highly-visible projects as opposed to smaller, more locally-distributed forms of generation, CHP will continue to struggle in its efforts to reach the same footing as conventional power generation.

For more information, consider visiting the following websites:
http://www.chpa.co.uk/

http://www.energetixgroup.com/

The growing awareness of the threat facing humanity from climate change has prompted a search for practical and affordable ways to ensure that the levels of CO₂ in the atmosphere do not rise to the point where they cause immense and irreversible ecological and environmental harm, while allowing humanity to continue with its more immediate quest for an ever higher standard of living.

Consequently, there are now loud and acrimonious debates between environmental campaigners and other interest groups regarding how our energy needs in the future should be met. The former argue for a widespread move towards renewable energy. However, while this is indeed laudible and there are indications that both the wind and solar industries are maturing rapidly, much of the world still depends on coal-fired power generation to fuel its industries and light its homes and will probably continue to do so for the foreseeable future. Coal-burning releases more CO₂ than cleaner sources of energy such as natural gas and accounts for around 56 per cent of all emissions from industry. It is therefore clear that there is a pressing need for technologies capable of mitigating and reducing the amount of CO₂ entering our atmosphere from such sources. The situation is more urgent when one considers that according to BP’s chief economist, Christof Ruehl, coal has been the consistently fastest-growing fuel for the past five years, with coal use up 4.5 per cent in 2007. Faced with such a predicament, it is little wonder that many in the energy industry are reaching for the planetary equivalent of low-tar cigarettes.

Carbon capture methods

To a certain extent, the process of condensing CO₂ and sequestering below the ground is relatively well understood. At present, discussions tend to be focused on the best way to purify the greenhouse gas. From the perspective of power plants, there are two main strategies:
1. Post-combustion, in which the fuel is burnt normally and the CO₂ is removed from the flue gases
2. pre-combustion, in which the fuel is first gassified, eventually producing hydrogen rich gas, which is burnt, and also CO₂.
The first method is hindered by the fact that the concentration of CO₂ in the flue gas is relatively low at 10-15 per cent, making it more difficult to recover, but it also lends itself more readily as a technology to be retrofitted to existing power plants. Pre-combustion by way of contrast, is unlikely to be retrofitted to normal power plants, but is a good fit for integrated combined cycle (IGCC) plants. These can run on a wide variety of fuels, including coal, petcoke, biomass and even asphalt.

Another approach is the oxyfuel combustion system in which the fuel is burnt using almost pure oxygen. The mixture of gases that is produced is then recycled, resulting in a much higher concentration of CO₂ than that generated by conventional methods. This process is currently being developed by Babcock & Wilcox in association with AEP and it is soon expected to complete a pilot demonstration plant at its Clean Environment Development Facility in Ohio.

One of the problems facing CCS as a technology is the issue of parasitic load – the amount of energy required by the process. Numbers given for this vary widely depending on the exact process involved but are often in the 11-40 per cent range. This means that more fuel has to be burnt to deliver the same amount of power to the end user and therefore the absolute amount of GHGs emitted by the plant is higher than simply multiplying the carbon emissions from the plant in the absence of CCS by the CCS plant’s capture rate. The largest component of parasitic load is the compression of the CO₂ (to 1200-2000psi) so it can be transported by pipeline. Precombustion techniques have an advantage in this area as they can generate CO₂ at an initially higher pressure than with post-combustion. The high pressure also allows pre-combustion techniques to use physical absorption systems for CO₂ capture rather than chemical absorbants. The cooling or heating needed to release the CO₂ from the absorbing medium is also energy intensive and is therefore another key factor in terms of parasitic load.

In addition to the different ways in which the fuel is burnt, there is also the choice of absorbing medium. Currently there are three main types: chilled ammonia, amines and glycerol-based solvents such as Selexol (a mixture of dimethylethers of polyetheleneglycol). Ion transport membranes and chemical looping mechanisms are also being developed. Ammonia-based systems absorb CO₂ in a solution of ammonium carbonate at a low temperature forming ammonium bicarbonate. When the temperature increases, the CO₂ is released and the ammonium carbonate regenerated. Amine systems use an amine or amine/water mix to capture the CO₂. This is then heated, releasing the CO₂ and regenerating the absorbant. Selexol-based systems, require cooling and regeneration of the solvent is achieved with heat (flashing) or with the use of a stripping gas.

The US Department of Energy (DoE) tested three Selexol-based capture systems in May 2007, in conjunction with coal-based IGCC power plants and found that if sequestration was included, the cost of reducing CO₂ emissions was US$32-42/t. In addition, the use of CCS reduced the efficiency of the system from 39.53 per cent to 32 per cent, while at the same time increasing the capital cost “by roughly 32-40 per cent”.

