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    MALAYSIA CHANGES

    ENERGY STRATEGYONLINE CONDITIONMONITORING

    STEAM GENERATORS:BOOSTING FLEXIBILITY

    FUEL CELL POWER IN

    SOUTH KOREA

    Official Media Partner for

    POWER-GEN Asia 2014

    SHOW ISSUE

    A new dawn forJapans power sector

    July-August 2014The magazine for the international power industry

    www.PowerEngineeringInt.com

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    Follow GE Power & Water

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    powergen.gepower.com

    We introduced H-class.So its only natural thatwe take it to the next level.A decade ago, GE built the industrys first H-class gas turbine. Since then, our H-class gas turbineshave logged more than 200,000 hours of operation and data monitoring. This experience, anddata-driven insights, have led to performance improvements and smart innovation. Today, our7HA and 9HA gas turbines lead the industry in total lifecycle value through strategic service

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    Contents

    POWER ENGINEERING INTERNATIONAL

    Free Product InfoYou can request product and service information from this issue. Simply click on the link below that will provide you access to supplier companies websites,

    product information and morehttp://pei.hotims.com

    If you are considering suppliers or buying products you read about in PEi, please use this service. It gives us an idea of how products are being received to help us continually

    improve our editorial offering and it also lets our advertisers know that you are a PEi reader and helps them to continue supporting the free distribution of your magazine.

    Power Engineering InternationalJuly-August 2014

    JULY-AUGUST 2014///VOLUME 22///ISSUE 7

    34 Steam generator flexilibity at low load

    Detailed analysis is the basis for success in optimizing existingboilers and further reducing stable minimum load.

    44 Risk in renewables investment

    How renewables investors moving into new and emergingmarkets can deal with additional market-specific risk.

    50 Online condition monitoring

    Early detection can mitigate the effects of medium andpeak load operation on power plant core components.

    56 Automated demand response in Europe

    ADR offers utilities a low-carbon method of stabilizingthe grid and accommodating peaks in demand quickly,

    effectively and cheaply.

    60 Power perspectives: pumped storage

    As the UK reforms its electricity market, it must alsorecognize and close its storage gap.

    Regional Profile

    10 Malaysias changing power sector

    With economic growth driving a need for more power,Malaysia is changing the way it generates and delivers

    electricity.

    2 Industry Highlights

    4 News Analysis

    64 Diary

    66 Project & Technology Update

    72 Ad Index

    Features

    16 Power Report: Japan

    Since the 2011 earthquake that destroyed the Fukushimanuclear complex, Japans energy industry has been in crisis.

    We explore how the sector is responding to the challenges.

    22 Fuel cell power scales up

    A look at the worlds biggest fuel cell energy park in SouthKorea and the company behind it, US-based FuelCell Energy.

    28 Walking the torque

    Howard Barnes of MAN Diesel & Turbo tells Kelvin Ross why hebelieves the power sector is on the verge of a gas engine

    boom.

    Malaysias changing power sector p.10

    Credit: Siemens

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    Industry Highlights

    Research reports on the various sectors

    of the power market are ten-a-penny,

    but what nearly all of them share

    regardless of what technology they are

    reporting on is that, at some point in their

    findings, they will state that Asia is driving

    growth in that particular technology.

    In the last few weeks I have read such

    reports on the markets for renewables (solar in

    particular), smart city technology, smart grid,

    diesel gensets the list goes on.

    All of which is good news for Asia, its powersector and those companies working in it and

    looking to break into it because the potential

    rewards are colossal.

    One of the aforementioned reports from

    Bloomberg New Energy Finance predicts

    that the Asia-Pacific region will spend

    $3.6 trillion between now and 2030 to meet its

    power demands (see story on p4).

    This opens the door to many European

    companies: business goes where business is,

    and there is precious little of it to be had in

    many parts of Europe these days.Jonathan Robinson, senior energy

    consultant at Frost & Sullivan, highlighted the

    attraction of Asia to European engineering

    companies and vice versa when he spoke

    about how German technological know-how

    is set to prove vital to China as it tackles its

    carbon emissions.

    Germany is a global leader in

    environmental technologies, thanks to years of

    tough regulations and attractive incentives for

    alternative energy solutions. He added that

    Germany is Chinas largest trading partner

    in Europe and China is Germanys in the

    Asia-Pacific region, so both countries already

    understand what each can offer(story p8).

    One such German firm targeting Asia

    in particular Southeast Asia is MAN Diesel

    & Turbo, which sees huge potential in the

    region for its gas engines. Yet the company

    has far from written off its home territory for

    new business. Embracing the new European

    power need for flexibility, it believes it has the

    technology to drive the next evolution of the

    gas market. Find out what it is in my interview

    with the companys vice president of powerplants, Howard Barnes, on p28.

