The Worldwide Thermal Power Generation Market

Transcription

ENERGY INDUSTRY MARKET FORECASTS
2008 - 2015
The Worldwide Thermal Power Generation Market
All rights reserved. No part of this publication may be reproduced, stored in a retrieval
system, or transmitted in any form or by any means, electronic, mechanical, photocopying,
recording or otherwise, without the prior written permission of Scottish Enterprise.
Scottish Enterprise Energy Team
27 Albyn Place
Aberdeen
AB10 1DB
Tel: 01224 252000
Fax: 01224 213417
Email: [email protected]
Web: www.scottish-enterprise.co.uk/energy
Report produced by: SINCLAIR KNIGHT MERZ
Sinclair Knight Merz is an international engineering consultancy with
operations throughout Europe, Austral-Asia, the Middle East, South Africa
and South America. Power Generation is a key business sector for SKM.
Sinclair Knight Merz (Europe) Ltd.
175 West George Street
Glasgow
G2 2LB
Tel: +44 (0)141 202 2828
Web: www.skmconsulting.com
PREFACE
The Power Generation sector provides many opportunities for Scottish businesses - at Scottish Enterprise we
want to work with industry to exploit these opportunities.
A key part of this support is providing market intelligence. This report is one in a series of studies looking at
different sectors within the energy industry.
We hope this report will help Scottish companies keep one step ahead of their global competitors and give them
an edge in winning future business. We encourage companies to take advantage of this study to help focus their
global business development activities, and to access the support available from Scottish Development
International.
This report looks at opportunities to supply equipment and services to the global thermal power generation
market. By thermal power we mean large plant, with typical unit sizes of greater than 300 MWe, which is generally
coal-fired, gas-fired or nuclear.
Over the last twelve months, carbon abatement, or carbon capture and storage (CCS) has become the hot topic in
the industry; and the report also looks at the size of the market associated with this area. The last year also saw
much public debate regarding new coal-fired plant, and the impact this potentially could have on the environment.
A short case study on a proposed new coal plant is included as an appendix, which also includes a summary of
the ensuing technical debate on levels of carbon abatement required for new plant, and details of proposals for a
CCS demonstrator.
Also associated with CCS is the broader topic of sustainability. The possible impact of sustainability issues on the
Supply Chain is discussed, and pointers are given to the developing ’best practice’.
I would like to take this opportunity to thank those companies who contributed with their views during the
production of this report for their valuable help and assistance.
Brian Nixon
Director, Scottish Enterprise Energy Team
January 2009
-i-
Contents
i PREFACE
Contents
Glossary
ii iii I INTRODUCTION
1 II THERMAL POWER GENERATION
3 III IV V VI VII Coal-Fired Generation
Gas-Fired Generation
Nuclear
Carbon Capture and Storage (CCS)
New-Build Timescales
4 7 8 10 14 GLOBAL ENERGY TRENDS
15 Increase in Installed Capacity and Capacity Additions
Forecast Increase in Installed Generating Capacity Worldwide, 2007 – 2015
Europe
China
India
United States of America
Other Regions of Interest
16 17 18 22 24 26 27 POWER PROJECTS DELIVERY
29 Sustainability
31 CAPITAL COSTS
33 Capital Cost Analysis
Power Plant Cost Breakdown
34 35 SCOTTISH SUPPLY CHAIN
37 Current Capability of the Scottish Supply Chain
Worldwide Forecast in Installed Capacity and Market Value, 2007 - 2015
Market Value of Equipment Supply for Coal-fired New Build, 2007 - 2015
38 39 40 OPPORTUNITIES FOR SCOTTISH COMPANIES
41 Scottish Enterprise Support to the Energy Industry
44 46 APPENDICES
- ii -
Glossary
ACCAT
BERR
BNES
Capacity
additions
CCGT
CCS
CHP
DECC
CMM or CBM
Eastern Europe
EIA
EOR
EPC Contractor
FBC
FGD
HRSG
IEA
IGCC
IGFC
IPCC
IPP
LNG
Middle East
NDA
Net electricity
generation
NOx
NI
DECC (formerly BERR) advisory committee on Advisory Committee on
Carbon Abatement Technologies
Department for Business, Enterprise and Regulatory Reform, formerly
known at the Department for Trade and Industry (DTI)
British Nuclear Energy Society
OECD
Equivalent value of the total new-build capacity for a particular region
usually in gigawatts(GW) or megawatts (MW)
Combined Cycle Gas Turbine based plant which will also have steam
turbines to utilise steam generated by a Heat Recovery Steam Generator
(HRSG)
Carbon Capture and Storage
OECD Asia Pacific
OECD Europe
Combined Heat And Power
Department for Energy and Climate Change
Coal Mine Methane or Coal Bed Methane
For the purposes of this report, includes the countries: Albania, Armenia,
Azerbaijan, Belarus, Bosnia-Herzegovina, Bulgaria, Croatia, Estonia,
Serbia and Montenegro, the former Yugoslav Republic of Macedonia,
Georgia, Kazakhstan, Kyrgyzstan, Latvia, Lithuania, Moldova, Romania,
Slovenia, Tajikistan, Turkmenistan, Ukraine and Uzbekistan. For
statistical reasons, this region also includes Cyprus and Malta. Russia is
included separately
Energy Information Administration (US Department of Energy)
OECD North
America
Other Asia
Enhanced oil recovery (as part of a CCS)
Engineering, Procurement and Construction contractor, generally
appointed as the turnkey contractor
Fluidised bed combustion
PCC
Primary energy
Flue gas desulphurisation
Heat recovery steam generator
International Energy Agency, an autonomous body which was
established in November 1974 within the framework of the OECD to
implement an international energy programme. This report refers both to
its Annual Outlook’s and its recent CCS report
Integrated Gasification Combined Cycle
SOx
SC and USC
SCR
Thermal power
generation
Tier 1 contractor
Tier 2 contractor
Tier 3 contractor
Total installed
capacity
Integrated gasification fuel cells ( A-IGFC is advanced IGFC)
Intergovernmental Panel on Climate Change
Independent power project
Liquefied natural gas
For the purposes of this report, includes Bahrain, Iran, Iraq, Israel,
Jordan, Kuwait, Lebanon, Oman, Qatar, Saudi Arabia, Syria, the United
Arab Emirates and Yemen.
Nuclear Decommissioning Authority
WEC
WNA
Is equal to final demand less network losses and station’s internal use of
- iii -
electricity at power plants.
Nitrous oxides
The Nuclear Institute: a merger of the BNES and the Institution of
Nuclear Engineers
Organisation for Economic Co-operation and Development. Member
countries are: Australia, Austria, Belgium, Canada, Czech Republic,
Denmark, Finland, France, Germany, Greece, Hungary, Ireland, Italy,
Japan, Republic of Korea, Luxembourg, Netherlands, New Zealand,
Norway, Portugal, Spain, Sweden, Switzerland, Turkey, United Kingdom
and United States. The Slovak Republic and Poland are likely to
become member countries in 2007/2008.
OECD classification: includes countries: Australia, Japan, Korea and
New Zealand.
OECD classification: includes Austria, Belgium, the Czech Republic,
Denmark, Finland, France, Germany, Greece, Hungary, Iceland, Ireland,
Italy, Luxembourg, the Netherlands, Norway, Poland, Portugal, the
Slovak Republic, Spain, Sweden, Switzerland, Turkey and the United
Kingdom.
OECD classification: includes Canada, Mexico and the United States.
Includes Afghanistan, Bangladesh, Bhutan, Brunei, Cambodia, China,
Chinese Taipei, Fiji, French Polynesia, India, Indonesia, Kiribati, the
Democratic People’s Republic of Korea, Laos, Macau, Malaysia,
Maldives, Mongolia, Myanmar, Nepal, New Caledonia, Pakistan, Papua
New Guinea, the Philippines, Samoa, Singapore, Solomon Islands, Sri
Lanka, Thailand, Tonga, Vietnam and Vanuatu. China and India are
included separately
pulverised coal combustion
Energy in the form that it is first accounted for in a statistical energy
balance, before any transformation to secondary or tertiary forms of
energy
Sulphurous oxides
Supercritical and Ultra-supercritical(steam technology)
Selective catalytic reduction (of NOx emissions)
Power generation whereby the prime mover is steam driven. Includes
coal, nuclear, most gas fired plants power plants are thermal.
Generally an EPC contractor
Major equipment suppliers, e.g. turbines, boilers, generators
Secondary equipment suppliers, e.g. pumps, fans
The maximum output, commonly expressed in megawatts (MW), that
generating equipment can supply to system load, adjusted for ambient
conditions
World Energy Council
World Nuclear Association
I
INTRODUCTION
Scope
•
2007 Survey of Energy Resources, World Energy Council (WEC)
The expertise and experience of Scottish companies ranges from design through
construction and operation of complete power plants, and in the supply of the
engineered systems and equipment that form the critical parts of power plants.
Scottish companies provide a range of support in all stages of a power project, from
concept to operation, including technical, legal, financial and environmental
consultancy services. The aim of this report is to highlight potential supply chain
opportunities for Scottish companies.
•
International Energy Outlook 2008 (IEO2008) and International Energy Outlook
2007 (IEO2007), by the Energy Information by the Energy Information
Administration (EIA), Outlook for international energy markets through 2030
•
Facts and Figures, Electricity Generation 2007 and 2008, VGB PowerTech
•
IEA CO2 Capture and Storage report 2008
•
Platts Energy Outlook and various related publications
Throughout the report there are references to member countries of the Organisation
for Economic Co-operation and Development (OECD) and non-member countries,
as much of the published research has been funded by the OECD.
This report looks at large thermal power plant generation plant globally and
evaluates opportunities up to 2015. Thermal power generation has been dominated
by coal-fired and nuclear plant over the last 50 years. Since the mid-1980s, much of
the new plant commissioned has been gas-fired with the UK’s ‘dash for gas’
following in the steps of the earlier market developments in the rest of Europe.
Recent concerns on the security of gas supplies, climate change and global world
opinion that ‘clean coal’ and new nuclear technology are an acceptable way forward
for new generating plant, has put these technologies back at the top of the agenda
for new developments. Thus, the main focus of this report is on coal fired and
nuclear opportunities. However, combined cycle gas-fired plant (CCGT) is not
neglected, as a number of schemes are currently being developed where gas is
readily available or is required to fast-track developments where electricity
generation is required as a priority. It is also widely expected that CCGT plant will be
installed to meet the ‘energy gap’ which may open up if large coal-fired or new
nuclear plant projects are delayed.
Primary research
Information was gathered during a series of interviews with industry contacts:
•
•
•
•
The issues addressed in the interviews are discussed in Appendix 2. In addition the
report draws on information presented at various recent seminars organised by the
IPA, BNES Scotland, IET Power Generation, ICE Scotland and the Nuclear Industry
Association’s ‘Meet the Vendors’ day.
Data sources and analysis
For this report, data relating to forecast net electricity demand and installed capacity
was extracted primarily from the World Energy Outlook 2008 and 2007 (IEA). The
forecasts in the IEA data are presented as the reference scenario based on data
accumulated up to 2006. The figures presented in this report have been derived from
work done by others, and have been further modified using existing financial models,
thus neither Scottish Enterprise nor SKM can guarantee their ultimate accuracy. The
reference scenario forecasts the outcome for given assumptions on economic
growth, population, energy prices and technology, assuming nothing more is done by
governments to change underlying energy trends. It takes account of those
government policies and measures that have been adopted by mid-2008, regardless
of whether they have yet been fully implemented. This data was compared to data
from International Energy Outlook 2008 and 2007 (EIA). There are large differences
between the IEA reference scenario and the EIA reference case projections for both
This report is part of a larger suite of reports produced by Scottish Enterprise that
includes wind, biofuels and renewables generation; therefore those areas are not
covered in this report. This report does not discuss small plants where the unit sizes
are typically less than 300 MW, and so diesel and gas engine based generation are
also excluded.
Research
Secondary research
The report was compiled over a period of 12 months during 2008. Sources included
the following publications:
•
World Energy Outlook 2008 and 2007, International Energy Agency (IEA) – the
2007 Outlook included ‘China and India Insights’
Chapter I: Introduction
SKM technical specialists
Scottish equipment suppliers
EPC contractors
Developers
-1-
INTRODUCTION (continued)
the OECD and non-OECD countries. The projections vary not only with respect to
levels of total world energy demand but also with respect to the mix of primary
energy inputs. Principally in the 2005 to 2015 period, the IEA expects faster growth
in fossil fuel use and slower growth in the use of non-fossil fuels than does EIA.
Areas of particular differences are:
•
•
•
•
•
•
•
IEA projections of US growth in energy demand significantly surpass the high
growth scenario by the EIA, therefore EIA data has been used for the increase in
installed capacity for the US.
•
For China and the Middle East, IEA projects much faster growth than EIA from
2005 to 2015 e.g. IEA projects average annual growth of 5.5% in China’s coal
demand, compared with 4.4% from the EIA. Similarly, India’s coal use grows by
4.7% per year in the IEA reference scenario, compared with the EIA’s 2.9 %.
It is important to note that much of the research and data collation for this report and
its associated sources was undertaken prior to the global financial crisis. The current
financial problems that are being experienced globally will likely affect the shorter
term forecasts for new build. However the forecast high demand for power worldwide
is likely to take precedence in the long term.
IEA projects a modest 1.8% annual increase in Africa’s energy use from 2005 to
2015, compared to 2.7 % in the EIA reference case.
Appendix 1 includes a flowchart which summarises the data sources and the
subsequent analysis carried out to provide data for this report.
Using this report for business development
Forecast installed capacity
The following table details the layout of this report and describes how the end-user
might use the information effectively.
The majority of data for installed capacity and generation forecasts was based on
information in the reference scenario in IEA World Energy Outlook 2008. The latest
complete set of worldwide generation data is for the year 2006, therefore the
forecasts cover the period from 2007 to 2015.
Chapter
The majority of forecasts only present the increase in total installed capacity; they do
not represent the total new-build capacity (capacity additions). The forecasts for
new-build capacity are expected to be higher as significant existing capacity is
expected to be decommissioned and replaced throughout the world in the next 10
years. The forecast capacities:
•
do not include the embedded medium and small generation plant
•
do not reflect the current contracted position and take no account of future
uncertainty
•
are based only on those technologies currently deployed on a large scale
Future uncertainty
There are no guarantees made regarding the forecast as there are a number of
factors that can significantly affect the generation and demand forecasts, including:
•
Changes in legislation, for example the gas moratorium in recent times caused a
dramatic change in policy in the UK and was unexpected by most observers
Chapter I: Introduction
Political instability, with increasing reliance on fuel supplies from the Middle East,
Africa and Russia
Economic factors affecting fuel costs, including possible market manipulation
War/terrorism/natural disasters; attacks on pipelines or nuclear facilities could
dramatically shift the generation outlook
Technical innovation, a rapid advance in fuel cells or other storage devices would
be a massive boost for renewable sources
Climate change, incentives for nuclear generation and renewables could increase
significantly due the development of future government policies under the postKyoto negotiations.
-2-
Aims to provide or identify:
I
Introduction
Introduction and methods of data analysis, primary and
secondary research
II
Thermal power
generation
Brief description of coal, gas and nuclear power generation
technologies, environmental and economic drivers, and
associated trends; the impact of the growing demand for
carbon capture are also discussed here
III
Global energy trends
Review of the forecast increase in installed power generating
capacity around the world
IV
Power projects
Discussion on the current contracting strategies and
approaches to building power plants, and the impact of
sustainability initiatives
V
Capital costs
Analysis and breakdown of the current capital costs of building
power plants
VI
Scottish supply chain
Analysis of the forecast market value of particular areas of
equipment supply and an assessment of the contribution
Scottish companies could make
VII
Opportunities for
Scottish Companies
Summary of the opportunities identified
II
THERMAL POWER GENERATION
order to maintain capacity. The options for replacing this lost capacity are retrofits,
plant extensions or new plant.
Introduction
For the forecast period up to 2015, coal, natural gas and nuclear power will continue
to be the most important primary energy sources for electricity generation.
Efficiency
Increasing the combustion efficiency of both conventional and advanced new power
systems has become paramount. Facilities will increasingly be retrofitted or replaced
with higher efficiency plant.
Total world power generation demand is projected to grow from 18,920 TWh in 2006
to 24,980 TWh in 2015, with:
•
Coal-fired power stations increasing their share in total generation from 40% in
2006 to 44% in 2015
•
Gas-fired generation dropping marginally from 20% to 19% in 2015, as a result of
higher prices
•
Oil use in power generation continuing to decline, from 6% to 4%
•
Nuclear power suffering a fall in market share, from 15% to 13% in 2015
•
Conversely renewable generation (including hydro) is expected to rise from 18%
in 2006 to 20% in 2015
New coal fired power plants worldwide are being built to operate at 'supercritical' and
'ultra-supercritical' conditions of temperature and pressure, increasing electricity
generation efficiency to 40-50% and higher. China has engaged on an aggressive
strategy of increasing power generating capacity. It has already added over 100 GW
of coal-fired plant in 2006 alone. The first 1,000 MW supercritical plant came online
in November 2006 in line with the government's aim of phasing out small, inefficient
coal plant.
Environmental drivers
The following sections provide an introduction to each of the major energy
conversion processes, the associated supporting technologies and trends in
electricity generation of following main power generating technologies:
•
Coal-fired technology
•
Gas-fired technology
•
Nuclear technology
Emissions
Globally, standards on emissions continue to tighten leading to:
•
Installation and retrofit of established pollution-control technologies to address
sulphur and nitrous oxides (SOx and NOx) and particulate-matter emissions
•
Installation and retrofit of FGD (flue gas desulphurisation)
•
Precipitator upgrades on coal plant to reduce ash
Economic drivers
Carbon capture
Energy shortages
•
The IEA forecasts that global electricity demand will almost double over the next 25
years. On average, demand will grow by 3.2% pa in the period 2007 to 2015,
slowing to an average of 2% from 2015 to 2030. In developing countries, it will grow
three times as fast as in developed countries, tripling the installed capacity
requirement in those countries by 2030.
Emerging issues
Emerging environmental drivers include:
Obsolescence
A significant amount of plant in Europe and America is due to be decommissioned in
the next 10 years. The impact of the EU’s Large Combustion Plant Directive (LPCD)
in conjunction with plans to phase out nuclear power in countries such as Germany,
will give rise to a generation shortage, and replacement plant will have to be built in
Chapter II: Thermal Power Generation
A broad range of carbon capture technologies has been, and continues to be,
developed to address environmental concerns surrounding coal-fired and gasfired plant emissions.
-3-
•
Lack of cooling water for plants in countries with warm climates
•
The difficulty of obtaining planning permission to use river and sea water for
cooling purposes
•
Mercury emissions, associated with FGD processes
•
Ash disposal, particularly for mature plants where the original lifetime-design
capacity has been exceeded
Coal-Fired Generation
•
Electricity generation outlook
Coal Fired Net Electricity Generation
The greatest increase in the demand for coal will be in the developing countries,
especially in developing Asia, where reserves are large and low-cost. OECD
coal use is likely to grow modestly.
Electricity Generation (TWh)
5000
2006
4000
Coal processes
2015
Coal technologies are continuously being developed to improve efficiency and meet
environmental challenges. The efficiency of the current generation of PC units has
steadily improved and today ranges between 30% and 45% depending on the quality
of coal used, ambient conditions and the back-end cooling employed. The various
technologies currently available or undergoing development are listed below.