The DoE has also published a study comparing the relative efficiencies and costs of the different combustion methods coupled with CCS. The results are shown in figures 1 and 2. They indicate that IGCC plants, despite being relatively inefficient, compared to their natural gas-fired counterparts, are by far the cheapest of the four methods investigated. The other techniques all had a price of CO₂ mitigation of US$75/t or higher. IGCC plants also performed well in terms of the price of electricity, narrowly outperforming NGCC plants and at the same time, costing less than half that of powdered coal-fired plants. This is to be expected, given the greater difficulties in capturing carbon emissions after combustion has occurred

Figure 1: Net plant efficiency. Source: Office of Fossil Fuels, US Department of Energy, May 2008 presentation

Figure 2: CO2 mitigation costs. Source: Office of Fossil Fuels, US Department of Energy, May 2008 presentation

As compelling as this data appears, there is the problem that the vast majority of coal-fired power plants currently in operation are not IGCC plants. Therefore, energy utilities may well face an unwelcome dilemma: either pay a considerable premium on top of the capital needed for the CCS plant, or see a sharp reduction in performance and profitability. Fortunately, CCS technology has considerable room for improvement. Reducing parasitic load is one of the main R&D priorities in this field and great strides are already being made. For example, Fluor’s Econamine FG Plus technology offers a 19 per cent reduction in power demand compared to other monoethanolamine (MEA)-based systems, thanks to a combination of high-efficiency reclaiming, advanced heat recovery and integration and several other innovations.

Current and future projects

At present, facilities that are sequestering carbon, are few and far between. Currently there are only three: StatoilHydro’s Sleipner plant on the Norwegian continental shelf, its Snøhvit LNG plant and the In Salah plant in Algeria, which is a joint venture between Sonatrach, BP and StatoilHydro. It is no accident that two of these three projects are located in Norway. The country has taxed CO₂ emissions resulting from its industries at US$45/t since 1991. In the case of the In Salah plant, this was realised in response to BP setting a price for carbon internally as part of its efforts to manage its operations in a more sustainable manner.

StatoilHydro’s CO₂ sequestration activities at the Sleipner field (see the imbedded company video shown left) have been ongoing for the past 11.5 years, injecting 1Mta of CO₂. It is extracted from the field’s natural gas, which contains nine per cent CO₂ and the sequestration is saving the company around US$45m per annum in tax revenue. Despite its strong lead and considerable experience with CCS, StatoilHydro is not looking to own the associated technology, instead it plans to assist in its development and implementation.

The In Salah and Snøhvit projects involve removing and sequestering the CO₂ associated with natural gas and they are injecting around 1Mta and 0.7Mta of CO₂. It should be stressed that there are other projects currently sequestering CO₂ but these are the only ones in the world doing so with the goal of storing CO₂ for the purpose of climate change mitigation. The others pump CO₂ into depleted oilfields, in an effort to boost ouput. This technique is referred to as enchanced oil recovery. A project currently in development is the Mongstad refinery in Norway. A CHP plant and a large scale CCS demonstration plant are expected to come online in 2011, with an initial injection capacity of 100,000tpa.The project will test both the amine and chilled ammonia methods of CO₂ capture, before an investment decision is made in 2012. The project is funded by Dong Energy, the Norwegian authorities, Shell StatoilHydro and Vattenfall, with the aim of reducing both the costs and risks associated with large-scale CO₂ capture.

At a StatoilHydro press conference, Olaf Kaarstad, a special adviser, was keen to point out that the evidence indicates that the risk of any gas escaping from a reservoir decreases with time as the CO₂ gradually reacts with the surrounding rock and dissolves into any saline water present. Furthermore, he said that currently no CO₂ sequestration project has yet reached the point where a reservoir has been filled and requires capping. There are ongoing discussions to decide who should hold the final responsibility for maintaining and monitoring capped reservoir and Mr Kaarstad expressed the opinion that this role is likely to be taken on by governments.

During a press conference, he explained that one of the barriers to further expansion of CCS is that such projects currently cannot earn credits as part of the UN’s Clean Development Mechanism (CDM) as India and Brazil blocked its inclusion, possibly out of concern that it would draw funding away from reforestation projects. He suggested that when the CDM was being designed, it probably was not written with CCS in mind. Mr Kaarstad said that in his opinion, not many CCS projects will come online in the next few decades, with those that do, likely to be the “low-hanging fruit” such as schemes to remove CO₂ from natural gas and that generated from ammonia and hydrogen plants.

According to a report on the subject written by the International Panel on Climate Change (IPCC), one element that is unlikely to be an issue is finding enough storage capacity. Saline acquifers alone could hold 1000-10,000Gt of CO₂, while oil and gas fields could store 675-900Gt. Unfortunately these figures are “raw” in that they do not take economic considerations into account.

In the US, American Electric Power (AEP) announced in March, that it is looking to install CCS on two of its power plants, with the first project expected to be complete in 2011. It will sequester 100,000tpa of CO₂ from AEP’s 1300MW Mountaineer plant in West Virginia. The technology used will be provided by Alstom and will be in the form of pre-combustion with ammonia as the absorbant. This method is currently being pilot tested.