    And there is no doubt that a power evolution

    is needed in Europe. At a press conference I

    attended in London recently, Fatih Birol, chief

    economist of the International Energy Agency,

    stated that the European thermal power

    market was almost uninvestable.

    Birol was speaking at a conference

    examining the UK sector and he said that the

    British governments Electricity Market Reform

    package was moving in the right direction

    and is an example to many other countries.

    Part of that reform package is the

    introduction of a capacity mechanism andcontracts for difference a guaranteed

    price paid to energy firms for the electricity

    they generate and both of these measures

    cleared EU State Aid rules in July.

    This is good news in a broad sense, but just

    how good depends on which sector you work

    in. One market that feels like it has dropped

    off the governments radar is pumped

    storage. Quarry Battery Company is a UK firm

    that turns abandoned quarries and mines

    into energy storage facilities. In this issue, its

    managing director Dave Holmes writes thatthe provision of more grid-scale storage to

    partner renewables has been notably absent

    from British government action.

    In his article on p60 part of a new series

    we are running called Power Perspectives

    he urges the government to secure Britains

    energy future by backing storage in a way that

    their predecessors had neither the foresight

    nor the courage to do.

    There is certainly no lack of foresight and

    courage in Asia. It has become the go-to

    power sector because it is the get-on-with-it

    region. And this sets the scene for lively, relevant

    debate at this years POWER-GEN Asia, being

    held in Kuala Lumpur from 1012 September

    (register atwww.powergenasia.com).

    With debates on topics such as flexible

    generation, emissions control, smart and

    micro grids and sustainable power growth

    as well as technical sessions on the latest

    developments in gas and steam turbines,

    boilers, generators and control systems, plus

    many more it is sure to be an indicator

    not just of how far the region has come in

    developing its energy mix, and also how far itis prepared to go. Ill be there in Kuala Lumpur

    and I hope to see you there too.

    The Asia Pacificregion will spend$3.6 trillion between

    now and 2030 to meetits power needs.Kelvin RossEditorwww.PowerEngineeringInt.com

    Follow PEi Magazine on Twitter:

    @PEimagzine

    Follow me: @kelvinross68

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    6/764 www.PowerEngineeringInt.comPower Engineering InternationalJuly-August 2014

    News Analysis

    The Asia-Pacific region will spend $3.6 trillion

    between now and 2030 to meet its power

    demands, and two thirds of that sum will go

    on renewable technologies, according to a

    new report.

    The study from research company

    Bloomberg New Energy Finance (BNEF)

    called BNEF 2030 Market Outlook is based

    on modelling of electricity market supply

    and demand, technology cost evolution and

    policy development in individual countries

    and regions. It forecasts that Asia-Pacific will

    account for more than half of the 5 TW of

    net new power capacity that will be added

    worldwide in the next decade and a half, and

    this will equate to $3.6 trillion of investment in

    the region.

    While it predicts that Asia-Pacifics fossilfuel power sources, such as coal and gas,

    will continue to grow despite concerns about

    pollution and climate change, the biggest

    growth will be in renewables, with some

    $2.5 trillion invested and 1.7 TW of capacity

    added.

    Milo Sjardin, head of Asia-Pacific for BNEF,

    said: The period to 2030 is going to see

    spectacular growth in solar in this region, with

    nearly 800 GW of rooftop and utility-scale PV

    added. This will be driven by economics, not

    subsidies. Our analysis suggests that solar will

    be fully competitive with other power sources

    by 2020, only six years from now.

    However, Sjardin added that this does not

    mean that the days of fossil-fuel power are

    over far from it. Rapid economic growth in

    Asia will still drive net increases of 434 GW in

    coal-fired capacity and 314 GW in gas-fired

    plant between now and 2030. That meansthat emissions will continue to increase for

    many years to come.

    BNEF forecasts that China will add a net

    1.4 TW of new generating capacity between

    now and 2030 to meet a surge in power

    demand. This will require capital investment

    of around $2 trillion, of which 72 per cent will

    go to renewables such as wind, solar and

    hydro.