3000
2000
Pulverised coal combustion (PC)
1000
In PC plant, the coal is first milled to a fine powder to increase the surface area and
thus allow a quicker, more even burn. The pulverised fuel is blown into the
combustion chamber of a boiler where it is burnt at high temperature. Steam is
produced in a water tube boiler to drive a steam turbine driven generator.
Afric a
Middle East
Region
Latin Americ a
Other As ia
India
China
Russ ia
Eastern
Europe
OEC D
Europe
OECD As iaPacific
United Stat es
0
Fluidised bed combustion
Fluidised bed combustion (FBC) allows most combustible material to be burnt,
including coal, biomass and general waste. FBC systems improve the environmental
impact of coal-based electricity, reducing SOx and NOx emissions by up to 90%.
Coal is burned in a reactor comprised of a bed (normally sand) through which air is
fed to keep the fuel in a turbulent state. This improves combustion, heat transfer and
recovery of waste products.
Projections of future coal use are particularly sensitive to assumptions about future
policies that might be adopted to mitigate greenhouse gas emissions. However, coal
will continue to dominate the fuel mix in most regions, with its share increasing
quickly in non-OECD regions, for the following reasons:
•
Coal is plentiful, widely distributed and likely to be available
•
Coal has consistently outperformed oil and gas on an equivalent-energy basis,
and despite a potential cost of carbon, coal is likely to remain the most affordable
fuel for power generation in many developing and industrialised countries for
several decades
•
Coal is considered relatively affordable and has less price volatility compared to
oil and gas
•
The use of indigenous reserves or the ability to access a well-provided and
affordable international market can enhance a country's or region's energy
security, and provide affordable, reliable power to drive economies and
development
The higher heat exchanger efficiencies and better mixing of FBC systems allows
them to operate at lower temperatures than conventional PCC plant. In addition, by
elevating pressures within a bed, a high-pressure gas stream can be used to drive a
gas turbine, generating electricity. FBC systems fit into two groups, non-pressurised
systems (FBC) and pressurised systems (PFBC), and two subgroups, circulating or
bubbling fluidised bed. At present, the largest operating coal-fired FBC unit is 320
MW. The first supercritical CFBC unit (460 MW) is currently undergoing construction
in Poland, and is scheduled to operate in the first half of 2009.
Super- and ultra-supercritical combustion
Supercritical (SC) and ultra-supercritical (USC) power plants operate at steam
pressures above the critical point (22 MPa, 221 bar). Efficiencies are now up to
-4-
Coal-Fired Generation (continued)
46% for supercritical and 50% for ultra-supercritical with resultant lower emissions
than traditional coal-fired plant.
More expensive materials are required to withstand the high temperatures and
pressures; however the higher capital cost is balanced by the increased efficiency,
which brings fuel cost savings.
IGCC also uses 30-40% less water than a conventional plant and up to 90% of
mercury emissions can be captured (and at a up to 10% lower cost than for a
conventional plant). One of the main barriers to the widespread uptake of IGCC in
the past has been capital cost. Further developments to improve efficiency and
reliability and to reduce costs are ongoing. Only five coal fired 250 MW IGCC plants
are in operation worldwide.
Typical temperatures and pressures for different types of plant are:
Coal mine methane
Plant type
Temperature (ºC)
Sub-critical
Coal mine methane (CMM), including coal bed methane (CBM), is a relatively large
and undeveloped resource. Currently only a fraction of the CMM resource is
recovered in a suitable form to be used for heat or power production. Worldwide,
there are several power generation projects operating at coal mines.
Pressure (bar)
538
167
Super-critical
540-566
250
Ultra-supercritical
580-620
270-285
Power production from CMM has been developing for more than a decade in
countries such as Australia, Germany, Japan, the UK and the USA. In the past two
years there have been rapid developments in CMM utilisation for power production in
a number of markets, most notably China, but also in Poland and Ukraine.
According to 2005 data, there are roughly fifty projects operating worldwide at
abandoned and active coal mines, ranging in size from 150 kWe to 94 MWe and
totalling more than 300 MWe. An important driver for CMM in developing countries
is the Clean Development Mechanism - there are currently five registered CMM
projects and likely to be many more.
Supercritical technology has become the preferred technology for new plants in
OECD countries and increasingly so in China. More than 240 super-critical units are
in operation worldwide, including a number in developing countries. China currently
has 22 supercritical units in operation, providing almost 14 GW of electricity
generation. There are also 24 ultra-supercritical units operating worldwide, which
achieve even higher efficiencies, with units in Denmark, Germany, Japan, the
Netherlands, and USA. Temperatures and pressures above those of ultrasupercritical plant could potentially yield further efficiency improvements, however,
new materials must be developed to handle such extreme operating conditions.
Underground coal gasification (UCG)
Where mining is no longer taking place, for economic or geological reasons, UCG
permits exploitation of deposits by the controlled gasification of coal seams in situ.
CO2 from the process can safely be returned to the gasified seam, resulting in zero
emissions and very little ground disturbance. Feasibility studies and demonstrations
are ongoing in the UK, Russia, China, South Africa and New Zealand, amongst
others.
Integrated gasification combined cycle (IGCC)
Integrated Gasification Combined Cycle (IGCC) is another advanced technology
which holds out a number of benefits for coal-fired power generation. Coal is not
burnt to raise steam, as with conventional power plants, but instead reacted to form a
synthesis gas of hydrogen and carbon monoxide. A gas turbine is used to generate
electricity, with waste heat being used to raise steam for a secondary steam turbine.
IGCC offers efficiencies up to 50%, with a potential of 56% in the future –
significantly improving the environmental performance of coal.
Development of new coal technologies
Technologies that aim to meet coal's environmental challenges are collectively
referred to as Clean Coal Technologies (CCTs). The IEA defines CCTs as those
which facilitate the use of coal in an environmentally satisfactory and economically
viable way.
Pollutant emissions are reduced compared to advanced conventional technologies
by up to:
•
33% less NOx
•
75% less SOx
The environmental challenges can be summarised as:
•
almost no particulate emissions
•
-5-
Improving combustion technologies to increase efficiency and reduce emissions
Coal-Fired Generation (continued)
Reducing CO2 emissions with the development of carbon capture and storage
•
Eliminating emissions of particulates, NOx and SOx
will increase to 41%, as the new coal fired plants that being built to replace the
existing ones are expected to be far more efficient.
The following diagram illustrates recent and expected improvements in generation
efficiency (%) and reductions in emissions of carbon dioxide (CO2 g/kWh) for coalfired plant.
Various technologies including some of those described above are undergoing
development in order to provide an environmentally satisfactory method of using coal
as a basic fuel for power production in new plants, including:
Supercritical coal-fired plant along with flue gas cleaning units
•
Fluidised bed combustion mainly with subcritical steam turbines, together with
sorbent injection for SO2 reduction and particulates removal from flue gases
•
Combined cycle pressurised fluidised bed combustion (PFBC) (using both gas
and steam turbines) with bubbling bed boilers, uses sorbent injection for SO2
reduction and particulate removal from flue gases
•
•
Efficiency and CO2 Emissions
1200
55
1100
50
Efficiency %
•
Integrated gasification combined cycle (IGCC), where the syngas stream is
cleaned of H2S and particulates before combustion and expansion of the
combustion products through the turbine
Combined heat and power (CHP) applications where the (subcritical) steam
turbine is designed to produce both power and useful heat for process or district
heating
1000
45
900
40
800
700
35
600
30
500
400
25
300
200
20
1950
A particularly relevant development is Carbon capture and storage (CSS). CCS is
the process of removing CO2 from flue gases and storing it safely, for example into
deep saline aquifers, expired oil and gas reservoirs or using it for enhanced oil
recovery. CCS is discussed further at the end of Chapter II.
CO2 Emissions g/kWh
•
1970
1990
2010
2030
Year
Technology Progression
Improvements in efficiency
Although significant progress has been made in clean coal technologies in the last
decade, considerable challenges remain in exploiting the remaining potential,
particularly for low-grade coals. Considerable research is under way to, for example,
overcome fouling problems in gasification and combustion with high ash coals and to
develop cheaper and more efficient drying systems for high-moisture coals.
Subcritical
Ultra-supercritical
The higher efficiencies are only achievable with the use of more complex technology
such as super-critical plant. However, the payback on the investment is two-fold,
and the market place will likely pursue the more complex technology to meet
environmental demands and be financially viable.
The IEA estimates that the average efficiency of coal fired generation will increase
from 34% in 2006 to 36% in 2015 and to 38% in 2030. In OECD countries, efficiency
Supercritical, IGCC
-6-
Gas-Fired Generation
Technology
•
Gas Fired Net Electricity Generation
Electricity G eneration (TWh)
1000
•
2006
2015
800
600
•
400
200
Af rica
Middle East
Latin America
Other As ia
Region
India
China
Russia
Eas tern
Europe
OEC D Europe
OECD As iaPacif ic
United St ates
0
•
Natural gas continues to be the first choice energy source for new power generation
plants in developed countries; however the total amount of electricity generated from
natural gas will still be around half that of coal in 2015. Detailed trends include the
following:
•
•
•
•
•
•
1
At the end of 2008, gas’s share of the UK electricity generation mix reached 50%
1
for the first time .
Gas demand is increasing fastest in developing countries; the biggest regional
increase is in the Middle East, where gas resources are extensive.
Although natural gas is more environment-friendly than coal, its volatile price and
availability are likely to affect its future use in new power plant.
New combined-cycle gas turbine plants are projected to absorb over half of the
increase in gas demand.
The share of natural gas in the power generation fuel mix is falling as a result of
higher gas prices.
In the EU, there is more gas-fired capacity under construction than coal due to
tightening CO2 regulations and the value of the flexibility of gas.
•
Developments
•
•
•
http://stats.berr.gov.uk/energystats/etdec08.pdf
Gas-fired generating plants are very efficient at converting primary energy into
electricity and are cheap to build compared with coal and nuclear power plants.
A gas turbine extracts energy from a flow of hot gas produced by combustion of
gas in a stream of compressed air. Combined cycle gas turbine (CCGT) use
waste heat from the gas turbine process to boil steam to drive a steam turbine.
These plants offer efficiencies of up to 60%. Most new gas power plants in North
America and Europe are CCGTs.
Combined cycle plant has matured over the last twenty years and a number of
major suppliers of the key plant gas turbine plant have emerged including
Siemens, Alstom (including ABB), GE and Mitsubishi. The steam (the
combination) cycle turbines and the associated heat recovery from the gas
turbine’s exhaust gas using Heat Recovery Steam Generator (HRSG) are often
supplied by others.
Gas turbines can also be used in the simple/open cycle mode (OCGTs).
However, this is a less efficient mode of operation, and is usually part of a
phased approach to introducing a full combined cycle configuration which
provides considerably higher energy conversion efficiency. Natural-gas-fired
combined-cycle capacity is an attractive choice for new power plants because of
its fuel efficiency, operating flexibility, relatively short construction times (2-3
years compared to the 4-6 years that coal-fired and nuclear power plants typically
require), and because investment costs are lower than those for other
technologies per installed MW.
Smaller gas-fired generating units based on aero-derivative gas turbine
technology, such as the Rolls Royce RB211 turbines, are not considered in this
report.
-7-
Gas fired power plants are expected to be increasingly used for mid-merit order
and peak load, replacing oil to some extent.
A wave of construction of LNG plant is currently under way, which is expected to
double liquefaction and shipping capacity by 2010. LNG is generally the cheapest
method transporting gas for distances in excess of about 4000 kilometres, even
where it is technically feasible to build a pipeline
LNG accounts for over 80% of the increase in total inter-regional gas trading.
Nuclear
Nuclear power plants: New-builds and plans
Country
Nuclear Net Electricity Generation
2007 data
1000
Argentina
2006
800
2015
Brazil
Bulgaria
Canada
China
Finland
France
600
400
200
Africa
Middle East
Latin America
Other Asia
Region
India
China
Russia
Eastern
Europe
OECD
Europe
OECD AsiaPacific
United States
0
•
Nuclear power supply worldwide is projected to grow from 2,793 TWh in 2006 to
3,134 TWh in 2015. Installed capacity increased from 368 GW in 2006, and rose
to 372 GW in 2007 and is expected to rise to almost 400 GW in 2015. The most
significant increases will occur in China, Japan, India, Russia, the United States
and Korea.
•
Approximately 62 reactors are being built, or are at conceptual design stage. The
IEA estimates that 31 GW of nuclear power are under construction worldwide.
•
If existing policies continue unchanged, nuclear capacity in OECD Europe is
expected to decrease by 15 GW over the projected period, largely due to phaseout policies in Germany, Sweden and Belgium, which result in the closure of all
nuclear power plants in these three countries before 2030.
•
Under construction
2007 data
2008 update
1
1
1
2
8
2
10
1
1
18
1
1
26
2
1
7
53
2
1
India
Iran
Italy
Japan
Lithuania
Pakistan
Romania
4
1
8
1
4
1
3
3
1
1
2
11
1
2
Russia
Slovakia
South Africa
South Korea
Switzerland
Taiwan
6
9
2
1
6
Ukraine
United Kingdom
USA
TOTAL
1
6
2
1
3
9
1
2
1
17
14
28
2
1
28
2
3
6
34
144
8
35
174
2
2
35
1
62
Planned shutdowns: United Kingdom 4, Germany 17, Lithuania 1, Slovakia 1
Vendors
The major nuclear vendors are:
The following projections for plant which will be commissioned in 2015 are from a
survey produced by Germany’s VGB Power Tech organisation. The numbers for
plants under construction and plants in planning has changed dramatically
between the 2007 report and the 2008 report. The large change in acceptance of
nuclear as an alternative to coal-fired is mostly due to its almost zero carbon
emissions, making it acceptable to most political persuasions and many
previously anti-nuclear pressure groups.
2008 update
Planned
-8-
•
AREVA (France)
•
Westinghouse (USA) now owned by Toshiba
•
General Electric (USA) now in a joint venture with Hitachi
•
AECL (Canada)
•
ASE (AtomStroExport) and TPE (TechnoPromExport) both from Russia
Nuclear (continued)
The first four vendors have made submissions for approval to the UK’s Generic
Design Assessment (GDA) being carried out by the Nuclear Installations
Inspectorate of the HSE. A number of countries are already in negotiation for these
new designs. In the US, orders are already being taken for long order items such as
the pressure vessels, for which there is currently limited capacity in the world. In
2008, AECL withdrew from the UK’s GDA process to allow it to concentrate on
Canada’s domestic new generation building programme. Russian companies’
reputation is still recovering following the Chernobyl accident in 1987 and therefore
they have a more limited promotion of designs.
All the vendors have stated that they expect to partner with major EPCs
(engineering, procurement and construction contractor). AECL states that SNC
Lavalin will carry out this role with it and GE states that it currently has two preferred
EPCs: Washington Group/Black and Veatch and Zachary. AREVA has recently
signed a joint venture with Bechtel to develop a new version of its reactor. The
construction element is important to the vendors as they wish to have a dedicated
workforce available to ensure firmer pricing for the installations.
All the vendors are keen to put forward a message that local labour content will be
high, particularly as the projects develop from single units to multi-unit plant. This
may be a marketing strategy to gain political approval, but it is likely to be required to
actually manage the gaps in the supply chain. It help the buying countries balance
of payments, however, there must be opportunities to support these ’internal’
companies get up to speed with the technical and quality demands of the vendor.
Each of the new designs has a modular design philosophy. This will improve build
quality and allow much of the plant to be factory-built, and delivered to site as
modules, thus speeding up the site construction activities. The fact that these
modules are well-defined packages means that the vendors are able to sub-contract
the manufacture.
For instance in the nuclear island (the reactor block),
Westinghouse has defined 350 modules, and AECL, 185.
In common with the rest of the industry, the nuclear vendors have stated that they
will require additional suppliers for forgings and castings as current suppliers are
already seeing their order books over-booked. Currently in the UK, the vendors are
either buying companies who understand the nuclear regulator’s working
arrangements, or recruiting senior personnel who have been responsible for power
plant safety cases. Marketing reactors to other countries will also require vendors to
go through this process, and at least take on consultants to provide an independent
view of how their design satisfies other countries’ safety standards.
Key areas of activity
•
AECL are currently active in Canada, Romania, Argentina and Korea.
•
Areva is actively marketing its design to the UK, South Africa and the Middle
East. They expect to receive orders for more than 30 plants before 2020 and
build 4 to 6 reactors in the UK.
•
GE / Hitachi appear to concentrating on the US, with serious negotiations in
place with three utilities, and also in Japan.
•
Westinghouse has the broadest marketing activities with plant already being built
in China, a US order almost firmed-up and on-going negotiations with a number
of other countries.
•
Russia is promoting their designs to Turkey and India.
Decommissioning
Associated with the debate for new nuclear build, the nuclear industry has been
concentrating on decommissioning. This has moved forward considerably in the last
few years. The supply chain in Scotland has repositioned itself somewhat to satisfy
the needs of the UK’s Nuclear Decommissioning Authority (NDA). There is an
accepted shortage of nuclear-experienced engineers, and this report also reviews
the impact that the decommissioning projects have on the availability of resources to
service the new (nuclear) build opportunities. In general, the drive to accelerate the
decommissioning projects will support the case for new nuclear build, and many
companies see this as a way to gain the most appropriate experience for new-build
projects, and develop the skills of their workforces. Thus there are synergies
between the decommissioning supply chain and the chain which it is anticipated will
develop for new-build. The majority of the nuclear decommissioning opportunities are
discussed in Appendix 5 as this is area calls on different capabilities to those
required for new-build, albeit that some of the baseline technical knowledge is
common.
Nuclear new build
In March 2008 the UK’s Nuclear Industry Association (NIA) ran an event called ‘Meet
the Vendors’. This was for the mutual benefit of its members, many of whom have
aspirations to be suppliers to these companies if they are selected as vendors for
new-build in the UK. It was also for the benefit of the vendors who need to establish
a supply chain within the UK. At the event the vendors actually stated that they were
looking for suppliers for international projects. Competition is not cut-throat between
these companies as they are all expect a large market to develop over the next
couple of years, and no one of these companies will be able to service that market
on their own. Some of the companies already share suppliers.
-9-
Carbon Capture and Storage (CCS)
The figure below illustrates these 3 types of CO2 capture options:
Background
The IEA estimates that 69% of all CO2 emissions are energy-related. Its projections
are that CO2 emissions attributable to the energy sector will increase by 130% by
2050 in the absence of new policies or supply constraints, largely as a result of
increased fossil fuel usage. Reducing emissions, whilst increasing capacity, will take
an energy technology revolution involving increased energy efficiency, increased use
of renewable energy and nuclear power, and the decarbonisation of the by-products
of power generation derived from fossil fuels, the latter of which is the subject of this
section.
CO2 capture processes 3
CCS is the process of removing CO2 from flue gases and injecting it underground,
for example into deep saline aquifers, expired oil and gas reservoirs or using it for
enhanced oil recovery. This year, G8 countries endorsed the IEA’s recommendation
that 20 large-scale CCS demonstration projects need to be committed by 2010, with
a view to beginning broad deployment by 2020. During 2008, the profile of CCS grew
1
enormously. The IEA published its CCS – A key carbon abatement option report
and a number of working groups and journals such as Carbon Capture Journal 2
have appeared.
Capture, transport and storage
There following table describes key types of technologies for CO2 capture system:
Method
Description
Post-combustion
CO2is removed after combustion of the fossil fuel. The fuel is combusted
in air and the resulting CO2is scrubbed, absorbed, or otherwise captured
from the flue gas. This scheme can be retro-fitted to existing power
plants.
Pre-combustion
The fuel is de-carbonised via gasification, pyrolysis, or reforming prior to
combustion. The synthesis gas (syngas) from de-carbonisation is
primarily a mixture of CO2and hydrogen. The CO2is captured from the
syngas before the hydrogen is combusted.