The challenges ahead

At present, it could be argued that the two main obstacles to the implementation of CCS on a large scale are a lack of financial incentives and the huge scale of investment required to bring it to fruition. Another issue is that the relative immaturity of the technology means that investors are likely to remain afraid of financing large projects, until a number of demonstration plants have been built and tested. To give some idea of the costs involved, a recent study undertaken by the UK government’s North Sea Basin Task Force, calculated that the cost of building a CCS network, allowing Britain and Norway to sequester the carbon from their power plants in depleted oil and gas fields, would cost GBP46bn, 78 per cent of which would be incurred by equipping the power stations with the facilities needed to capture CO₂, while only 10 per cent of total expenditure would be needed to build pipelines and eight per cent for platform and well costs. It is worth noting that the study found it difficult acquiring all the necessary information, making its estimates relatively tentative. However, it did conclude that expanding the network to generate revenue via enchanced oil recovery, would lead to a tripling of the investment required.

The EU as a whole is stumbling over the costs needed for its demonstration programme, which has been costed at some €10bn. The European Commission expects member states and energy companies to foot the bill, particularly as the current price of emitting carbon is approximately half that required to probably cover the cost of CCS. This may yet change, as the third phase of the EU ETS is expected to be tighter than either phase I or II, and if aviation and other sectors are included, the additional demand could lead to a higher price. Unfortunately, the important word here is “if”. Without clear indications that there will be a reliable revenue stream available, it is understandable that both CEOs and the financial institutions capable of funding CCS have been reluctant to embrace it. Currently CCS projects cannot yet receive carbon credits from the ETS, but this will change in 2013, when the third phase of the scheme begins. Interestingly, Chris Davies, an EU MP with the responsibility of shaping an EU directive on CCS, has proposed that such schemes should receive carbon credits for each tonne of CO₂ sequestered. This would effectively reward their operators twice; once for not having to buy the credits needed for compliance and again for being able to sell the earned credits on to other parties. One of his more controversial ideas is for all coal-fired power plants commissioned in the EU after 2015 to require CCS. Such a move would send a strong signal to the market and could potentially trigger greater investment in renewables, as coal would no longer be a relatively “cheap” option.

Escalating costs were the publically announced reason for the “rescheduling” of the Future-Gen CCS project in the US, together with the belief that given the number of different technologies on offer, it seemed to make little sense for the Federal Government to place all its eggs in one basket. Countering this arguement is the fact that plenty of time, money and effort has already been invested in finding a geologically suitable site.

In addition, the winners of the initial contest, Coles Together for the Mattoon, Illinois site, had already secured all the necessary permits for the installation of any additional infrastructure required, a process that could take a considerable amount of time, if new site(s) are sought. After a Senate Appropriations Subcommittee on Energy and Water Development meeting on this subject, it now looks like the buck has been well and truly passed to the next president of the United States. Until the new administration is sworn in, the Future-Gen project is now on hold.

Interestingly, environmentalists are divided on the subject of CCS. Greenpeace is adamant in its opposition to the technology. “Carbon capture and storage is a scam. It is the ultimate coal industry pipedream,” said Emily Rochon, campaigner and the author of a report on the subject called “False Hope”. The environmental pressure group believes that it is just a smokescreen to allow the coal industry to push through a new wave of coal-fired plants. In stark contrast, the World Wildlife Fund is supporting the technology and has already formed an alliance with the Australian Coal Association, the Climate Institute and the CFMEU, a large Australian mining union, possibly creating a rift between it and other environmental action groups. Both India and China have yet to agree to binding CO₂ reduction targets and their reliance on coal-fired generation for a large proportion of their power generation, therefore widespread adoption of CCS in both countries seems a long way off.

That said, there are some grounds for optimism. Back in 2005, a company called Greengen was set up as a joint venture between some of China’s largest power and coal companies as well as an investment bank, with the aim of advancing clean coal technologies and CCS. It is committed to building an IGCC plant with CCS. The Chinese government launched a joint initiative in November 2007, in partnership with the UK, with the goal of promoting and researching the use of CCS in China. In addition, China Huaneng Group, one of the country’s largest power utilities is a member of the Future-Gen alliance. However, although such participation indicates that China is taking an active interest, it does little to counter claims from those opposed to CCS that it will not provide tangible benefits in terms of greenhouse gas emission reductions before the effects of climate change are widely felt. Indeed, of the 21 projects that are progressing worldwide, only three could be said to be of commercial size. Clearly much then rests on the diplomatic efforts needed to bring developing nations onboard, particularly to address the issue of carbon leakage, as well as the move towards a robust and (crucial for investors) stable carbon price signal.

For more information consider visiting the following websites:
http://fossil.energy.gov/
www.futuregenalliance.org