    Meanwhile, Japans power sector will

    experience a very different trajectory in the

    next 16 years, with electricity demand only

    regaining its 2010 levels in 2021 and then

    growing at a modest 1 per cent a year, as

    efficiency gains partially offset economic

    growth. The report states that Japan will invest

    around $203bn in new power generation

    capacity by 2030, with $116bn going to

    rooftop solar and $72bn to other renewable

    technologies.India is forecast to see a quadrupling of its

    power generation capacity, from 236 GW in

    ASIA-PACIFIC

    Asia-Pacific to outpace Europe in renewables

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    An Efficient,Compact Design forChallenging Fuels

    Steam cycle effi ciency and fuel flexibility are key advantages of blending together

    two proven boiler technology designs supercritical once-through and fluidized-bed

    combustion. Babcock & Wilcox Power Generation Group, Inc.s (B&W) supercritical

    circulating fluidized-bed (CFB) boiler is a unique product of this technology fusion,

    allowing power producers to sustainably use diffi cult-to-burn fuels, such as wastecoal, to produce electricity while reducing the environmental impact of the steam

    generation process.

    Nearly 50 years ago, B&W designed and built the worlds first commercially operated

    supercritical boiler and helped transform the power generation industry through an

    effi cient boiler design that improved plant heat rates, and reduced fuel consumption

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    of CFB boiler experience, B&Ws supercritical CFB is a natural evolution to meet the

    increasing demand for electricity generated from diverse fuels.

    B&Ws supercritical CFB is a

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    changing electric power

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    2014 Babcock & Wilcox Power Generation Group, Inc. All rights reserved.

    The information contained herein is provided for general information purposes only and is not intended nor

    to be construed as a warranty, an offer, or any representation of contractual or other legal responsibility.

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    B&Ws supercritical CFB employs a

    two-stage solids separation system,

    with U-beams and a multi-cyclone

    dust collector, to provide high solids

    collection effi ciency and controllable

    furnace performance for low carbon

    loss, limestone usage and emissions. This design also allows for a more compact

    furnace arrangement than typical hot cyclone CFB arrangements.

    In-Bed Heat Exchanger (IBHX)Division walls and wing walls are typically used to add internal heating surface in

    a CFB. For large supercritical CFBs, the number of division and wing walls required

    would be extensive and require taller furnaces to solve arrangement and once-

    through circulation issues. B&Ws IBHX is an effective solution to compensate

    for the internal heating surface requirements of a large supercritical CFB, again

    allowing for a more compact furnace arrangement.

    Together, the solids collection system and IBHX features of B&Ws supercritical CFB

    allow scalability with a cost-effective, compact design translating into reduced

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    Learn more about B&Ws supercritical CFB and other innovative steam generation

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    Two-Stage SolidsSeparation System

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    With its patented two-stage

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    capital costs.

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    10/768 www.PowerEngineeringInt.comPower Engineering InternationalJuly-August 2014

    News Analysis

    2013 to 887 GW in 2030, with 169 GW taking

    the form of utility-scale solar and 98 GW of

    onshore wind. Hydro will see capacity boosted

    by 95 GW, coal by 155 GW and gas by 55 GW.

    This will take Indias total investment to 2030 to

    $754bn, with $477bn of that in renewables.

    Meanwhile in Europe, the report forecasts

    that 557 GW of new renewable capacity will

    come online by 2030.

    In the same period, it predicts coal-fired

    capacity will shrink from 195 GW to 125 GW

    as emission regulations bite and the cost-

    of-generation comparison shifts in favour

    of renewables, while gas-fired capacity

    increases modestly from 257 GW to 280 GW.

    Seb Henbest, BNEFs head of Europe, Middle

    East and Africa, said: Our research shows that

    further improvements in the economics of

    solar and wind will mean they are increasingly

    installed without subsidy in the years ahead.

    We expect Europe to invest nearly $1 trillion

    to increase its renewables capacity by 2030,

    with rooftop PV accounting for $339bn and

    onshore wind $250bn.

    Our model suggests that power demand

    in Europe will increase by only 9 per cent

    between 2014 and 2030, as energy efficiencyimprovements take effect. This, and the

    growing cost advantage of wind and solar, will

    enable the continent to cut its power sector

    emissions from 1.3bn tonnes of CO2in 2013 to

    564m tonnes in 2030.

    BNEF states that the only major renewable

    power technology to remain subsidized

    in the 2020s will be offshore wind, and the

    report predicts that Europe will add 64 GW

    of offshore wind capacity between now and

    2030, involving an investment of $296bn, as

    governments continue to back it for energy

    security and industrial development reasons.

    Germany is expected to see $171bn of

    investment in renewable generation, with

    small-scale solar taking $69bn of that, offshore

    wind $70bn and onshore wind $18bn. The

    UK is forecast to invest $197bn, with offshore

    wind taking $89bn, small-scale solar $49bn

    and gas-fired capacity installed partly for

    balancing purposes taking $8bn.