Oxyfuel
combustion
The fuel is burned in oxygen instead of air (oxy-firing). The flue gas
consists of mainly CO2 and water vapour, which is condensed through
cooling. The result is an almost pure carbon dioxide stream that can be
transported and stored. The initial extraction of oxygen from air demands
a considerable energy input.
1
2
To transport small amounts of CO2 (less than a few million tonnes per year), or for
transportation over larger distances overseas, shipping is the most economically
feasible option. Pipelines are the preferred option for transporting larger quantities
for distances up to 1,000 km.
Storage of CO2 in deep onshore or offshore geological formations, such as oil and
gas fields, saline formations, un-mineable coal beds, uses much of the same
technology that has been developed by the oil and gas industry. Storage has been
proven to be economically feasible under specific conditions for oil and gas fields
and saline formations, but not yet for storage in un-mineable coal beds.
A number of research and development projects worldwide are exploring the issues
and opportunities, and demonstration plants are expected to be in operation from
2009 onwards. The most appropriate technology for individual CCS applications
depends on the power plant and its fuel characteristics. For existing plant which will
require retro-fitting of equipment, post combustion capture based on chemical
Available from http://www.iea.org/w/bookshop/add.aspx?id=335
Available on-line at www.carboncapturejournal.com
3
- 10 -
Original Source IPCC 2005, extracted from IEA Report: CO2 Capture and Storage report (2008) pg 47
Carbon Capture and Storage (continued)
absorption is the technology of choice. Pre-combustion capture based on physical
absorption would be the preferred option for coal fired integrated gasification
combined cycle (IGCC) plants.
Carbon capture readiness (CCR)
There has been much discussion on what CCR means. DECC’s consultation
document 2 entitled ‘Towards Carbon Capture and Storage’ provides a useful
definition of CCR. ‘CCR is the process of designing or building new combustion plant
so that it can be retrofitted with carbon capture technology and linked via appropriate
transport routes to long term storage once the technology becomes technically and
economically viable.’
Obstacles
CO2 capture and storage really only makes sense for highly efficient plants; the
capture and transportation processes are energy-intensive, reducing overall plant
efficiency and adding considerable capital cost. Typical loss in plant efficiency is 6 to
12%. The IEA estimates that:
•
Therefore CCR is linked to four factors:
• suitable space on the installation site for the equipment necessary to capture and
compress CO2
Capture and storage from coal fired power plants will typically cost USD50 per
tonne CO2mitigated, once the technology has matured. However, today’s costs
are about twice as high as this.
•
assessments of the availability of suitable storage sites
Total electricity generation costs including CCS are about 75% to 100% higher
than for conventional steam cycles without CCS. This may reduce to 30% to
50% in the longer term.
•
suitable transport facilities
•
the technical feasibility of retrofitting for CO2 capture
•
In terms of cost per tonne of CO2 captured, costs are USD40-55/t for coal-fired
plants, and USD50-90/t for gas-fired plants.
•
In terms of cost per tonne of CO2abated, the figures for coal-fired plants in 2010
are around USD60-75, dropping to USD50-65/t CO2by 2030; and for gas-fired
plants, USD60-110 in 2010, dropping to USD55-90 by 2030.
This supports the assessment made in an earlier IEA report from 2007 referenced by
DECC, but not readily available. The definition lists 19 existing plant items which
would need to be modified to address a post- combustion capture process such as
amine scrubbing, including many power station common plant areas such as water
treatment, cooling water, waste water and fire protection systems.
•
OECD Coal-fired Power Plant Investment Cost with Carbon Capture 1
without carbon capture
For additional information, the reader is referred to the Sustainability sub-section
within Chapter IV, in particular to the discussion on the need to ‘future-proof’ designs
for all future changes in operational demands.
with carbon capture
Subcritical PC
CCS demonstration projects
Supercritical PC
The main challenge for CCS is to lower costs and demonstrate reliable operation.
The addition of CCS equipment to a power plant will significantly increase the capital
cost, not least because the overall thermal efficiency is lower.
Ultra-supercritical PC
CFBC
A number of competitions are being held round the world to simulate development
and deployment of CCS as quickly as possible. In the UK, a competition funded by
DECC is currently underway. ‘The project should demonstrate post-combustion
CCS on a coal-fired power station, with CO2 stored offshore. The government will
consider a phased approach to the project as long as the full CCS chain is
demonstrated by 2014, and the project captures around 90% of the CO2 emitted by
IGCC
1000
1500
2000
2500
3000
3500
4000
USD (2006) per KW
1
Table adapted from Table 13.9, paged 365, World Energy Outlook 2007, International Energy Agency (IEA).
Original Sources: IEA and EPRI databases; IEA (2006) Energy Technology Perspectives, OECD/IEA, Paris;
MIT (2007), The Future of Coal – Options for a Carbon Constrained World, March, MIT, Cambridge.
2
- 11 -
http://www.berr.gov.uk/files/file46810.pdf
the equivalent of 300 MW generating capacity as soon as possible thereafter 1 . A
decision has been taken to only consider post-combustion capture, as only this
method could be retrofitted to existing plant.
Hydrogen Energy’s decarbonised fuel (DF) projects
Hydrogen Energy is a joint venture between BP and Rio Tinto, after Rio Tinto bought
into the earlier work done by the then BP Alternative Energy. It is likely that
5
Hydrogen Energy’s well documented DF-4 / HPAD (Hydrogen Power Abu Dhabi)
project will proceed.
The European Commission has recently proposed legislation to encourage CCS, by
helping fund up to 12 demonstration plants and by providing a legal and regulatory
2
framework to make geological storage of CO2 possible .
This project will separate natural gas via a reformer into a synthetic gas (syngas)
which is then scrubbed to remove the CO2 to leave pure hydrogen for combustion in
a gas turbine. Another Hydrogen Energy project, DF-2 in California, if it proceeds,
would use oil-coke rather than gas, thus the interest by Rio Tinto as it will have future
possibilities with mined coal. The process is generally as the IGCC process
described earlier. DF-1 was the Peterhead project which would have used the Miller
field for enhanced oil recovery (EOR).
The IEA expect that CCS technology will be mature by 2020 following the
implementation of at least 20 full-scale CCS projects. Several industrial-size
demonstration CCS projects have been announced in Europe, North America,
Australia and the Middle East. A total of 28 coal and gas fired demonstration
projects are proposed worldwide.
The UK’s carbon capture competition
Up to 1.7 million tonnes of CO2 per year will be injected into the (DF-4) HPAD oil
field, replacing natural gas which was previously injected to maintain pressure and
provide EOR. The natural gas will also be recovered. The project requires total
capital investment (excluding CO2 transportation and storage) of about $2B.
Currently a Front End Engineering and Design (FEED) process is being completed. If
a decision to proceed can be made at the end of 2009, the plant could be in
commercial operation in early 2013.
3
The competition announced in 2007, by the then DTi, is for a demonstration plant
capturing the carbon dioxide from a 300~400 MW generating unit. The government
will provide funding in the order of £100M. The competition has now reached the
shortlist stage. Only parties offering post-combustion capture are being considered,
as it is considered that this is where the greatest need is. It is also considered that
there will be considerable opportunities for British companies to export the
technology, once it has been proven. The view that there will be export opportunities
4
is supported by the Royal Society. The short list consists of:
•
ScottishPower Generation, in partnership with Marathon proposes to capture half
a unit’s worth of CO2 emissions from a unit at Longannet Power Station. This
would capture the CO2 for the equivalent of a 300 MW generating unit. Aker
Clean Coal and Aker Solutions are also partners in the bid.
•
E.ON has proposed CCS at its new Kingsnorth station – this is described in more
detail in the Appendix 4 case study.
•
The third shortlisted entrant was Peel Energy’s proposals for a new 400 MW
supercritical plant. Peel Energy and Denmarks’s Dong Energy had set up a joint
venture company, Peel Energy CCS Ltd., however, as this is being written, RWE
has made a major investment in Peel Energy’s CCS business, thus all three
major UK generators are now actively involved in developing CCS solutions.
FutureGen
In the United States, the Department of Energy’s National Energy Technology
Laboratory (NETL) issued a funding opportunity announcement (FAO) in June
(2008). This is a restructured version of a programme initiated originally in 2003.
Similarly to the UK competition, and the Hydrogen Energy projects, this programme
is well reported 6 . The website includes links to the funding announcement. The
announcement refers to IGCC or ‘other advanced clean coal-based generation
technology with CCS’. The announcement also states that $290M funding will be
available in 2009, with $1000 in subsequent years. Currently the most reported
submission is for a plant at Mattoon, Coles County, Illinois, with a target capture rate
greater than 81%.
Overleaf is a selection of the other major CCS projects currently in planning or
underway.
The winner will not be announced until the end of 2009. It is hoped to have a plant
running by 2014.
1
http://www.berr.gov.uk/energy/sources/sustainable/carbon-abatement-tech/ccs-demo/page40961.html
http://www.reuters.com/article/environmentNews/idUSL1746940520080417
3
http://www.berr.gov.uk/whatwedo/energy/sources/sustainable/ccs/ccs-demo/docs-qa/page42503.html
4
http://royalsociety.org/displaypagedoc.asp?id=29510
2
5
6
- 12 -
http://www.hydrogenenergy.com/38.html
http://www.netl.doe.gov/technologies/coalpower/futuregen/index.html
Major CCS projects currently in planning or underway
Developer
MW
Year
Remarks
SaskPower
(Canada)
GreenGen
(China)
Dynamis
(Europe)
RWE
(Germany)
300
2012
250
2018
250
2012
400
to
450
250
2014
Lignite with post-combustion capture or oxy-fuel
technology, will capture approximately 8,000 t CO2/d.
250 MW IGCC plant by 2009, with scale-up in 2012 and
full integration with CCS by 2018.
Large scale power generation using advanced power
cycles with hydrogen-fuelled gas turbines.
IGCC technology; CO2 will be stored in a depleted gas
reservoir or saline aquifer.
Progressive
Energy (UK)
800
2011
Powerfuel
(UK)
900
Post2012
E.ON (UK)
450
Post2012
E.ON (UK)
2x
800
1000
2015
500
2011
Vattenfall
(Germany)
RWE nPower
(UK)
Carson
Project
(USA)
Dong Energy
FutureGen
(USA)
2020
2016
2005
275
2012 2017
increasing amounts of environmental clean-up equipment, in which the traditional
power plant components are becoming ‘lost’ in the new process plant. This trend is
likely to continue as power plant owners install more of such equipment. Thus it
might be surmised that much of the supply chain opportunity in retrofit work will be
for process plant oriented items associated with technologies such as carbon capture
rather than traditional power station plant components.
Regarding Scottish expertise in CCS, Doosan Babcock has been heavily involved in
carbon capture initiatives and is actively involved in a number of new and retrofit
projects which may include carbon capture. Babcock’s Dr Mike Farley is a member
of DECC’s Advisory Committee on Carbon Abatement Technology (ACCAT), and
makes regular presentations 1 on this topic. At the University of Edinburgh, the
Scottish Centre for Carbon Storage (SCCS) is a leading player in the CCS debate.
The Scottish Government are contributing to the CCS debate both directly, and via
the DECC consultation discussed earlier.
30 MW CCS pilot plant now operational, RandD platform
for development of a larger commercial-scale plant;
1,000 MW by 2020.
Use IGCC and capture 5mt of CO2/yr to be used for EOR
in the central North Sea. The project will be able to
operate on coal or petroleum coke, with the possibility of
including biomass.
IGCC CCS project is to be located at the Hatfield Colliery
(South Yorkshire), closed in 2004 and due to reopen by
end-2007.
IGCC project will be co-located with E.ON’s existing gasfired power plant in Killingholme. The first phase of the
project would be the construction of the power plant, with
CCS being added in a second phase.
Two new 800 MW supercritical units at its Kingsnorth
power station.
Investigate supercritical technology combined with postcombustion CCS at Tilbury. This is the largest of all the
proposed CCS projects to date.
Will use a gasifier to convert petroleum coke to H2 and
CO2, and then use the hydrogen as a fuel for a 500 MW
power station and store up to 5 Mt CO2/yr deep
underground.
Esbjerg, Denmark (Castor project)
The non-carbon emissions issues
This short section has been included to ensure that the reader does not associate
carbon capture with tackling all the emissions issues. In the UK, sulphur dioxide
emissions have generally been addressed with retrofitting flue gas desulphurisation
(FGD) plant, or with plans to install it along with new plant. There is still a sizeable
opportunity for retrofit to plant outwith the EU and North America. These plants can
add 7-15% 2 to the capital cost of a plant. Nitrous oxides (NOx) emissions remain an
issue requiring separate technology.
Various improved burner designs have been developed, along with over-fire air
additions, such as the boosted over fire scheme installed at ScottishPower’s
Longannet Power Station. Selective catalytic reduction (SCR) provides 80-95%
reduction in NOx emissions, however, at a further additional cost of 4-8% 3 capital
cost. The EU Industrial Emissions Directive (IED), which is expected to come into
force before 2020, will put further pressure on the plant operators, and suppliers are
likely to be asked to take this into consideration within any designs offered in the
short term. This falls outwith the 2015 window being considered in this report. The
IEA’s Clean Coal Centre website provides detailed descriptions of the various
technologies available. 4
IGCC to produce electricity and hydrogen as well as CCS.
The project is a partnership between the US DOE and
industry.
CCS skills in Scotland
1
At a recent Industrial and Power Association (IPA) lecture, ScottishPower's CCS
Programme Manager, Steven Marshall, commented that since the late 1980's much
of the investment in existing power plant has been focussed on dealing with the
environmental challenges arising from fossil fuel use. This has meant that power
stations have evolved from plants comprising only a power island to plants with
Mike Farley presentation to the 2008 All Energy conference in Aberdeenhttp://www.allenergy.co.uk/userfiles/file/Mike_Farley220508.pdf
2
The Word Bank’s International Finance Corporation’
http://www.ifc.org/ifcext/policyreview.nsf/AttachmentsBy Title /EHS_Draft_ThermalPowerPlants/$FILE/Draft++THERMAL+POWER+PLANTS+March_11_08.pdf
3
As above
4
http://www.iea-coal.org.uk/site/ieacoal/databases/clean-coal-technologies
- 13 -
New-Build Timescales
2015 projects. From the chart we can see that gas (CCGT) and coal fit well within
the 9 year lead time for 2015, however IGCC and carbon capture and the other
measures which are not the subject of this study, are likely to take longer to be
developed to a stage of repeat orders. It is thus proposed that these technologies be
considered in less depth at this stage, but should be reviewed again in the near
future.
Timescales for deployment
At this stage in the report, it is worth reviewing the generation technologies which are
likely to be dominant at the 2015 date – this date has been taken as the
commissioning date which will provide supply opportunities in the intervening (lead
time) period to build these plants. A number of innovative areas of technology have
been mentioned; however, not all of these will become mature and provide a steady
stream of sustainable supply chain opportunity by the 2015 date.
UK perspective
ScottishPower 2 has made an estimate of the total spend on power plant upgrades
and new build in the UK before 2025; this is illustrated in the graph below. The
estimated spend in the UK before 2025 could be as high as £75 billion, however this
figure includes a projected spend of £30 billion on renewable. Retrofit and new build
CCGT and coal plant will be required prior to 2015 to meet the energy gap forecast
by many due to the impact of closures due to the Large Combustion Plant Directive.
An estimate for the time to deploy 5GW of each of the various technologies has been
developed by Mott MacDonald. It was intended to communicate a broad view as to
how long it would take to create scale in a given technology, taking into account
development, planning permission and multiple project deployment, and assumes
1
that finance and political will support these technologies. The following chart shows
their predictions. For example, it is estimated that if five developers within the UK
each announced plans today to build a 1 GW supercritical coal fired power station, it
would be at least 8 years before all of those stations were built.
Power plant upgrade and new build spend in the UK before 2025
35
Timescales: years from today for 5 GW to be installed
Gas
30
GW
25
£ Billion
Nuclear
20
Coal Supercritical
15
Coal Subcritical
Coal IGCC
10
Carbon Capture and Storage
5
Biomass
0
Major transmission
Retrofit
(FGD & SCR)
0
2
4
Y6ears 8
10
12
14
Renewables
Scottish and Southern Energy’s (SSE) most recent half yearly results 3 detail its
investment programme for coal-fired and gas-fired plant. SSE identifies CCGT
technology remaining as the ’benchmark technology for some years to come, and
SSE has identified a series of options for additional CCGT plant’.
2
3
As presented at Power Scotland 2008, seminar organised by the Industrial and Power Association
New build
(nuclear)
16
The timescale includes the application and planning process, in addition to the
contracting, construction and commissioning time. There are huge uncertainties in
such estimates, and Mott MacDonald considers these to be educated guesses for
the purpose of framing policy than engineering targets. However they provide a
useful ‘weighting’ as to where the bulk of the business is likely to be in the lead-in to
1
New build
(CCGT & coal)
- 14 -
Martin Sedgwick, Head of Asset management, IET Power Generation Control seminar, Birmingham 1/12/08
http://www.scottish-southern.co.uk/SSEInternet/
III
GLOBAL ENERGY TRENDS
Long term primary energy demand
Electricity generation mix
Primary energy demand has increased by more than 50% since 1980. Fossil fuels
account for more than 80% of the world’s primary energy mix. Demand grows more
slowly in the 2008 forecasts compared to 2007 forecasts due to higher energy prices
and slower economic growth due to the global financial crisis.
•
Coal will continue to dominate the fuel mix in most regions, though its share
increases in non-OECD regions and falls in the OECD regions.
•
Relatively high world oil price have encouraged the shift from oil-fired generation
to natural gas and coal.
In their 2008 World Energy Outlook Report, the IEA forecasts the following growth for
the period 2006 to 2030:
•
In addition, high oil prices in combination with concerns about the environmental
consequences of greenhouse gas emissions are raising renewed interest in
nuclear power and renewable energy sources as alternatives to the use of coal
and natural gas for electric power generation.
•
Projections of future coal use are particularly sensitive to future policies that
might be adopted to mitigate greenhouse gas emissions.
Electricity use will almost double between 2007 and 2030, with its share of final
energy consumption rising from 16% to 24.9%.
Some $26.3 trillion of investment in supply infrastructure is needed to meet
projected global demand. The power sector will account for $13.6 trillion or 52%
of this total. Just over half the projected global energy investment is simply to
maintain the current level of supply capacity, as much of the current production
capacity will need to be replaced by 2030.
•
4000
3000
2000
1000
Africa
Middle East
Latin America
Other Asia
India
China
Russia
Region
Forecast Electricity Generation Mix, 2015
Global power generation is projected to grow from 18,921 TWh in 2006 to
24,975 TWh in 2015.
Oil 1,046 GW
Coal 11,110 GW
Renewable
4,969 GW
On average, electricity demand is projected to grow by 3.2 % per year worldwide
between 2007 and 2015. In developing countries, it grows three times as fast as
in the OECD, India and China experience the fastest rates of demand growth.
Nuclear
3,134 GW
Gas 4,725 GW
Chapter III: Global Energy Trends
2015
0
Electricity demand
•
2006
5000
Eastern
Europe
•
In the reference scenarios, over 70% of the growth in energy demand will come
from developing countries, where populations and economies are growing
considerably faster than in the OECD nations. China alone will account for some
30% of increased energy demand. The combined power-generation and heat
sector absorbs a growing share of global energy demand over the projection
period, rising from 38% to 42% in 2030.
OECD
Europe
•
Total Net Electricity Generation
6000
OECD AsiaPacific
•
An alternative policy scenario that considers the impact of additional measures to
address energy-security and climate-change concerns, global primary energy
demand grows by 1.3% per year over 2006-2030, resulting in an 11% saving in
2030 compared to the baseline scenario.
United States
•
World primary energy demand will grow by more than 45% between 2006 and
2030, at an average annual rate of 1.8%, assuming that there are no new
energy-policy interventions by governments.
•
- 15 -
Increase in Installed Capacity and Capacity Additions
A diagram to illustrate the forecast increase in installed generating capacity
worldwide between 2007 and 2015 can be found on the following page.
Total installed capacity
In the IEA reference scenario (2008), total installed power-generation capacity
worldwide is projected to rise from 4,344 GW in 2006 to 5,697 GW in 2015, an
increase of 1,353 GW. The EIA (2008) estimates the rise to be (from 3,889 GW in
2005) to 5,189GW in 2015. The difference of 508 GW between the estimates
demonstrates varying and uncertain nature between various forecasts.
Capacity additions
The IEA estimate that over the forecast period (2007-2015), total capacity additions,
including replacement and expansion, will be 1,690GW. These additions average
190GW pa. Therefore if the forecast increase in total installed capacity worldwide
1,353 GW, it could be supposed that over 300GW of current capacity worldwide are
due to come off line by 2015.
The majority of the forecasts in graphs and pie-charts in this chapter only present the
increase in total installed capacity; they do not represent the total new-build
(additional capacity) being built. The more conservative IEA data (for the projected
increase in capacity) has been used for the majority of the forecasts. However, for
the United States, EIA (the responsible U.S government body) data is presented, as
the IEA projections notably surpassed the EIA’s high growth scenario.
The IEA estimates that investment in the power sector (including renewables) over
2007-2015 will be around $5 trillion (2007 present value). Over $2 trillion will be
required for power generation, while the remainder will be for distribution and
transmission networks.
Significant existing capacity is expected to be decommissioned and replaced
throughout the world in the next 10 years. Therefore, the forecasts for (wholly) newbuild capacity are expected to be higher than the forecasts for increases in installed
capacity. Future levels of generating capacity will depend on how much of this
existing plant is retired from service and how much new plant is built.
Projected capacity additions and investment in power infrastructure
Capacity
Additions
(GW)
Over 600GW of power generation capacity is currently under construction around the
world, and expected to be operational by 2015. Three quarters of this new capacity is
being built outside the OECD.
Capacity under construction (GW)
Power- generation capacity under construction worldwide
1
200
154
GW
278
656
North America
379
121
260
OECD Europe
221
457
93
281
78
146
65
115
1,177
1,215
589
1,285
Eastern Europe
137
180
55
183
Asia
781
794
433
894
574
521
296
612
78
59
32
67
Middle East
Africa
Latin America
50
World
59
59
28
58
121
123
41
84
1,691
2,197
867
1,941
0
Coal
Gas
Oil
Nuclear
Hydro
Wind
Other
Renewables
1
Original Source: Platt’s World Electric Power Plants database, January 2008, adapted from IEA World
Energy Outlook 2008. Note: includes power plants considered as ‘under construction’ in 2007
2
- 16 -
Distribution
982
China
460
GW
Transmission
215
150
100
Power
Generation
514
NON-OECD
Total =613 GW
Non-OECD
OECD
Investment, 2007-2015 ($2007, billion)
OECD
OECD Asia-Pacific
250
2
Extracted from IEA World Energy Outlook 2008 p151
Forecast Increase in Installed Generating Capacity Worldwide, 2007 – 2015
Data Sourced from: World Energy Outlook 2008 (IEA)
NOTE 1: The forecasts only present the increase in installed capacity; they do not represent the total new-build capacity.
NOTE 2: The total generation represents all forecast generation including, oil fired generation, renewables and hydro generation.
- 17 -
Europe
•
OECD Europe
Trends
•
Electricity generation is projected to grow slowly, as a result of the slow
population growth and the already well-established electricity markets.
•
Europe has an ageing power generation portfolio and the political decisions to
phase out nuclear power in countries such as Germany will give rise to a
generation shortage.
•
•
Electricity demand in OECD Europe is expected to rise from 3530 TWh in 2006
today to around 4,028 TWh in 2015.
Net Electricity Generation in OECD Europe by Fuel
Electricity G eneration (TWh)
Coal
Gas
1250
Nuclear
Fuel
Renewables
Utilities and other investors have made
plans for a significant number of newbuild projects due to the replacement
demand for old power plants and the
increase in electricity consumption in
Europe.
Country
Size
(MW)
No. of
Projects
Germany
33,435
33
According to Platts and Greenpeace over
64 GW of coal plant are in planning.
UK
8,700
8
•
VGB 2 estimates replacement demand of
around 300 GW by 2020 in the EU.
Italy
5,890
6
Poland
3,526
5
According to VGB 3 , new-build projects
with a joint capacity of roughly
186,700 MW have been announced,
consisting of:
Netherlands
6,200
5
•
Hungary
1,600
2
Bulgaria
750
1
France
700
1
Greece
600
1
Austria
800
1
Slovakia
885
1
Oil
1000
750
•
83 GW of natural gas projects
•
40 GW of lignite, hard coal and peat
•
7.8 GW of new nuclear power plant
Spain
under construction in the Finland and
Total
France, and a further 4 GW of
nuclear plant is being planned in
Bulgaria, Romania and the Slovak Republic
500
250
0
2006
Planned Coal Power Plants in
Europe 1
•
2015
1,200
1
64,286
65
In addition, output is being increased at existing plants.
Planned new plant
3
Planned New Power Plant capacity in the EU
(Announced from 2007 by 2016)
The IEA estimates that 158 GW of installed capacity will be added from 2007 to 2015
in OECD Europe. These values do not reflect the total new-build as a large number
of plants are due to be replaced in the next 15 years.
Nuclear 7.8 GW
Gas 82.7 G W
Renewables
53.3 GW
Forecast Capacity Increase in the OECD Europe, 2007 - 2015
Renewables
146 GW
Coal 39.8 GW
Coal 12 GW
Oil 3.5 GW
Gas 23 GW
1
2
3
- 18 -
Greenpeace analysis of coal power plants, data from Platts, Power in Europe, issues 2006/07
Facts and Figures, Electricity Generation 2007, VGB PowerTech
Facts and Figures, Electricity Generation 2008, VGB PowerTech
Europe (continued)
•
The realisation of the proposed new-build projects will depend on future primary
energy price trends and political conditions.
•
Natural gas is expected to be by far the fastest-growing fuel for electricity
generation in OECD Europe, while high world oil prices and environmental
concerns lead to decreases in the use of petroleum and coal.
•
generators opt-out of this obligation, the plant will have to close by the end of
2015 or after 20,000 hours of operation from 1 January 2008, whichever is the
sooner. 2
•
Renewable electricity generation (primarily non-hydropower) in OECD Europe is
also projected to increase significantly over the next ten years. Currently 7 of the
world’s 10 largest markets for wind-powered electricity generation are in Europe.
Plants in the UK opting out of the LCPD
Plant name
United Kingdom
•
Great Britain currently has a total of about 80 GW of electricity generating
capacity; National Grid forecasts that this will rise to about 110 GW by
2014/2015 1 .
Capacity (GW)
Increase in Generation Capacity for the UK
50
45
40
35
30
25
20
15
10
5
0
42.6
Sum of 2008/09 Capacity (GW)
32.3
Sum of 2014/15 Capacity (GW)
13.9
9.6
3.9
Coal
Gas
Hydro
Nuclear
Oil
According to the above forecast, gas capacity will overtake that of coal by
2009/10 in the UK.
•
The total gas capacity will be made up of CCGT, OCGT, CHP and IGCC plants.
•
According to current timetables more than 6 GW of nuclear generation capacity
will have closed by 2015.
1
RWE nPower
1.1
Cockenzie (coal)
ScottishPower
1.2
Didcot (coal)
RWE nPower
2.1
Ferrybridge (stack 2) (coal)
SSE
1.0
Ironbridge (coal)
E.ON
1.0
Kingsnorth (coal/oil)
E.ON
2.0
Littlebrook (oil)
RWE nPower
1.2
Fawley (oil)
RWE nPower
1.0
Grain (oil)
E.ON
1.4
TOTAL CAPACITY
12
•
Potentially some of the plants listed above will have used up their 20,000 hr
allocation by 2011/2012 rather than 2015. This is likely to increase the pressure
on the current generating capacity, in so much as that derogations are likely to be
pursued.
•
Some of the above plants are being replaced by new plants. For instance,
Grain (B) CCGT plant will replace Grain (A) oil-fired plant shown above.
•
The LCPD requires large electricity generators, and other large industrial
facilities, to meet stringent air quality standards from 1 January 2008. If
2
National Grid 2008 Seven Year Statement, May 2008 and August 2008 Update
Tilbury (coal)
New build
Large combustion plants directive (LCPD)
•
Capacity (GW)
The decision to close the plants is a commercial decision for the plant owners,
and takes into account factors such as plant age and condition, the cost of
retrofitting appropriate equipment and other environmental restrictions.
Wind
•
Owner
•
3.6
0.4
Biomass
According to BERR, approximately 12 GW of coal and oil-fired generating plants
have opted-out and will have to close by the end of 2015, representing about
15% of Great Britain’s present total capacity.
- 19 -
Below is a list of all the conventional generating plants understood to be at
various stages in the development process in the UK using information from
National Grid and BERR.
BERR, Energy markets outlook: October 2007, Chapter 4 - Electricity
Europe (continued)
UK conventional generating plants in planning or construction
Planning
status
Company / Location
Type of
project
Granted
RWE nPower, Staythorpe
CCGT
1,650
Granted
Centrica, Langage, Plymouth
CCGT
890
15/11/2000
Granted
ESBi, Marchwood Power
Station, Hampshire
CCGT/OCGT
860
28/11/2002
Granted
Conoco Refinery (Immingham
CHP)
CHP CCGT
extension
450
01/08/2006
Granted
Severn Power Ltd., Uskmouth
CCGT
800
21/08/2006
Granted
E.ON, New Isle of Grain Station
CCGT
1,200
31/10/2006
Granted
E.ON, Drakelow Power Station
CCGT
1,220
16/10/2007
Granted
EDF, Energy West Burton Power
Stations
CCGT
1,270
30/10/2007
Applied for
RWE nPower, New Pembroke
Power Station
CCGT
2,000
06/01/2005
Applied for
EDF Energy New Sutton Bridge
B
CCGT
1260
23/12/2005
Applied for
E.ON, Kingsnorth, Medway
Coal-fired
1,600
11/12/2006
Applied for
Port Talbot Power Station
CCGT
1,300
05/01/2007
Applied for
Thor Cogeneration Ltd,
Teesside
CCGT
1,020
19/01/2007
Applied for
Conoco Phillips
CHP CCGT
800
12/07/2007
Applied for
Bridestones Ltd
CCGT
860
17/08/2007
TOTAL
Capacity
(MW)
Date of
decision/
application
•
It is anticipated that there will be increased competition for construction
resources, in particular, if other planned capital projects in the UK all go ahead.
•
Specialist engineering skills, for example in reactor engineering, would be
needed in the short term for design and licensing; these are in short supply and
face a demand overlap with the submarine reactor and nuclear decommissioning
programmes.
•
Delays to major infrastructure projects of several years are not uncommon due to
the planning and consents processes for both generating plant and the related
transmission network reinforcements.
•
The proposed reforms in the government’s ‘White Paper – Planning a
Sustainable Future’ aim to make the planning and consents regime, including for
major energy infrastructure projects, more streamlined and certain whilst
ensuring that the rights of interested parties are safeguarded.
•
The longer lead times for nuclear power would allow time for the industry to plan
ahead for the skills needed to build and operate the stations and to manage
supply chain constraints through such measures as placing contracts well in
advance to secure slots in manufacturers’ order books.
Lead times in the UK
•
17,180
•
The above table does not include the recent announcements by EDF / British Energy
to build new nuclear plant.
Influences and constraints on new build
•
Building significant numbers of new power stations, and reinforcing the
associated transmission/distribution network infrastructure, will strain the
engineering sectors of most developed countries.
- 20 -
Lead time from decision to invest through to commissioning are estimated as
follows:
•
For a CCGT power station: approximately 5 years, including 2 years for
design, planning consent, project planning and permitting, 2 for construction
and six months for commissioning
•
For a coal-fired power station: approximately 7 years, including 4-5 years for
construction
•
For a new nuclear power station: approximately 8-10 years, with 5 years for
construction, but after an extended licensing period
There may be scope for some time savings in the front-end, especially for a fleet
of identical stations; however growing demand for new power stations from
around the world is likely to lead to longer order books at the key manufacturers.
Europe (continued)
Eastern Europe
Net Electricity Generation in the Eastern Europe
Coal
Elec tric ity Generation (TWh)
Russia
Forecast Capacity Increase in Russia, 2007 - 2015
Gas 8 GW
Nuclear 4 G W
Renewables
8 GW
Coal 14 GW
•
Russia has announced plans to increase its nuclear power capacity over the midterm, in order to lessen the reliance of its power sector on natural gas and
preserve what is becoming one of its most valuable export commodities.
•
As a result, electricity production from Russia’s nuclear power plants is projected
to grow by 3.7% per year on average in the reference case, while natural gasfired generation increases at the slower rate of 2.2% per year.
•
•
•
•
Nuclear
Renewables
150
100
50
0
2015
Planned and proposed plant in Eastern Europe (MW), Dec 2007
Source: Platts
Country
Coal
Gas
Only 3 GW of new nuclear generating capacity has become operational in Russia
since 1991.
Albania
In 2006, an ambitious plan was proposed to complete the construction of 10 new
1,000 MW reactors and begin construction on another 10 reactors by 2015.
Bosnia-Herz.
4,210
Bulgaria
1,410
335
It is questionable whether the plan can be achieved within the announced time
frame, so instead it is estimated that up to 5 GW of nuclear capacity will be
added to Russia’s existing 22 GW by 2015.
Czech Republic
3,522
220-400
Hungary
700
2,823
One problem is that tariffs on nuclear power currently are much lower than those
on thermal generation, therefore raising nuclear tariffs will be necessary to attract
the private-sector capital investment.
Kosovo
1,800-2,100
Natural gas is the region’s fastest growing source of electric power, with an
expected 45% increase to 2015.
•
Coal-fired and nuclear power plants are also important regional sources of
electricity generation, with increases of 6% and 9% respectively, over the same
period.
Nuclear
1,200
Belarus
2,000
2,000
Estonia
Lithuania
Eastern Europe as a whole possesses ample natural gas resources, therefore
much of its electricity supply will continue to be provided from natural gas-fired
power plants.
•
Oil
200
2006
Other Eastern European countries
•
Gas
250
- 21 -
810-910
Poland
3,940-4,540
300
Romania
1,130-1,430
1,583
1,440
Russia
9,367
22,532
28,240
Serbia
730
900
Slovakia
1,615
880
Slovenia
866
1,000
Turkey
8,641
1,784
5,000
Ukraine
1,815-2,015
1,290
5,000
China
Overview
Forecast energy mix
Net Electricity Generation in Chi na by Fuel
Electr icity G eneration ( TWh)
Coal
Gas
Renewables
Coal
Oil
4000
•
Coal remains the dominant fuel in China’s electricity mix, coal-fired generation
accounted for 80% of total electricity supply in 2006.
•
Coal-fired generation is expected to increase at an average rate of over 7 % per
year.
•
The expansion of coal-fired generation in China will continue to be based on
pulverised coal, with supercritical steam cycle technology expected to play a
much greater role in the future, because of its efficiency and emissions
advantages.
•
China has made considerable progress in the implementation of state-of-the-art
coal-fired generation technologies, by building world-class, larger and more
efficient power plants.
•
China added 18 GW of supercritical plant in 2006, bringing total supercritical
capacity to about 30 GW. There are over 100 GW of supercritical plant on order,
implying that the share of supercritical technology in new capacity will increase
significantly over the next few years.
•
The new coal-fired plants are expected to be concentrated in Shanxi, Shaanxi,
Inner Mongolia, Guizhou, Yunnan, Henan, Ningxia and Anhui, areas with
convenient and economical access to the coal resources.
3000
2000
1000
0
2006
•
Nuclear
5000
2015
In less than a generation, China has changed from being a minor and largely
self-sufficient energy consumer to become the world’s second-largest and
fastest-growing energy consumer and a major player on the global energy
market.
•
China’s annual electricity demand has been growing at an annual rate of 14%
since 2000.
•
Installed power generation capacity increased from 66 GW in 1985 to 517 GW in
2005 and 622 GW in 2006.
•
105 GW of new power plants, most of which are coal-fired, were built in 2006
alone. About 200GW is reported to be under construction in China.
Gas
•
In the period 2007-2015, generation is projected to grow by 9% per year.
•
Natural gas accounted for less than1% of total generation in 2006.
•
Total electricity generation is expected to reach 5,559 TWh in 2015 and installed
capacity 1,189 GW.
•
Gas-fired electricity generation is expected to grow rapidly, doubling in installed
capacity to 33 GW in 2015.
•
Although gas is not competitive with coal for power generation under current
market conditions, China is pursuing policies to diversify the electricity mix and to
reduce local pollution, which could boost the share of gas in certain regions.
•
An import infrastructure for LNG is being established as demand increases
beyond domestic supply.
Forecast Capacity Increase in China, 2007 - 2015
Gas 19 GW
Coal 417 GW
Nuclear 14 GW
Oil 4 GW
Renewables
113 GW
Nuclear
•
- 22 -
Nuclear generation amounted to 55 TWh, or just under 2% of total generation in
2006, installed capacity was 7 GW in 2006.
China (continued)
•
Two new reactors were connected to the grid in 2006 and 2007, bringing the total
number of reactors in operation to 11 and installed capacity to 8.6 GW.
•
The heat from CHP has been mainly used in China in the industrial sector and for
central heating in northern cities.
•
Four reactors with a total capacity of 3.2 GW are under construction, expected to
be completed by 2010-2011.
•
Coal remains the predominant fuel, with a small amount of oil use and natural
gas now beginning to be used in this application.
•
The government’s target is to have 40 GW in place by 2020, which is considered
to be ambitious.
•
•
IEA estimate that installed nuclear capacity will reach 21 GW in 2015 and 25 GW
in 2020.
Efforts are being made to encourage gas-fired CHP schemes. A dozen pilot
projects of gas-fuelled tri-generation are being undertaken in Shanghai and
Beijing.
•
•
China is pursuing a dual objective in nuclear technology: a) to adopt a
standardised technology for long-term nuclear development and b) to develop a
home-based technology, so that China becomes self-sufficient in reactor design
and construction, as well as other aspects of the fuel cycle.
The potential for CHP is significant, mostly concentrated in Beijing, Tianjin and
regions in the Yangtze River Deltas, including Shanghai, Jiangsu and Zhejiang
provinces, where direct coal combustion is now forbidden in many cities.
•
Power generation from CHP plants is projected to reach over 600 TWh in 2030.
Main developers
New technologies
•
In 1997 most of the assets of the Ministry of Power (nearly all of the grid, as well
as 40% of generating capacity) were transferred to the newly formed State Power
Corporation.
•
In 2002, the State Power Corporation was split into two transmission companies
and five power generation groups:
CCS
•
•
China sees CCS as a future technological option for greenhouse-gas emissions
abatement and is willing to join international efforts for its development.
International co-operation programmes have been initiated with APEC, Canada,
the European Union, the United Kingdom, the United States and others (Torrens,
2007).
•
CCS appears in China’s 11th Five- Year Plan.
•
Current experimental projects include:
•
A micro-pilot ECBM (Enhanced Coal-Bed Methane Recovery) project in
Shanxi province
•
A 300-400 MW demonstration project at the Yantai IGCC Plant (with the
option of future CCS and hydrogen production), which will closely follow the
China Huaneng (CHNG) Greengen first stage plan for a 250 MW IGCC
plant. The second phase of the Greengen will have a 400 MW IGCC and
CO2 separation / H2 power, and is planned for operation in 2015.
CHP
•
Combined heat and power (CHP) accounted for over 11% of total installed
generating capacity in 2005.
- 23 -
•
State Grid Corporation of China (SGCC) - 80%.
•
China Southern Power Grid (CSG) - 20%.
•
The five generation entities were initially given around 20 GW of capacity
each.
•
With China’s generation assets largely under the control of the state, generation
investments have been made primarily by state-owned or provincially-owned
entities, backed by government funding.
•
Transmission investments accounted for about 40% of total investment in the
power sector in 2006.
India
Overview
Forecast energy mix
Net Electricity Generation in India by Fuel
Coal
Gas
Nuclear
Renewables
Forecast Capacity Increase in India, 2007 - 2015
Oil
1000
Gas 5 GW
Coal 63 GW
800
Renewables
32 GW
600
400
200
0
2006
2015
•
To meet projected electricity demand, India's power generating capacity in total
will need to increase to 254 GW in 2015.
•
In the period 2007-2015, India is projected to build over 100 GW of capacity.
•
More than half of this capacity is projected to be coal-fired.
About 15 GW of coal-fired capacity was under construction at the beginning of
2007.
Capacity additions are expected to include the replacement of some older power
plants, mainly coal-fired.
•
India has the fifth-largest installed power-generating capacity in the world.
•
•
Primary energy demand has grown over the last thirty years at an average rate of
3.6% a year 1 .
•
•
•
Total electricity generation was 744 TWh in 2006. In the period 2005-2015,
electricity generation is projected to grow by 6.3% per year, and therefore
demand is estimated to be 1,286 TWh in 2015.
The total installed capacity in India has increased to 140 GW 2 in 2007 compared
to 86 GW 3 in 2004, an increase of over 60%.
•
The projected rate of increase in electricity consumption, estimated at as much
as 8-10% annually through to 2020, is one of the highest in the world.
•
The Indian government has announced plans to provide power to the entire
population by 2012, which would require an additional 69 GW of base capacity1.
2
3
Coal
Per capita electricity generation, at 639 kWh in 2005, is one of the lowest in the
world – over four times lower than the world average and 14 times lower than the
average in the OECD (8,870 kWh).
•
1
Nuclear 4 GW
http://www.worldcoal.org/pages/content/index.asp?PageID=402
http://powermin.gov.in/JSP_SERVLETS/internal.jsp
http://www.cslforum.org/india.htm
- 24 -
•
Coal is the dominant fuel in India's electricity generation, accounting for over two
thirds of total electricity produced.
•
India's coal-fired power plants are among the least efficient in the world. The
poor quality of available coal and inadequate maintenance of power plants
contribute to the low performance.
•
Improving the efficiency of coal fired power plants will be essential in helping to
meet some of the demand.
•
Currently all operating coal plant in India use subcritical steam conditions but a
move to supercritical conditions is beginning in order to raise efficiency.
•
Six supercritical coal-fired units, with a capacity of 660 MW each, were included
in the 10th Plan; however none of these units is expected to be built by 2015.
•
Sipat, a supercritical station of 3x 660 MW is the first such project of National
Thermal Power Corporation (NTPC), and , is due to be completed early in 2009.
India (cont)
•
In 2006, the Ministry of Power launched an initiative to develop large coal-based
plants, known as ultra-mega power projects. Each of these plants will have a
minimum capacity of 4 GW.
•
In the private sector, the first mega power project commenced at Hirma, where
Reliance Power and Southern Electric USA are constructing 3960 MW of
supercritical plant 1 .A further 39 GW of supercritical plant are proposed as part of
11th (2007-2011) and 12th (2012-2016) five year plans.1
•
The selection of the projects is based on competitive bidding and both coastal
and pit-head projects can be considered.
•
To streamline these projects, the government set up project companies to obtain
the necessary clearances before offering the project to bidders and to allocate
mining blocks to the pit-head projects.
•
India's nuclear power capacity is projected to rise to 8 GW by 2015, well below
the level targeted by the government.
•
NPCIL, the owner of India's nuclear power stations, is responsible for the
construction of new nuclear power plants.
Other technologies
•
India has a 6.2 MWe IGCC demonstration at Tiruchirapalli in Tamil Nadu. There
are plans for scaling up the process to 100-125 MWe, with the construction of a
demonstration plant at Aurya in Uttar Pradesh.
•
CCS is being investigated by India. India is a member of the Carbon
Sequestration Leadership Forum and involved in the FutureGen project.
•
No IGCC plants nor plants with CCS facilities are expected to be built before
2015.
Gas and oil
•
Gas-fired generation accounted for 9% of total generation in 2005. This share
has risen over the past decade as gas production has increased.
•
Total gas-based electricity generation is projected to increase by 6.6% per
annum.
•
The power sector faces gas supply shortages both because the government
favours allocation of gas supplies to the fertilizer industry and because adequate
supplies at the agreed price have not been forthcoming.
•
Equipment suppliers
Many gas-fired power plants still have to run on naphtha as a substitute or
remain idle because naphtha is too expensive to use. It is estimated that around
7 TWh of generation was lost in 2005 because of a lack of gas. The share of oil is
projected to fall to 2.6% of total generation in 2015.
Nuclear
•
Nuclear power accounted for 2.5% of total electricity generation in 2005, when
installed nuclear power capacity was 3 GW.
•
This rose to 3.6 GW in 2006, with the connection to the grid of Tarapur-3.
•
One unit at Kaiga was connected to the grid in April 2007 and three more units
are expected to be connected to the grid by the end of 2007.
•
The Indian government's nuclear power generation programme is ambitious, to
raise nuclear power generation capacity to 20 GW by 2020 and to 40 GW by
2030.
1
http://goliath.ecnext.com/coms2/gi_0198-211733/Sipat-new-generation-for-India.html
- 25 -
•
The main supplier of coal-fired power plants in India is Bharat Heavy Electricals
Ltd. (BHEL) and it is likely to maintain its dominant position in the future.
•
Manufacturers from industrialised countries are more prominent in the provision
of gas turbines and hydro plants.
•
The 11th Five-Year (2017-2012) plan calls for BHEL's manufacturing capacity to
expand from 6 GW a year now to around 10 GW.
•
There is some uncertainty regarding the rate at which BHEL will be able to
expand its manufacturing capacity and when it will be in a position to produce
more efficient power plants, notably supercritical ones.
•
In any case, due to the increasing demand for coal-fired power stations, it is likely
that more plant purchases will have to be made from other manufacturers.
•
Tata Power has selected Doosan Heavy Industries of Korea as supplier of five
boilers for the 4 GW Mundra project, one of the largest plants ever in India.
United States of America
•
Trends
Net Generation in the United States (EIA), 2005 and 2015
y
Coal
Gas
(eia
Nuclear
by
Fuel
Renewables
Oil
Energy mix
3000
•
Coal is the leading source of energy for power generation, accounting for almost
50 percent of the 2005 total and will remain that way until 2015 but increasing to
54 percent in 2030, in the absence of legislation restricting the growth of carbon
dioxide emissions.
•
Natural-gas-fired plants are built to maintain a diverse capacity mix, to serve as
reserve capacity, or to meet environmental regulations.
•
Electricity generation from natural-gas-fired power plants is projected to increase
from 2005 to 2020, as recently built plants are used more intensively to meet
growing demand.
•
The last new nuclear generating unit brought on line in the United States began
operation in 1996. Since then, changes in U.S. nuclear capacity have resulted
only from up-rating of existing units and retirements.
•
By 2010, 23 entities are expected to have submitted construction applications for
34 new nuclear power plants in the US, however it is likely to take many more
years to get the plants built.
•
14.6 GW of net nuclear installed capacity is expected between 2005 and 2030.
This includes 16.6 GW of capacity at newly built nuclear power plants and
2.7 GW from up-rates of existing plants, offset by 4.5 GW of retirements.
2000
1000
0
2005
2015
•
Most areas of the United States currently have excess generation capacity, but
all electricity demand regions are expected to need additional, currently
unplanned, capacity by 2030.
•
According to the EIA 1 , U.S. electricity consumption is projected to increase
steadily at an average rate of 1% per year. In comparison, electricity
consumption grew by annual rates of 4.2%, 2.6%, and 2.3% in the 1970s, 1980s,
and 1990s, respectively.
•
The EIA estimates that the increase in total installed capacity will be 51 GW
between 2005 and 2030.
•
In order to replace the 45 GW inefficient, older generating plants that are due to
be retired by 2030, estimates for capacity additions range from 182 GW in the
low growth case to 349 GW in the high growth case.
•
The majority of this growth in electricity generation is projected to be from coalfired generation and renewables, rather than natural gas.
•
However early capacity additions use natural gas.
•
Energy Policy Act (EPAct) 2005 and State RPS (renewables portfolio standards)
programs are expected to stimulate generation from renewable and nuclear
plants (18% and 6% of total additions, respectively).
Forecast Capacity Increase in USA (EIA), 2006 - 2015
Nuclear 2 GW
Renewables
36 GW
Gas 26 GW
Coal 15 GW
1
Annual Energy Outlook 2008, With Projections to 2030, June 2008, Energy Information Administration
(EIA), Office of Integrated Analysis and Forecasting, U.S. Department of Energy
Given the assumed continuation of current energy and environmental policies in
the reference case, CCS technology is not projected to come into widespread
use before 2030.
- 26 -
Other Regions of Interest
Middle East
•
Electric power generation in the Middle East region is projected to grow by 4.1%
per year, from 681 TWh in 2006 to 979 TWh in 2015.
•
Iran is the only country projected to add nuclear capacity, with completion of its
Bushehr 1 reactor expected by 2010.
•
There is little incentive for countries in the Middle East to increase their use of
renewable energy sources, renewables are projected to account for a modest 2%
of the region’s total electricity generation throughout the projection period 1 .
Net Electricity Generation in the Middle East
Elec tricity Generation (TWh)
Coal
Gas
Nuclear
Renewables
Oil
600
Forecast Capacity Increase in the Middle East, 2007 - 2015
500
300
Renewables
8 GW
200
Oil 8 GW
Coal 4 GW
100
0
2006
•
•
Yemen, the region’s poorest economy, is the exception, with only an estimated
50% of the population having access to electric power in 2002. Nevertheless,
population and income growth in the region are expected to result in growing
demand for electric power in the future.
In 2006, natural-gas-fired generation accounted for over half the region’s total
power supply; this share will increase over the period to 2015, as the petroleum
share of generation decreases slightly over the projection period.
•
The Middle East is the only region in the world where petroleum liquids are
expected to continue accounting for a sizable portion of the fuel mix for electricity
generation throughout the projection period.
•
Net Electricity
Generation in Africa
y
Coal
Natural gas is the largest source of energy for electricity generation in the Middle
East, and it is expected to continue in that role.
•
Israel is the only country in the region that uses significant amounts of coal to
generate electric power.
Gas
Nuclear
Renewables
Oil
500
250
0
2006
The Middle East region as a whole relied on oil-fired capacity to meet 36% of its
total generation needs in 2006, and that share is projected to fall only slightly, to
33% in 2015.
According to the EIA, demand for electricity in Africa is projected to grow at an
average annual rate of 3.5%.
Elec tricity Generation (TWh)
Most of the countries in the Middle East region have well-established electricity
infrastructures, with electrification rates above 90%.
•
Africa
2015
•
•
Nuclear 1 GW
Gas 56 GW
400
2015
•
Thermal generation accounted for most of the region’s total electricity supply in
2005 and is expected to be in the same position through to 2015.
•
Coal-fired power plants, which were the region’s largest source of electricity in
2005, accounting for 44% of total generation, are projected to provide a 41%
1
International Energy Outlook 2007 (IEO2007), by the Energy Information Administration (EIA) of the outlook
for international energy markets through 2030
- 27 -
Other Regions of Interest (continued)
share in 2015, as natural-gas-fired generation expands strongly from 27% of the
total in 2005 to 30% in 2015.
At present, South Africa’s two nuclear reactors are the only ones operating in the
region, accounting for less than 2% of Africa’s total electricity generation.
•
4 GW of new nuclear capacity is projected to become operational in Africa over
the next 10 years.
•
Hydroelectricity and other marketed renewable energy sources are expected to
grow slowly in Africa.
•
As they have in the past, non-marketed renewables can be expected to continue
providing energy to Africa’s rural areas; however, it is often difficult for African
nations to find funding or international support for larger commercial projects.
Coal
Electricity Generation ( TWh)
•
Net Electricity Generation in Latin America
Oil
750
500
250
0
2015
Renewables
14 GW
In 2015, the share of hydropower and other renewable energy sources in their
combined fuel use for electricity generation is projected to be over 60%.
•
Robust growth in the use of natural gas and nuclear power is projected to lessen
the region’s overall reliance on hydropower in the mid-term.
Oil 2 GW
•
Until recently, Argentina was a major regional supplier of natural gas. In 2007,
Argentina reduced natural gas exports to Chile in the face of rising domestic
demand and stagnant production. Chile, in turn, has begun construction on an
LNG regasification facility, which is scheduled for completion in 2010.
•
In addition to coping with reduced gas supplies, Chile has had very low water
levels at its hydroelectric facilities as a result of drought conditions. The Chilean
government is pressing consumers to reduce power use by 5 percent but has
electricity rationing may be necessary in the short run.
•
Several countries in the region are looking at near-term solutions to meeting
electricity demand. Both Argentina and Brazil, for instance, are turning to coal,
fuel oil, and diesel generation as emergency alternative sources of power.
Latin America
•
Electricity generation in Central and South America is projected to increase
steadily in from 959 TWh in 2006 to 1,259 TWh in 2015.
•
Brazil, the region’s largest economy, is expected to remain its largest electricity
producer as well, accounting for 54% of total projected electricity generation in
the Central and South America region.
•
Throughout Central and South America, a significant proportion of electricity is
derived from renewable energy sources, primarily hydropower.
•
Hydroelectric generation accounted for over 80% of Brazil’s total electricity
supply in 2006, and despite ongoing efforts to diversify the fuel mix for the
country’s electricity generation, hydropower is projected to remain Brazil’s
predominant source of electricity through 2015.
Forecast Capacity Increase in the Central and South America 2007 - 2015
Latin America, 2007 2015
Nuclear 2 GW
Gas 36 GW
Renewables
31 GW
In combination, the other nations of Central and South America rely on
hydropower for a smaller percentage of their electricity supply, just over 50% in
2006.
Renewables
•
Coal 12 GW
•
Nuclear
2006
Forecast Capacity Increase in Africa, 2007 - 2015
Gas 29 GW
Gas
1000
Coal 14 GW
Oil 27 GW
- 28 -
IV
POWER PROJECTS DELIVERY
these variables led to protracted and costly disputes resulting in major financial
problems for the owner, contractor and engineer. A number of contractors suffered
heavy losses and, as a result, a number of contractors now refuse to enter into EPC
contracts in certain jurisdictions.
Building power plants
There are a number of contractual approaches used construct a power station.
Engineering, Procurement and Construction ("EPC") contracts have historically been
the most common form of contract used in the private sector for large scale projects.
The other common approach is to have a separate supply contract, design
agreement and construction contract with or without a project management
agreement. The choice of contracting approach depends on a number of factors
including the time available, the lenders requirements and the identity of the
contractor(s). Appendix 7 contains a brief summary of the various contract strategies
used to building power plants.
Current trends
In the last couple of years, the power generation market has become very buoyant
and is predicted to continue this way for at least the next 20 years. There is currently
a huge amount of work for contractors on projects around the world as countries
become more concerned about energy supply, and demand continues to increase for
more new-build combined-cycle and other power plants. As a result, there is great
demand for plant, materials, equipment and expertise, costs are also rising and
contractors and manufacturers have near full order books. Contractors are
considered to be in a prime position as they shop around for projects that carry the
least risk and the most profit.
The following section discusses the current trends and provides commentary relating
to the changing face of power station supply and construction. This information is
considered relevant to equipment and service suppliers with a view to addressing
current supply strategies and consulting with the relevant parties.
In the last few years, contractors and manufacturers have become more risk averse,
and when negotiating contracts are seeking exclusions from and significant caps on
liability. More recently, contractors are simply declining to bid for turnkey/EPC
contracts. It is clear that the market has changed and with it the bargaining dynamics
of the parties involved. Some traditional EPC contractors have been reluctant to take
on EPC roles and have preferred to partner with other organisations providing
balance of plant equipment or just provide the installation of main equipment. In
response to these escalating cost concerns and contractor resistance, owners have
recently shown a willingness to modify EPC terms by spreading some of the
contractor risks between power island equipment suppliers and the engineercontractor team.
Historic trends
Prior to privatisation, most power stations were built on a Design, Bid, Build basis.
Large public engineering bodies carried out the design phase and put the
construction out of the plant to tender. Between 1980 and 2000 when the power
generation market was tight, large equipment manufacturers such as Siemens took
on EPC roles, as that was the only way they could ensure their equipment was
utilised.
The movement away from the typical "design and build" method to EPC altered the
traditional relationships among the owner, the owner's representative, the
architect/engineer, the construction manager, and the contractor. These altered
relationships shifted the risks assumed by each party, specifically the project
completion cost and performance onto the contractor's shoulders. The traditional
EPC contract adds as much as 8-15% to the actual cost of the work because of
assumption of all project risk by the contractor,
Alternative procurement approaches such as alliance and framework arrangements
and multi-contracting are being considered. In the UK on a current coal fired projects,
there are a dozen contracts each worth a 100 million for the project, rather than a
single EPC contract.
However the EPC was viewed as offering a power plant owner a number of distinct
advantages, including certainty of price, single-point responsibility, a greater transfer
of risk to the contractor and a fast track to completion of a project. Early EPC deals
did not provide any relief for project variables such as tight labour availability,
equipment under-performance, errors and discrepancies in the basic design. Often
Chapter IV: Power Projects Delivery
Owners are issuing direct contracts for specialised equipment. The gap for EPC roles
has opened and where EPC contractors cannot be found, developers are resorting to
separate contracts for contractors and design engineers.
- 29 -
Trends in Building Power Plants (continued)
under the background of recent rapidly growing demands for power in China and
India.
Impact on equipment suppliers and services
The shift from the EPC approach to EPCM has opened up the contracting market for
Tier 2 and Tier 3 equipment suppliers. Whereas previously equipment suppliers had
to rely on relationships with EPC contractors, equipment suppliers should currently
consider developing direct relationships with owners and developers.
Major EPC contractors include the following companies listed in the following table.
In addition, the lack of EPC contractor roles has led to openings for architectengineer and design roles. Scottish companies, with their established skill and
expertise should consider such avenues into power projects.
It is worth noting that the approach to building power stations is subject to change as
a result of supply and demand. The lack of the traditional EPC contractors in recent
years has opened up a significant market for companies new to EPC contracting.
Therefore companies are advised to be diligent in assessing and researching the
market for new entrants such as BHEL in India.
However regardless of trends in contracting approach, it is essential that equipment
suppliers are on the preferred suppliers list of major contractors. Some major
contractors such as GE and Siemens do not put their contracts out to tender
Approaches should be made to traditional EPC contractors and developers to ensure
equipment is on the ‘preferred suppliers list’. However, track records suggest that
some EPC contractors have a regional bias towards their selection of Tier 2 and Tier
3 suppliers. Therefore efforts in approaching some of the emerging major
contractors from China and India, South East Asia and Eastern Europe may prove
more beneficial, as traditional relationships between secondary and tertiary suppliers
have not yet developed between these companies.
Website address
Siemens Power Generation
http://www.powergeneration.siemens.com
GE Energy
http://www.gepower.com
Aker Kvaerner
http://www.akersolutions.com
Toshiba Power Systems
http://www.toshiba.co.jp
Alstom Ltd
http://www.alstom.com
Ansaldo
http://www.ansaldoenergia.com
ABB Power Systems
http://www.abb.com
Doosan Babcock
http://www.doosanbabcock.com
Daewoo Engineering and Construction
http://www.daewooenc.com
Hyundai Engineering Company
http://eng.hdec.co.kr
China National Machinery and Equipment
Import and Export Corporation (CMEC)
http://www.cmec.com
Bharat Heavy Electricals Limited (BHEL) - India
http://www.bhel.com
Equipment shortages
Due to the high demand for power plants, there are long lead times for various
equipment and materials worldwide. Some of the known equipment and material
shortages include:
There is more discussion on contracting strategies in Appendix 7.
Major EPC contractors and equipment suppliers
Major players in equipment manufacturing, including European manufacturers such
as Alstom Power and Siemens and Japanese manufacturers such as Mitsubishi
Heavy Industries, Toshiba and Hitachi, have global businesses in steam turbines and
boilers. Emerging companies include 3 major Chinese companies, Shanghai, Harbin
and Dongfang, and Indian national power company BHEL. These companies are
beginning to take a large share of the global market through technical cooperation
with major Japanese, European and American manufacturers. This is happening
Chapter IV: Power Projects Delivery
Company
•
Electrical equipment such as transformers and HV switchgear
•
Generators have an estimated lead time of 22-32 weeks
•
Large castings, such as turbine forging, with lead times of up to 2 years
•
Exotic steels and expensive alloys for supercritical boilers
The long lead time for major equipment items is delaying the building of new plant. .
In addition early payment is required for any equipment purchasing. Some of these
lead times are decreasing due to current global financial crisis; however this is not
expected to affect demand in the long term. Currently Scotland is not known to
manufacture any of the above equipment; however opportunities exist for knowledge
sharing and diversifying for companies.
- 30 -
Sustainability
The key issues
There is increasing recognition of the need for sustainable power generation and this
is being reflected in government legislation, community expectations and corporate
behaviour. These large changes are expected to continue in a reasonably
predictable fashion, requiring the thermal power generation industry to have a futureproofing strategy that addresses the following issues throughout the supply chain:
•
Preparing for climate change mitigation policy measures
•
Equipment specification recognising the need for climate change adaption
•
Minimised energy and water use in manufacturing, installation and operation
•
Attention to waste disposal methods, including end of life disposal
Reducing the carbon footprint of the supply chain, particularly those elements
that will require replacement during the life of the power station
Trends in supply chain carbon footprinting
In recent years, a variety of greenhouse gas (GHG) accounting standards have been
developed, which are increasingly being used by national and regional/local
governments and large corporations, as well as on specific projects and products. It
is likely that within the next 5-10 years suppliers will be increasingly asked to quantify
their direct and indirect emissions in accordance with the relevant standards.
A new international agreement to take over from the 1997 Kyoto Protocol is expected
to be decided upon by the end of 2009 and this is likely to lead to a raft of new
legislative and financial instruments to reduce CO2 emissions.
Current measures in these countries and increasingly in China, India and other nonOECD nations are in the form of incentives and directives to reduce the CO2
emissions and energy usage in every part of the economy. The direction of future
climate change mitigation measures can represent considerable business risk, and it
cannot simply be assumed that existing plants will be exempt from such measures,
as demonstrated by the European LCPD.
The GHG Protocol 1 Initiative
In 2001, the GHG Protocol published The Greenhouse Gas Protocol: A Corporate
Accounting and Reporting Standard, which is being used by large corporations and
for national GHG accounting programmes. It provides a methodology for measuring
direct GHG emissions. Guidelines are now being developed for product lifecycle
emissions based on complete worldwide supply chain analysis. The GHG Protocol
notes that “supply chain sustainability has become a high priority in the corporate
community”. Within the power sector, Siemens is a participant in this programme.
For the plant developer and owner, future-proofing should be a key risk management
technique aimed at evaluating possible future regulation scenarios and undertaking
actions that will be of significantly lower cost now than if they need to be applied
retrospectively later. Examples include:
International Standards Organisation (ISO)
Siting and laying out a power station to accommodate future CCS and/or to
waste heat capture technologies
In 2006, ISO 14064-I: Specification with Guidance at the Organization Level for
Quantification and Reporting of Greenhouse Gas Emissions and Removals was
Considering the integration of renewables (typically biomass co-firing, where
biomass is burnt with the fossil fuels, and integrated solar combined cycle, where
solar thermal energy is added to gas turbine waste heat to heat steam)
Chapter IV: Power Projects Delivery - Sustainability
•
As discussed earlier, emissions controls will also have to address NOx emissions –
see earlier discussion on the EU Industrial Emissions Directive at the end of the CCS
section – thus future-proofing strategies should allow for changes in this area as well.
The OECD countries have announced targets of reducing greenhouse gas emissions
ranging from 60% (e.g. EU, Australia) to 80% (e.g. UK, US) by 2050, a period that
will span the lifetime of most of the new generation being considered in this report.
•
Use of very high efficiency plant, including high efficiency components to reduce
plant auxiliary load
For the component supplier, a future-proofing strategy will be just as important. As
well as addressing the last point regarding carbon footprint, evidence of business
strategies to mitigate the risks posed by likely future climate change mitigation
measures would provide comfort to the developer. Typical considerations might be
the scope to retro-fit sub-components, system (software) reconfiguration to meet
changing legislation, or the retrofit of a whole module of equipment on a direct
replacement basis.
Future-proofing against climate change measures
•
•
1
The GHG Protocol is a joint initiative of the World Resources Institute and the World Business Council for
Sustainable Development. http://www.ghgprotocol.org
- 31 -
Sustainability (continued)
published based on the work of the GHG Protocol Initiative to measure direct
emissions. Part II of this standard relates to project level GHG accounting. The ISO
14040 series provides a high level framework for a life cycle assessment of the
impact of a product and is the basis of subsequent supply chain GHG analysis
assessment tools, i.e., those that consider indirect emissions as well as direct.
cooled condensers are thus becoming increasingly common. The collection and
reuse of waste water streams is likely to become a standard requirement, and water
efficiency will be as important as energy efficiency for thermal power stations in
some locations. Increasingly, power stations projects are being associated with
desalination plants, either as a use of waste heat to maximise efficiency or as a basic
need for the power station steam cycle.
British Standards Institute (BSi)
The BSi has recently developed PAS2050 – Specification for the assessment of the
life cycle greenhouse gas emissions of goods and services. It builds upon the ISO
14044 life cycle assessment methodology to create a specific methodology for
accounting for GHG emissions across the supply chain.
Water is treated before entering the boiler cycle to remove corrosive elements:
various treatment options are available to achieve this, some of which will use fewer
chemicals, materials and less energy, as well as less water overall. A choice made
after careful consideration of the key local constraints will offer better future-proofing.
Carbon Trust
Waste disposal
In the UK, the Carbon Trust has developed guidelines for calculating the carbon
footprint of products, i.e., supply chain carbon accounting, and has recently released
a label standard, with a methodology based on PAS2050. A growing number of
companies have committed to measure and display the carbon footprint of their
products 1 .
Waste products from thermal power stations can include:
Climate change adaptation and equipment specifications
It is widely accepted that some global warming will be inevitable in this century with
different parts of the world experiencing varying effects, but with a likely minimum
average global temperature increase of about 3 °C2. Therefore, whilst it is normal
practice to consider existing local climatic conditions when specifying equipment,
increasingly, specifications will need to consider changing local conditions. This is
likely to include 3 :
•
•
•
•
•
Coal ash from coal fired power stations, usually containing several trace minerals
•
Cooling water at elevated temperature
•
Other waste water streams, including human waste
•
Chemicals from water treatment and elsewhere
•
Oils and lubricants
•
Parts being replaced or upgraded, including at the end of the power station life
Ash disposal in landfill increases the physical footprint of a coal fired power station,
often on arable land. Trace chemicals are of concern to local water sources and
soils, as is the use of water and energy to transport ash via a slurry, trucking or
conveying. Ash can be recycled in concrete, ceramics and other products, currently
accounting for a small proportion of the total ash produced globally 5 . However, the
availability of recycling options is likely to decrease tolerance of landfill solutions.
Increased temperature and annual temperature fluctuations
Changing rainfall patterns
Increased sea levels
Increased storm and storm surge activity
Increased wind speeds
The cost of disposal of components likely to be replaced during the lifetime of the
power station, such as control equipment, is likely to increase as availability of landfill
decreases. Readily recyclable components may become more sought after as
companies adjust to performing a more thorough life-cycle analysis of their
investments.
Water usage
With water becoming significantly scarcer in many places, fresh water use in power
stations will become more expensive and less acceptable to local communities4. Air
diversion to the power station from municipal water supplies during times of urban water restrictions.
5
In the US, 62% of ash is sent to landfill; 36% in Europe,
http://www.caer.uky.edu/kyasheducation/whathappens.shtml. There is considerable interest in India and
China in alternative uses of ash, http://saferenvironment.wordpress.com/2008/09/05/coal-fired-power-plantsand-pollution
1
http://www.carbon-label.com/business
Based on IPCC predictions using the scenario of a stabilisation of CO2 in the atmosphere of 550 ppm
3
Further information available from the IPCC
4
Eg, this was seen in 2008 at the Loy Yang coal-fired power station in Australia with public outcry over
2
Chapter IV: Power Projects Delivery - Sustainability
•
- 32 -
V
CAPITAL COSTS
of materials, high energy prices, rising labour costs and supply chain constraints.
Coal and gas prices are assumed to remain high, resulting in increasing cost of new
plants and thus pushing up end user prices.
EPC capital costs
The capital cost of building a typical plant is usually considered to be the EPC
contract costs. The capital costs are sensitive to the following factors:
•
Site-specific requirements relating to supporting infrastructure
•
The duration of construction of the project
•
Market influence of major equipment manufacturers
•
Price variations due to equipment supply and demand in the market
•
“Soft costs” such as development, financing and legal fees
The table on following page compares data collated from various sources on capital
costs. Some of the data includes forecasts or data particular to countries,
specifically China and Russia.
Recently there have been sharp increases in construction costs of new power plants,
particularly in OECD countries. For non-OECD countries, less cost data are
available; therefore it is difficult to draw conclusions on the extent of the increases
experienced there. According to the IEA, the sharpest increases have been in the
United States, where the construction cost of a new supercritical coal plant has
doubled over a few years. In addition, nuclear power construction companies there
have announced construction costs at least 50% higher than previously expected.
Costs have been evaluated by a number of studies 1 .
•
In 2005, a joint IEA/NEA study, Projected Costs of Generating Electricity:
•
•
•
•
Estimated that capital cost2 of nuclear ranged from $1000 to $2000/kW and
construction time from 5 to 7 years. The cost of nuclear electricity in the
ranged between $30 and $50/MWh.
Similar trends are evident in other OECD countries; the main causes of higher costs
are as follows:
The study estimated that for coal-based electricity, the construction costs
were $1000-$1500/kW, 4-years construction with investment costs of $35$60/MWh.
The construction costs of gas-based electricity were estimated to be $400$800/kW, 2-3 years construction and investments costs of $40- $63/MWh
The IEA World Energy Outlook 2006 compares projected (2015) nuclear, coal,
gas, see Appendix 6. The projected capital costs for each technology are as
follows:
•
Coal: 1400$/kW
•
Nuclear: 2000-2500$/kW
•
Gas: 650$/kW
There is significant variance in the capital costs of plants built in developed nations
and transition nations. For example the capital cost building a subcritical coal fired
plant in China can be up to half the cost of building a similar plant in Europe or
Japan. The cost of building power stations has increased significantly over the past
few years, particularly in OECD countries. This is largely due to increase in the cost
1
IEA Energy Technology Essentials, Nuclear Power, March 2007
Sometimes referred to as the overnight construction cost, which is defined as the total of all costs incurred
for building the plant accounted for as if they were spent instantaneously.
2
Chapter V: Capital Costs
- 33 -
•
Increase in demand: Outside the OECD, strong growth in electricity demand is
pushing up orders for new plant in addition to the need for new plant in OECD
countries due to shrinking reserve margins.
•
Increases in the cost of materials: metal prices such as steel, Al, and Cu have
substantially increased since 2003/2004 and the prices of some special steels
used in power plant manufacturing have increased even faster. Cement prices
are also reported to have gone up.
•
Increase in energy costs: High energy prices affect the manufacturing and
transportation cost of power plant equipment and components.
•
Tight manufacturing capacity: power plant manufacturer are not able to fulfil
orders quickly due to lack of capacity and a shortage of skilled engineers. Many
manufacturers claim that their order books are full for the next three to five years.
•
Increases in labour costs: Rising labour costs, particularly in non-OECD countries
and a shortage of EPC contractors in some regions is pushing up total project
costs.
Capital Cost Analysis
Capital cost per kW
Source
IEA, NEA
& OECD1
OECD2
PB Power3
IEA4
IEA
(China)6
ERIRAS
(Russia)7
WEC5
IEA, NEA
&OECD1
IEA,
DGEMP8
Year
2005
2005
2006
2006
2007
2007
2007
2015
forecast
2015
forecast
USD
USD
USD
USD
USD
USD
USD
USD
500-600
1050-1200
750
1,350
1,276
600-900
960-1130
1,000
627
569
2,718
1,633
Technology type
Unit size
(MW)
Efficiency
(%)
USD
Coal Subcritical
200-400
30-36
1,350
1,067
1,000-1,500
Coal Supercritical
330-800
41-45
Gas CCGT
400-800
49-55
Nuclear
1150
IGCC
1,200
570
500-1,000
2,250
45-55
1,200-1,400
594
450-800
b
2000-2,500
1,500-1,800
1,747
1,400-1,600
1,100 -1,400
1,834
1,000-2,500
550-650
1400 -1800
1,500
INFORMATION SOURCES:
1
IEA, p33, http://www.iea.org/Textbase/Papers/2008/CHP_Report.pdf
IEA sources , including IEA ,NEA (Nuclear Energy Agency) and OECD report, Projected Costs of Generating Electricity (IEA 2005 Update)
2
2005 OECD comparative study, http://www.world-nuclear.org/info/inf02.html
[a] Nuclear overnight construction costs ranged from US$ 1000/kW in Czech Republic to $2500/kW in Japan, and averaged $1500/kW.
3
PB Power report "Powering the Nation", published in March 2006. A summary document is available as a free download in pdf format. http://www.pbworld.co.uk/index.php?doc=528. All
prices in Pounds sterling converted to USD, using exchange rate of 1.74
4
IEA, World Energy Outlook 2006, International Energy Agency (IEA), p145 The Economics of New Power Plants
5
World Energy Council, Survey of Energy Resources 2007, http://www.worldenergy.org/publications/survey_of_energy_resources_2007/coal/631.asp
6
IEA, World Energy Outlook 2007, International Energy Agency (IEA), China and India Insights, p345 Coal-Based Power Generation Technology in China and p352-3 Power Generation
Economics
7
Energy Research Institute Russian Academy of Sciences, 3rd international forum, RUSSIAN POWER, Investing into the Russian power generation companies. Alexei Makarov, Fedor
Veselov, http://www.eriras.ru/papers/2007/makarovveseloveng.pdf
8
Energy Policies of IEA Countries, France 2004 review, http://www.iea.org/textbase/nppdf/free/2004/france.pdf, p129
In December 2003, DGEMP – DIDEME within the Ministry of Economy, Finance and Industry released a study on the costs of the generation of electricity from different generating
technologies, “Coûts de référence de la production électrique”.
All capital cost assumptions include equipment, construction, design, development and interest during construction.
- 34 -
Power Plant Cost Breakdown
•
Control and Monitoring
Calculating power plant cost breakdowns
•
Chemical
The EPC cost of building a power plant is now broken down into specific cost areas.
The breakdowns charted below are for:
The following table lists some of the items in each of those disciplines:
•
400 MW sub-critical coal-fired plant
•
600 MW super-critical coal-fired plant
•
400 MW combined cycle (CCGT) plant
Discipline
Includes the following items
Civil and Structural
Structural Steel, Ladders, Walkways, Stack, Tanks, Bridge
Cranes, Coal Handling Equipment
Mechanical
Boilers, Steam Turbine Package, Soot Blowers, Coal
Pulverisers, Fans, Feedwater Heaters, Water-cooled
Condensers, Air-cooled Condensers, Flue Gas Desulfurization,
Stack, Pumps, Cooling Tower, Heat Exchangers, District
Heaters, Air Compressors
Electrical
Transmission and Generation Equipment.
Total cost of a power plant
Particulate Control, Nitrogen Oxide Control, Continuous
Emissions Monitoring System, Distributed Control System,
General Plant Instrumentation.
For the total EPC cost of a plant, the data produced a high level price breakdown has
produced the following percentage-value splits between the following areas:
Chemical
Makeup and Waste Water Treatment System
•
1,000 MW nuclear plant
In order to breakdown the value of work for specific plant areas, Thermoflow’s Plant
Engineering and Cost Estimator (PEACE) package has been used. Analysis has
been done in two stages:
•
Engineering costs, usually within the EPC’s remit
•
Owner’s costs which will include owner’s engineer and legal costs
•
Equipment procurement costs
•
The build cost of construction
•
The management cost of construction
As this study concerns what equipment Scottish companies might supply to these
projects, the main area of interest here is the value of the equipment to be procured.
To assess an approximate value of the opportunity for a particular discipline supply
within a specific type of plant, the following example is provided for electrical
equipment in a CCGT plant. The user would calculate:
Value of the procured equipment within a power plant project
Value = equipment procurement % X electrical content % = 0.58 X 0.10 = 0.058
(5.8% of the value for the whole plant)
The capital cost for equipment for each of these plant types was then broken down
into the values for each engineering discipline.
•
Civil and structural
•
Mechanical
•
Electrical
Later in the report these percentage splits are applied to the declared new-build
projects for various areas of the world to estimate the value of opportunities in those
areas.
- 35 -
Power Plant Cost Breakdown (continued)
Breakdown of the total cost of a power plant
600MW Supercitical
Coal-fired plant
400MW Subcritical
Coal-fired plant
3%
13%
Gas-fired plant, CCGT
3%
13%
11%
Nuclear plant
5%
8%
14%
38%
17%
3%
13%
39%
17%
18%
58%
10%
60%
28%
29%
Engineering
Equipment Procurement
Const ruction
Owner's costs
Construction Management
Breakdown of the value of the procured equipment within a power plant project
600MW Supercitical
Coal-fired plant
0.2%
7%
6%
Gas-fired plant, CCGT
400MW Subcritical
Coal-fired plant
0.3%
22%
6%
2%
6%
1%
4%
3%
8%
10%
22%
Nuclear plant
65%
6%
53%
83%
66%
Civil/structural
Mechanical
Electrical
- 36 -
Chemical
30%
VI
SCOTTISH SUPPLY CHAIN
Introduction
Worldwide forecast additional capacity and market value
This section drills down into the major projects to analyse the opportunities available
for Scottish equipment and service providers to the power industry worldwide, using:
The table on page 39 estimates the total worldwide market EPC value from 2006 to
2015 based on the forecasted projections of coal gas and nuclear new build and the
capital costs of new build plants. The table below is what SKM considers to be
appropriate costs based on the information available to through its involvement in
power generation projects globally. The valuations are intentionally conservative in
order not over-estimate the market value.
•
Current capability of the Scottish supply chain, page 38
•
Worldwide forecast additional capacity and market value, page 39
•
Market value of equipment supply, page 40
Current capability of the Scottish supply chain
A matrix is on page 38 identifies the companies based in Scotland that supply
equipment and services to the power industry. The list of companies and areas of
equipment and services supply areas for each company was extracted from the IPA
1
database and company websites. The Industrial and Power Association (IPA)
represents a group of companies that operate in all areas of the power and energy
related industries. There are 39 members listed in the IPA database. The following
chart shows the declared interests of the members of IPA companies with interests in
the power generation sector.
Plant type
$ / kW
Coal
1,200
CCGT
1,000
Nuclear
2,000
Market value of equipment supply
The total market value of particular items of equipment supply relevant to Scottish
industry is estimated for coal fired plants, over the period 2007 to 2015. The table in
this section:
IPA Member Interests
No. of members
30
20
15
Extracts the some relevant items of equipment that Scottish industry manufacture
using the ‘Current capability of the Scottish supply chain’ table on page 38.
•
Uses the new-build projections and market value for each sector detailed within
the ‘Worldwide forecast additional capacity and market value’ table on page 39.
•
Uses the percentage split for individual items of relevant equipment obtained from
the modelling as detailed in cost breakdowns section (Chapter IV) and applies
those percentages to the total market value
10
5
0
Thermal
Cogen
Nuclear
Industrial
Environmental Renewables
In addition to the relevant IPA members included in the matrix, further companies
which supply equipment or provide services considered suitable for medium to large
power plant are included.
Therefore the market value of those key components of coal-fired power generating
plant relevant to Scottish industry is estimated for the period 2007-2015 on page 40.
The matrix demonstrates that Scottish companies are primarily Tier 3 and Tier 4
equipment suppliers. However a number of Scottish companies provide a variety of
services.
1
•
25
A diagram illustrating the flow of data between the following tables can be found in
Appendix 3.
http://www.ipa-scotland.org.uk/members/default.asp
Chapter VI: Scottish Supply Chain
- 37 -
Company
Equipment or service
supply
Doosan Babcock Energy Ltd
ScottishPower Generation Ltd
BIB Cochran Ltd
Clyde Group
Diamond Power Speciality Ltd.
x
Howden Power
Wood Group
x
x
x
x
x
x
x
TUV NEL
x
x
x
x
- 38 -
Aggreko PLC
x
x
x
x
Enotec UK Ltd
x
x
x
x
x
Foster Wheeler
Halcrow
Jacobs
Mott MacDonald
PCS Ltd
Sinclair Knight Merz (SKM)
x
x
Currie and Brown
x
x
x
AEA Technology
x
CESS Ltd
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
RWE npower
Scottish and Southern Energy (SSE)
x
Siemens Power Generation Ltd
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
METTEK Limited
x
x
x
x
x
Failure investigation
Testing and
commissioning
Sourcing and marketing
Energy & environmental
consultancy
Equipment
Project management
Process design and
engineering
Plant construction and
installation
Plant and equipment
maintenance
Cost engineering
Design and planning
Gaseous emissions
monitoring
Particulate emissions
monitoring
Diagnostics systems
Air pollution control
Air combustion control
Control and
instrumentation systems
Main steam pipework
Back up diesel
generators
Milling equipment
Blowdown systems
Economisers
Heat exchangers
Compressors
Large pumps
Large fans (FD, PA, ID)
Ash handling
Flue gas
desulphurisation (FGD)
Burners
NOx reduction
Soot blowers
Auxiliary boilers
Boilers
Current Capability of the Scottish Supply Chain
Services
x
x
x
x
x
x
x
x
x
x
REGION
Forecast
increase in
installed
capacity (GW)
OECD
AsiaPacific
World
Coal
613 GW
17 GW
15 GW
12 GW
8 GW
14 GW
417 GW
63 GW
37 GW
14 GW
4 GW
12 GW
Gas
249 GW
16 GW
15 GW
23 GW
22 GW
8 GW
19 GW
5 GW
19 GW
36 GW
56 GW
29 GW
28 GW
2 GW
11 GW
0 GW
1 GW
4 GW
14 GW
4 GW
3 GW
2 GW
0 GW
0 GW
890 GW
62 GW
53 GW
158 GW
39 GW
34 GW
567 GW
103 GW
96 GW
111 GW
77 GW
56 GW
Coal
$736
$20
$18
$14
$10
$17
$500
$76
$44
$17
$5
$14
Gas
$249
$16
$15
$23
$22
$8
$19
$5
$19
$36
$56
$29
$56
$4
$22
$0
$2
$8
$28
$8
$6
$4
$0
$0
$1,041
$40
$55
$37
$34
$33
$547
$89
$69
$57
$61
$43
Nuclear
Total thermal
Total cost of
new build
(Billion USD)
OECD
North
America
GENERATION
TYPE
Nuclear
Total thermal
OECD
Europe
Eastern
Europe
Russia
China
Other
Asia
India
Latin
America
Market value of forecast increase in installed capacity 2007 - 2015
Billion USD
$100
$90
Coal
$80
Gas
$70
Nuclear
$ 500 billion
$60
$50
$40
$30
$20
$10
$0
OECD North OECD AsiaAmerica
Pacific
OECD
Europe
Eastern
Europe
Russia
China
Regions
- 39 -
India
Other Asia
Latin America Middle East
Africa
Middle
East
Africa
Market Value of Equipment Supply for Coal-fired New Build, 2007 - 2015
World
Coal
Forecast increase installed
capacity 2007- 2015
OECD
North
America
OECD
Asia Pacific
OECD
Europe
Eastern
Europe
Russia
China
Latin
America
India
Other
Asia
Middle
East
Africa
613 GW
17 GW
15 GW
12 GW
8 GW
14 GW
417 GW
63 GW
37 GW
14 GW
4 GW
12 GW
$735,600
$20,400
$18,000
$14,400
$9,600
$16,800
$500,400
$75,600
$44,400
$16,800
$4,800
$14,400
Boilers
$87,000
$2,417
$2,132
$1,706
$1,137
$1,990
$59,276
$8,955
$5,259
$1,990
$569
$1,706
Steam turbo-generator
$53,000
$1,475
$1,302
$1,041
$694
$1,215
$36,188
$5,467
$3,211
$1,215
$347
$1,041
Pumps
$6,700
$185
$163
$130
$87
$152
$4,533
$685
$402
$152
$43
$130
Soot blowers
$2,500
$69
$61
$49
$32
$57
$1,693
$256
$150
$57
$16
$49
Fans
$1,600
$45
$40
$32
$21
$37
$1,108
$167
$98
$37
$11
$32
Heat exchangers
$7,000
$194
$171
$137
$91
$160
$4,765
$720
$423
$160
$46
$137
Pulverised coal burners
$5,900
$163
$144
$115
$77
$134
$4,003
$605
$355
$134
$38
$115
Total cost of new build
(Million USD)
Market value of equipment supply (Million USD)
Equipment
NOx reduction
$370
$10
$9
$7
$5
$8
$250
$38
$22
$8
$2
$7
Flue gas desulphurisation
$36,000
$1,002
$884
$707
$471
$825
$24,570
$3,712
$2,180
$825
$236
$707
Ash handling
$17,000
$481
$424
$339
$226
$396
$11,791
$1,781
$1,046
$396
$113
$339
Large Fans (FD, PA, ID)
Mills
Stack
Control instrumentation
Large pumps
Compressors
Auxiliary boilers
Particulate monitoring
$1,600
$45
$40
$32
$21
$37
$1,108
$167
$98
$37
$11
$32
$17,000
$465
$410
$328
$219
$383
$11,412
$1,724
$1,013
$383
$109
$328
$5,700
$159
$141
$112
$75
$131
$3,906
$590
$347
$131
$37
$112
$22,000
$612
$540
$432
$288
$504
$15,012
$2,268
$1,332
$504
$144
$432
$6,700
$187
$165
$132
$88
$154
$4,589
$693
$407
$154
$44
$132
$380
$11
$9
$8
$5
$9
$261
$39
$23
$9
$3
$8
$3,700
$102
$90
$72
$48
$84
$2,502
$378
$222
$84
$24
$72
$16,000
$431
$381
$304
$203
$355
$10,581
$1,599
$939
$355
$101
$304
- 40 -
VII
OPPORTUNITIES FOR SCOTTISH COMPANIES
company boards are used to being presented with information concerning large
capital spends associated with the development of large generating plant plants.
The IEA’s $2,000+ billion spend projection
This report has used information from a number of reputable sources and modified
data to provide information which it is more pertinent to Scottish companies. This
section is intended to assist companies in carrying out strategic planning for their
business development in the power sector. The extract below from the table on page
39 outlines the global power sector investment opportunities in terms of the projected
increase in installed capacity.
Therefore it should be noted that the total worldwide investment in power generation
(up to 2015) has been identified as in excess of $2,000 billion. The ‘Projected
capacity additions and investment in power infrastructure’ table on page 19 (Chapter
III – Global Energy Trends) provides a regional breakdown of this figure. Note that
this figure also includes Renewables. The value of the thermal generation market is
estimated to be over $1,000 billion, however, this figure is still considered to be
conservative, as it does not take into account replacement capacity.
613
17
15
12
8
14
417
63
Gas
249
16
15
23
22
8
19
5
•
The on-going investment in flue gas desulphurisation plant
28
2
11
0
1
4
14
4
•
The likely fast-track investment in CCGT to meet the energy gap due to the
impact of the Large Combustion Plant Directive resulting in the closure of much
of the existing coal-fired plant
•
The installation of advanced super-critical steam plant or retrofitted selective
catalytic reduction (SCR)
•
New nuclear build
•
The impact of the outcome of the government-funded carbon capture and
storage demonstration projects.
Nuclear
Total thermal
890
62
53
158
39
34
567
103
Coal
736
20
18
14
10
17
500
76
Gas
249
16
15
23
22
8
19
5
Nuclear
Total thermal
Waves of investment
India
China
Coal
Russia
OECD AsiaPacific
Eastern Europe
OECD North
America
Total cost of
new build
(Billion USD)
GENERATION
TYPE
World
Forecast
increase in
installed
capacity (GW)
OECD Europe
56
4
22
0
2
8
28
8
1,041
40
55
37
34
33
547
89
The information on projected levels of investment has been presented so far in terms
1
of total investment in specific technologies. However, it has been suggested that the
future build programme for the UK will be in waves of investment, with the installation
of new higher efficiency and lower emissions plant. The figure below illustrates:
Note that this data relates the investment / opportunities to the projected increase in
capacity, and not to the actual value of the new plant which will be required to
achieve this total capacity once the existing plant has been retired. The study has
taken this approach as the data presented in the IEA report relates to projected
increases.
The following graph relates to investment through to 2025, whereas this report has
taken 2015 as its horizon. Although these projections are for the UK, the pattern
shown is representative of most of the regions considered here, apart from China
and India where fewer emissions controls are currently in place, and coal-fired plant
and nuclear plant developments are already progressing.
A feature of this study is that the analysis has drilled-down to estimate the
opportunities for specialist (Tier 3 and Tier 4) suppliers, for example on page 40.,
However, these smaller numbers for the market spend on equipment should not be
allowed to mask the very large worldwide power sector market spend. The
information presented in this report has tended to focus on the value of sub-systems
and components which might be delivered to EPCs. Managing Directors and
Chapter VII: Opportunities for Scottish Companies
1
Martin Sedgwick, Head of Asset management, Scottish Power, IET Power Generation Control seminar,
Birmingham, 1.12.08
- 41 -
Opportunities for Scottish Companies (continued)
future-proof their offerings to be ready for the likely CCS and SCR retrofitting and
new build opportunities.
The opportunities
As presented in the detail of the report, there is a significant market for supplying
equipment and services for the power industry forecast during the next 10 years.
Scottish companies have been manufacturing equipment for power plants for over
100 years and have a rich heritage in power generation engineering. The value of
this internationally accepted reputation should not be underestimated and should be
exploited when approaching international customers.
The report has highlighted the change in the ratio of ‘balance of plant’ to main
(traditional) generating plant equipment to address the more stringent emissions
demands. This means that more process engineering skills will be required to deliver
gas scrubbing and other process technologies. Scotland also has a rich heritage in
process engineering, and this should also be exploited.
The above graph is representative of the UK. Therefore, re-formulating this waves
graph for the global market produces the figure below. An additional dimension has
been introduced with the width of the bar representing the level of investment in a
particular technology.
“Waves” of investment worldwide
What Scottish companies need to do
New SC & USC coal
Joint ventures and licensing agreements
CCGT
Equipment suppliers in Scotland face significant competition from manufacturers in
China and India, South East Asia and Eastern Europe. Conventional manufacturing
has trended towards moving to these regions due to plentiful cheap labour and other
low cost inputs. However, Scottish companies do have the opportunity to partner
with companies with manufacturing facilities elsewhere, and particularly in the
countries where the generating plant will be installed. Localisation, the approach
being taken by the large nuclear vendors, mainly due to the need to re-develop the
supply chain, but also to satisfy local political pressure in many countries to minimise
the balance of payments, may become a factor in all large capital spend projects.
New nuclear
CCS deployment
2005
2010
2015
2020
2025
The data is now dominated by the opportunities / build programme in China and
India, where coal-fired plant building is proceeding rapidly. Nuclear build is
progressing quickly in China and a number of orders have placed from various
countries around the world.
For the emissions equipment supply, companies with a power sector track record
need to take the initiative with regard to forming joint ventures with process industries
partners, particularly when the process industry order book is already buoyant.
CCGT plant is still likely to be developed, particularly when gas becomes available in
areas requiring fast-tracking of increased generation capacity, and where CCS
schemes are not viable.
Equipment manufacturers in Scotland are also advised to consider licensing
agreements with companies in China, India, South East Asia and Eastern Europe for
the manufacture of equipment, which would be delivered by a Scottish lead contract.
This should also provide opportunities to the Scottish party for the provision of design
services to those organisations if they were leading supply contracts, either if the
CCS investment is only likely to start in earnest at the end of the timeframe of this
study, However, Scottish companies are recommended to consider how best to
- 42 -
Opportunities for Scottish Companies (continued)
other party is over-stretched, or the customer requires contracts delivered with
English-language design documentation, or to a more rigorous quality assurance
regime.
If and when the power and oil and gas sectors come together, there is a need to
provide joined-up thinking between the two sectors, particularly with regard to
providing consistent design documentation particularly with regard to plant safety
systems.
Skills transfer
Staffing and training
Scotland is well placed to offer skills in design, strategy, management, operation and
maintenance. There is a shortage in engineering expertise and personnel around
the world and a need for experienced design engineering skills. Therefore
opportunities might exist to subcontract in-house engineering staff to larger
international power generation contractors and developers. In addition, staff
secondments to larger firms would provide relationships and links to key clients, and
aid promotion of existing specialised designs or design services.
The hiatus over the last 20 years in new build within the UK has reduced the
available skilled work force. This has been recognised by others and increasingly we
are seeing initiatives such as formation of the Sector Skills Councils programme
Cogent1, which has been addressing skill gaps in sectors such as nuclear and
process engineering via the establishment of skills academies. If the power
manufacturing sector is to respond to the opportunity, then similar initiatives may be
required.
Services
Scottish companies are advised to consider the promotion of specialised services
such as emissions monitoring, quality assurance (QA), control and instrumentation
design and advice. General plant condition monitoring is also considered to be a
major area which Scottish companies could exploit. Scottish companies have much
to offer in this area with a combination of plant operational experience and service
delivery.
The recent establishment (not associated with the SSCs) of the University of
Strathclyde’s Graduate School of Engineering2 with a new course on Power Plant
Engineering is a key facilitator for developing engineering staff for the power
generator sector.
World vs UK market
The report has identified sizeable opportunities in the world market but also in the UK
market. At the time of writing this report, the pound is weak against the euro and the
dollar, so both the home and export markets should be of great interest to the
Scottish supplier.
Services such as quality audits and design reviews are likely to become a growth
industry as equipment is supplied by emerging companies, where new equipment is
being delivered without long service histories, and where the project risk must be
minimised by increased diligence in the project management of the supply chain.
Scottish companies have the capability and capacity to position themselves as
experts the various fields of specialised services for power generation.
The UK market is likely to be large, due to the much heralded ‘energy
consumer demand and the post-LCPD (2015) generation capability.
perceived to be a leader in emissions control technology, due to its
initiatives, investment in deliverables developed for the UK market
Scottish companies well in the international market.
New technology
Understanding and investing in new technology developments is vital. This report
has highlighted the move to supercritical boiler and (steam) turbine technology, and
the variety of equipment required to abate emissions.
Coal-fired plant designs are likely to take on board the nuclear industry’s
modularisation approach, allowing more factory build of sub-systems (packaged
plant) to allow faster build at site and fewer skilled personnel during construction and
commissioning. The Scottish oil and gas sector has obviously long experience of this
approach and that experience should be exploited in the development of new
products.
1
2
- 43 -
http://www.cogent-ssc.com/
http://www.strath.ac.uk/gse/
gap’ between
As the UK is
clean energy
should stand
Scottish Enterprise Support to the Energy Industry
Scottish Enterprise
Scottish Enterprise Energy Team
Scottish Enterprise is Scotland’s main economic, enterprise and investment agency.
Our ultimate goal is to stimulate sustainable growth of Scotland’s economy.
The Scottish Enterprise Energy team is based in Aberdeen. The teams remit covers
support for the oil and gas, renewables and conventional power sectors.
The Scottish Government has set the following overriding strategic objectives:-
To achieve this we help ambitious and innovative businesses grow and become
more successful. We also work with public and private sector partners to develop the
business environment in Scotland. We deliver a range of dedicated support services
locally, nationally and internationally. Our activities help businesses with the appetite
and capacity to grow to:
•
•
•
•
•
Growth prospects for the power generation sector will largely be driven by legislative
requirements, particularly in the EU by the Large Combustion Plants Directive. This
requires thermal power stations to comply with targets, which become more stringent
from 2012, and contributes to reducing emissions and addressing climate change
issues. Combined with the need to replace the ageing fleet of fossil and nuclear
power stations, which currently provide 80% of electricity, the power generation
sector will require significant investment.
improve efficiencies;
access new sources of funding; and
conquer new markets.
To build a world-class economy, we’re interested in industries that have real
competitive advantage in Scotland, particularly:
•
•
•
•
•
•
The principal areas of opportunity for the power generation sector targeted include:
coal - supporting development and deployment of clean coal
technologies (S/C & oxyfuel firing, Underground Coal Gasification
(UCG) and Coal Bed Methane (CBM)
carbon capture and storage (CCS) - supporting development and
deployment of CCS technologies
power systems - supporting development and deployment of
advanced grid management systems
nuclear decommissioning - development of market opportunities
(supply chain and technical development)
energy,
life sciences,
tourism,
financial services,
food and drink, and
digital markets and enabling technologies.
We work in partnership with universities, colleges, local authorities and other public
sector bodies to achieve these goals and to maximise our contribution to the
Government’s Economic Strategy. We are mainly funded by the Scottish
Government, although we also raise part of our budget from other sources, such as
property rental and disposal of assets.
an 80% reduction in emissions by 2050
sustainable economic development
- 44 -
Scottish Enterprise Support to the Energy Industry (continued)
Scottish Development International
Scottish Enterprise Energy Team (continued)
SDI is a joint venture between Scottish Enterprise, Highlands and Islands Enterprise
and the Scottish Government. SDI helps businesses to think globally.
Scottish Enterprise will build on the technological and global market strengths of the
cluster of Scottish companies in the thermal generation industry through:
•
•
•
•
•
•
Its aim is to broaden Scotland’s international appeal as a first choice source of
knowledge and to assist the growth of the Scottish economy, by encouraging inward
investment and helping Scottish-based companies develop international trade.
support for effective industry associations
signposting opportunities for growth
providing access to funding for R&D and deployment of new technologies,
including working with partners such as ITI Energy, the Energy Technology
Institute and the Energy Research Partnership.
supply chain development
provision of market intelligence
account management of appropriate growth companies
To do this, SDI provides a full range of services for companies seeking to exploit
Scotland’s key strengths in:
•
•
•
•
Further information on the Energy Team’s activities can be found at:
http://www.scottish-enterprise.com/sector-energy
knowledge;
high level skills;
technology; and
innovation.
SDI gives advice on the best locations, assists with recruitment and training, and
offers a business mentoring service. They also supply market information to help you
make the right connections.
By encouraging international companies to share expertise and promoting the
expansion of Scotland’s portfolio of first-class exports, they strive to create
partnerships with overseas investors, opening up new channels to markets,
technologies and products. SDI even helps strike licensing deals with some of the
UK’s top universities.
Different businesses require different thinking, so SDI creates tailored solutions to
deliver exactly what business needs. By promoting Scotland as a dynamic economy
on the international stage, SDI helps companies to succeed in the global
marketplace.
Further information on SDI’s activities in the Energy Sector can be found at:
http://www.sdi.co.uk/
- 45 -
APPENDICES
Appendix 1 Flowchart illustrating data sources and manipulation Appendix 2 Questionnaire Appendix 3 Calculation of Market Value of Equipment Supply
Appendix 4 Kingsnorth Case Study
Appendix 5 Nuclear Decommissioning Appendix 6 Cost and Technology Parameters
Appendix 7 Contractual approaches Appendix 1 Flowchart illustrating data sources and manipulation
SKM models
For typical coal, CCGT
& nuclear plants
(using Thermoflow PEACE)
% breakdowns
of equipment costs within EPC price
IEA EIA
World Energy Outlook 2008
2008 Data
WNA, Platts
& others total installed 2006;
projected capacity 2015
New build (GW)
Forecast increase in
capacity for 2015
New build ($)
for coal, nuclear & CCGT projects
Breakdown in value
of specific plant items
$/kW
Capital costs
Primary
Research
inc IPA information Appendix 2 Questionnaire
The approach to the respondents addressed a technical agenda as shown below:
Appendix 3 Calculation of Market Value of Equipment Supply
1) Forecast increase in capacity
The value for forecast increase in capacity between
2007 and 2015 is estimated from EIA sources.
The total value of the coal, gas, and nuclear new build
is calculated using an estimated price per kW.
2) Equipment percentage breakdown
The percentage breakdown for various items of
equipment is extracted from the coal fired 400MW
and 600Mw models.
3) Market value of equipment supply
The equipment percentage breakdown is applied to
the total value of the coal fired new build to extract an
average value for the estimated market of each
equipment type between 2007 and 2015
Appendix 4 Kingsnorth Case Study
Units 5 and 6
Carbon capture
This case study has been prepared as Kingsnorth is the first (proposed) new build
coal fired plant in the UK since the second stage of Drax completed commissioning
in 1986. The proposed plant has raised a number of issues as to how large projects
such as this proceed in the UK, and may be representative of the issues facing
similar new large plants world-wide. The project is under considerable pressure to
include carbon capture, thus should the design be developed to meet the demands
of all its critics, this study would effectively provide a worked example of the scope of
a clean coal plant which could be built before 2015.
The project has created enormous public interest – a Google (UK) search on
Kingsnorth currently produces 150,000 hits. During the summer of 2008 protesters
created a ‘Climate Camp’ close to the existing plant, and created much media
attention; Kingsnorth has become a cause célèbre for environmental groups. The
protesters main bone of contention is that no new coal plant is acceptable without
major carbon abatement, specifically carbon capture, which is not currently planned.
The government has announced that it will make a decision by the end of 2009.
E.ON - UK is planning to build two additional generating units (Nos 5 and 6) at its
existing Kingsnorth site on the Medway Estuary / Hoo Peninsula in Kent. These will
use super-critical boilers and turbines. Once these new units are commissioned, the
original plant shall be decommissioned. Units 1-4 (485 MW each) , designated as
‘existing plant' in the Large Combustion Plant Directive (LCPD), have been 'optedout' and must close by the end of 2015. E.ON’s website provides an overview of the
project:
http://www.eon-uk.com/generation/supercritical.aspx
The following information is also available in the public domain:
Environmental impact assessment (EIA)
http://www.eon-uk.com/images/Environmental_Statement_Kingsnorth.pdf
Planning submission MC2007/0014 was made to Medway Council on 15 December
2006. A Section 36 (Electricity Act) application was also made in December 2006 for
a 1600 MW maximum electrical output plant.
Prior to the creation of Department of Energy and Climate Change (DECC), the
Environmental Agency has commented on the project, and at that stage did not
support the project as it does not have carbon capture. See http://www.parliament.thestationery-office.com/pa/cm200708/cmselect/cmenvaud/654/654we05.htm
The project is competing to be the UK demonstration plant for carbon capture. This
aspect of the project would involve a consortium of partners: project managers Arup,
technology consultants EPRI, carbon capture technology suppliers Fluor and MHI,
pipeline transportation firm, Penspen, and carbon dioxide storage partner Tullow Oil.
See E.ON press release 1
Independent bodies such as the Royal Society have contributed to the debate http://royalsociety.org/displaypagedoc.asp?id=29510 - the Society argues that planning
consents should only be granted if new plants can capture 90% of the carbon dioxide
produced. Typical of the pressure groups submissions to the debate is that from the
World Wildlife Fund which also argues that the project should not proceed unless
carbon capture is fitted. WWF has commissioned a report from Edinburgh
University’s Scottish Centre for Carbon Storage (SCCS):
http://assets.wwf.org.uk/downloads/evading_capture_brief.pdf
Originally planned to get the go-ahead by early summer of 2008, E.ON asked for a
delay in consents to allow the (then) BERR considerations on carbon capture to be
completed before they (E.ON) would commence the project.
The plant will use supercritical boiler and turbine technology which will increase the
plant efficiency from (the existing units) 36% to 45%. This will reduce the carbon
dioxide produced from 850 g/kWh to 700 g/kWh. This compares with 320 g/kWh for
a modern CCGT plant, or 350 g/kWh for an IGCC plant (which is unlikely to be
available until after 2015.
Supply chain
E.ON’s proposed supply chain for this project follows an open tendering process.
Currently E.ON is still negotiating (due to the delays in programme, and possible
change in scope) with preferred tenderers in Doosan Babcock and Alstom /
Siemens. Doosan has offered to provide boilers. It also presented written evidence
to the Select Committee on Environment Audit:
http://www.publications.parliament.uk/pa/cm200708/cmselect/cmenvaud/654/654we12.htm
1
http://pressreleases.eon-uk.com/blogs/eonukpressreleases/archive/2008/03/31/E.ON-enters-UKGovernment_2700_s-Carbon-Capture-and-Storage-competition.aspx
This describes the plant offered for Kingsnorth. Note that E.ON has identified other
partners for the tendered carbon capture competition who are detailed above.
E.ON has declared that the plant is carbon-capture-ready: that is, space is available
to build post combustion capture (PCC), and a route to a possible storage location
has been identified.
Likely contract value
The declared cost for the additional units without carbon capture is £1000M. If
carbon capture plant is added then the cost will increase, and the net generation will
reduce, thus, both the capital and the operational costs will increase. The value of
the amine scrubbing as the post-combustion capture could be assessed, however,
that would be an academic exercise if a final storage solution has not been agreed.
This compares with the £500M for the 1250 MW CCGT plant nearby at the Isle of
Grain.
Other information
Kingsnorth is effectively a re-planting of a power station site. As sea water cooling is
used for the turbine condensers, the 1800 MW of new plant reduces the impact on
the local ecology than the four units (1940 MWe) being replaced.
Appendix 5 Nuclear Decommissioning
New nuclear build vs. nuclear decommissioning
There has been much debate on whether the decommissioning workforce will
migrate to the apparently more glamorous world of new-build. Many will argue that
decommissioning provides a good grounding in nuclear procedures and working
arrangements. Decommissioning will always be more rigorous than new-build as
contaminated waste is associated with almost all aspects of those projects, whereas,
generation has a well defined ‘nuclear island’ with much of the plant very similar to
conventional fossil-fired plant.
Thus, assuming that contractors need to consider pursuing nuclear decommissioning
work to develop their credentials for new-build work, the would-be supplier should be
aware of the ‘overheads’ associated with working in this sector. The supplier will
have to be able to demonstrate an enhanced safety culture within their organisation.
They will require radiation monitoring for staff who visit licensed sites, appointing a
Radiation Protection Supervisor (RPS) and Adviser (RPA). They will require to put in
place security clearance arrangement working on these designs as the Office for
Civil Nuclear Security (OCNS) consider this knowledge (both of decommissioning
site and power station sites) to be of national security. Design information held will
require to be managed such that on security cleared personnel have access to it.
The actual opportunities in decommissioning are published in some detail on the Site
Licensee Companies’ (SLCs’) web sites. This area is discussed in more detail in
following sections.
Nuclear decommissioning
In 2004 Scottish Enterprise published advice on opportunities in nuclear
decommissioning. This is still available at:
http://www.scottish-enterprise.com/publications/nuclear_decommissioning_opportunities.pdf
At that time the Nuclear Decommissioning Authority (NDA) was just being
established, and its strategy for decommissioning being formulated. In 2005 the
NDA became responsible for all the decommissioning of Sellafield, Dounreay, and
the Harwell and Winfrith research sites, the magnox stations which have closed. The
NDA is also responsible for running the remaining reprocessing facilities at Sellafield
and Dounreay, the fuel manufacturing plant at Preston and the remaining operational
magnox power stations, Oldbury and Wylfa. Much of the 2004 report is still relevant,
particularly the advice on barriers to entry and opportunities for technology transfer
from other sectors. In the intervening period, one of the areas which has been
developed from the oil and gas sector is the modularisation of equipment to allow a
faster site installation and a shorter commissioning period. This is a technique which
has also been developed for new-build.
In 2005, the DTI, SDI and UKTI published a report on Global Decommissioning
Opportunities. This includes a section dedicated to Opportunities and Issues for
Scotland. This report still provides a fair explanation of the international market and
the differences in approach between different countries. This report is available via:
http://collections.europarchive.org/tna/20060715171900/http:/www.dti.gov.uk/energy/eid/page2
7830.html
More recently, the Word Nuclear Association has published a useful
discussion document, which, albeit labelled as Safe Decommissioning,
provides a good general overview of nuclear decommissioning activities.
http://www.world-nuclear.org/reference/position_statements/decommissioning.html
The information which follows on nuclear decommissioning is generally specific to
what is happening in the United Kingdom. As decommissioning calls on many of the
personnel skill sets which will be required for nuclear new-build, an overview is
included here to allow companies to consider this as a way of developing those skills
as the relatively slow-moving new-build process. It concentrates on identifying the
synergies and clashes for resources with new nuclear build
The NDA is now responsible for the decommissioning of the 20 former UKAEA and
BNFL sites and for developing an integrated waste strategy for the UK. The NDA
reports to (its sponsoring Government department) the Department for Business,
Enterprise and Regulatory Reform (DBERR). A successful decommissioning
programme is important in making a case for new nuclear build, so it is likely to have
its current funding continued and decommissioning work will continue for at least the
next twenty years.
Earlier this year (2008), the NDA published its comprehensive spending review
(CSR). This requested an increase in funding from the Treasury which was
awarded. Currently, funding is being channelled towards Sellafield and Dounreay,
somewhat at the expense of projects on the magnox plants, at Harwell and at
Winfrith.
Lifetime plans (LTPs) have now been produced by the Site Licensee Companies
(SLCs) or Tier 1 contractors to the NDA. These are published by the NDA and in
more detail by the SLCs.
The NDA has also awarded the low-level waste repository (LLWR) contract to UK
Nuclear Waste Management (UKNWM) – a consortium of URS Washington, AREVA,
Studsvik and Serco Assurance.
Many of the existing site operators have taken on-board US companies as partners;
these companies are deemed to have greater experience from the faster
decommissioning which has been taking place in the US. However, to date this has
not had any impact on the supply chain process with contracts still being via the
European Union procurement process, with all major projects being advertised.
In 2007, the World Nuclear Association produced a statement on the status of
decommissioning activities worldwide
http://www.world-nuclear.org/info/inf19.html
The SLCs will provide continuity for the management a site, however, the contractual
responsibility for the SLC will via its Parent Body Organisation (PBO). This role is
currently being competitively bid for Sellafield and by May (2008) the preferred
bidder should be announced. Contracts with the existing SLC will be honoured;
however, new work will depend on the new PBO’s approach to managing its supply
chain which may differ from that currently in place.
The general terms and conditions for all work with the NDA’s various SLCs is defined
by standard terms and conditions which flow down through the SLCs (Tier 1s) to the
suppliers (Tier 2, Tier 3, etc. contractors). Currently, the various SLCs are
endeavouring to standardise their pre-qualification processes however, the three key
SLCs have different procurement systems and separate submissions will still be
required, albeit providing responses to similar questions.
Site Licensee
Company
Procurement
process
UKAEA
Omnicon
Magnox
stations
Achilles (UVDB)
Sellafield
CTM
Remarks
For the UK market, the NDA has published a Procurement Plan (last updated in June
2008) and available at http://www.nda.gov.uk/contracts/opportunities/
This details the existing supply chain for the HQs NDA operation, links to the
decommissioning sites procurement operations, and advice on how to use Tenders
Electronically Daily to search for decommissioning opportunities.
Supply Chain Network databases
Sellafield has established an on-line Supply Chain Network database for use by all
nuclear sector suppliers:
http://www.sellafieldsites.com/page/suppliers/supply-chain-network
This is separate from the Complete Tender management procurement route detailed
above and may provide a route for companies to come together to create solutions
for the UK SLCs. It may also provide a platform for companies to develop alliances
to bid international decommissioning projects.
New-build on decommissioning sites
In March 2008 the NDA invited proposals from developers for new-build projects on
NDA sites. These sites are much more likely to succeed as:
Utility Vendors database
Complete Tender Management system
Currently projects are progressing in a start/stop manner, often due to the NDA’s
need to reallocate funding to different sites or projects to meet their prime
responsibility of managing the biggest risks. The regulator - the Nuclear Installations
Inspectorate (NII) of the HSE – has the greater clout on this aspect of the process
and until some generic approaches to safety management are developed then this
unpredictable progress is likely to continue. The contractor working in these areas
must be prepared for this unpredictability.
•
There is generally local support for nuclear
•
Previous usage of sea or river water for turbine condenser cooling will ease the
projects through planning
International projects
UKAEA is pursuing international opportunities for its own workforce to both provide a
spread of work to smooth out the troughs in funding for its own in-house
decommissioning, and partly to ensure a long term workload for its staff based
primarily around Dounreay. In these projects, UKAEA is likely to concentrate on
project management and technical strategy and will rely on some of its own supply
chain to support projects.
Appendix 6 Cost and Technology Parameters
Main cost and technology parameters of plants starting commercial operation in 2015
Parameter
Unit
Coal steam
CCGT
Nuclear
IGCC
Wind onshore
%
85
85
85
85
28
%
44
58
33
46
n/a
Construction period
months
48
36
60
54
18
Plant life
years
40
25
40
40
20
Capacity factor
Thermal efficiency (net, LHV)
a
b
Investment cost
USD/kW
1,400
650
2,000-2,500
1,600
900
Annual incremental capital cost
USD/kW
12
6
20
14
10
Unit cost of fuel
USD/MBtu
50
25
65
55
20
4.21
2.43
n/a
4.21
n/a
c
Total OandM cost
Carbon intensity of the fuel
USD/kW
d
t CO2 per toe
a) Lower heating value (LHV) is the heat liberated by the complete combustion of a unit of fuel when the water produced is assumed to remain as a vapour and the heat is not recovered.
b) Total capital expenditure for the project, excluding the cost of finance.
c) Total non-fuel operating and maintenance costs are assumed to be fixed.
d) CO2 intensity refers to electricity generation only. Life cycle emissions are somewhat higher for wind and nuclear power (but still negligible compared with coal or gas).
Source: IEA World Energy Outlook 2006, forecast of 2015 costs.
Appendix 7 Contractual approaches
There are a number of contractual approaches that can be taken to construct a
power station. Engineering, Procurement and Construction ("EPC") Contracts have
historically been the most common form of contract used to undertake power plant
projects by the private sector on large scale. Another option is to have a supply
contract, a design agreement and construction contract with or without a project
management agreement. The choice of contracting approach depends on a number
of factors including the time available, the lenders requirements and the identity of
the contractor(s). The following section is a brief summary of the various contract
strategies used to building power plants.
Engineering, procurement and construction (EPC)
In an engineering, procurement and construction (EPC) contract, the EPC contractor
(EPCC) agrees to deliver a commissioned plant to the owner for an agreed amount.
EPC, also known as Design-Build, is a project delivery method that combines two,
usually separate services into a single contract. With EPC procurements, owners
execute a single, fixed-fee contract for both architectural/engineering services and
construction.
Under an EPC Contract a contractor is obliged to deliver a complete facility to a
developer who need only 'turn a key' to start operating the facility, hence EPC
Contracts are sometimes called turnkey construction contracts. In addition to
delivering a complete facility, the contractor must deliver that facility for a guaranteed
price by a guaranteed date and it must perform to the specified level.
EPC contracts generally involve the contractor assuming a greater proportion of the
risk than they would in a multi-contract context. Therefore there are inherent risks
and complexities in EPC contracts due to the involvement of different parties and
various factors.
Engineering, procurement, construction and management
Engineering, Procurement, Construction and Management (EPCM), also known as
Design Bid Build, is the traditional project delivery approach that was used for most
of the 20th century to procure public works. The EPCM segregates design and
construction responsibilities by awarding them to an independent private engineer
and a separate private contractor.
•
During the initial design phase, a design contract is awarded to an architectengineer or designer. The architect - engineer is responsible for completing a
final project design and providing detailed documentation, including drawings,
specifications, and supporting documentation.
•
The owner would use the documentation prepared by the engineer to assemble
construction bid documents. The project would then move into the construction
phase, with the owner retaining responsibility for monitoring the contractor's
performance.
Multi-contracting
Multi-contracting is when the works are let in a number of packages. For multicontracting to work well, the owner must possess (or buy-in) good project
management skills.
One advantage of procurement on this basis in the current climate is the scope to
tailor risk allocation to the particular requirements of each package. In addition, by
reducing contract values it can also help reduce prospective liabilities of the
contractors and lead to cost reductions.
Alliance agreements
An alliance agreement or framework is generally formed between the leading
equipment suppliers and construction companies for a project to work towards a set
project goals. An Alliance Leadership Team (ALT), consisting of one or more senior
representatives from each alliance member company, is responsible for overseeing
the project. Concepts of alliance working can bring benefits to the project. As the
parties work together in a spirit of mutual trust and co-operation, they will typically
begin to introduce formal communication structures, sharing of resources, joint
determination of goals and objectives and shared risks.
This aim of the project alliance contract is to align the interests of the owner and the
contractor to build the project in a collaborative way, without disputes and without
major claims.

The Worldwide Thermal Power Generation Market

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