    Globally, BNEF expects $7.7 trillion to be

    invested in new generating capacity by

    2030, with 66 per cent going on renewable

    technologies including hydro. Out of the

    $5.1 trillion to be spent on renewables, the

    Asia-Pacific region will account for $2.5 trillion,

    the Americas $816bn, Europe $967bn and therest of the world, including the Middle East

    and Africa, $818bn.

    The report states that fossil fuels will retain

    the biggest share of power generation by 2030

    at 44 per cent, albeit down from 64 per cent

    in 2013. Some 1073 GW of new coal, gas and

    oil capacity worldwide will be added over the

    next 16 years, excluding replacement plant.

    The vast majority will be in developing

    countries seeking to meet the increased power

    demand that comes with industrialization,

    and also to balance variable generation

    sources such as wind and solar. Solar PV and

    wind will increase their combined share of

    global generation from 3 per cent last year to

    16 per cent in 2030.

    The spectaculargrowth in solar will bedriven by economics,not subsidies.Solar will be fullycompetitive withother power sourcesby 2020.Milo Sjardin, head of Asia-Pacific for BNEF

    German power firms set for China boom timeGerman companies are poised to reap the

    rewards from power opportunities in China,

    India and developing Asia, according to an

    energy expert.

    Jonathan Robinson, senior energy

    consultant at Frost & Sullivan, said that German

    technological know-how is set to prove vital to

    China as it tackles its carbon emissions.

    Pollution in China has been a serious issue

    for some time, but it has now become one of

    the biggest sources of public discontent in

    the country, and as a result is a hot political

    issue.

    The Chinese government is focused on

    reducing environmental damage both in

    terms of atmospheric emissions and also

    water pollution as well as making better useof the waste resource that is produced.

    Robinson said Germany is a global leader

    in environmental technologies, thanks to years

    of tough regulations and attractive incentives

    for alternative energy solutions, adding that

    it was already Chinas largest trading partner

    in Europe, and China is Germanys in the

    Asia-Pacific region, so both countries already

    understand what each can offer.

    He said reducing air pollution is a key

    objective in China and the countrys coal

    plants already have pollution control

    technology fitted, but many industries,

    particularly manufacturing, petrochemical

    and chemical, are still heavy polluters.

    According to Robinson,water is another

    key issue. Chinas coal industry is water

    intensive this includes mining, usage in

    power plants and also usage in associatedheavy industries. Installing wastewater

    treatment solutions could help to avoid water

    shortage within the industry, ensuring sufficient

    availability for the population and agriculture.

    He stressed that the waste-to-energy potential

    is also huge, as is the potential for greater

    waste recycling and re-use and the potential

    for biogas, which offers huge opportunities.

    However, he added that the big concern

    for German companies is to find a way to sell

    their products and services into the Chinese

    market, while also protecting their intellectual

    property rights something that has proved

    an issue for a number of major companies in

    the past.

    The most likely route to market would

    be through partnerships/joint ventures with

    Chinese players or potential technology

    licence agreements although these carrythe risk of creating competitors for the future,

    he said.

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    W

    ith Malaysia boasting

    average GDP growth

    of around 6 per cent

    for the last four years

    edging up to around6.2 per cent in the first

    three months of this year economists remain

    bullish about this Southeast Asian nations

    newly industrialized market economy.

    The strong economic growth is driving

    demand for electricity, which according to

    state power company TNB is expected to

    grow at an annual rate of 3 per cent up to

    2030, when per capita demand should reach

    the OECD average.

    Malaysia has always seen its power

    sector primarily as a strategic resource and

    an essential input to the economy. In May

    the Prime Minister, Najib Razak, reaffirmed his

    support for TNBs dominant role in providing

    reliable and affordable power to fuel the

    countrys quest to become a developed

    nation. He also defended a recent hike in

    tariffs, noting that TNBs capital expenditure

    required to expand production capacity andkeep pace with demand had been larger

    than its profits for some time, requiring loans

    to make up the difference.

    But in opting to maintain a power sector

    dominated by a state generator and operator,

    alongside independent power producers

    (IPPs), Dr Razak is continuing with a model

    perhaps more associated with developing

    countries than a developed one.

    However, while TNB remains responsible

    for the transmission, distribution and nearly

    half of the power generation in Peninsular

    Malaysia, its role as system operator and

    single buyer is in the process of being

    ring-fenced to enhance transparency,

    Regional profile: Malaysia

    With economic growthdriving the need for moreenergy, Malaysia has set

    out plans to meet thisdemand while at thesame time changing theway it generates anddelivers electricity, writesJeremy Bowden

    Malaysias changingpower sector

    Sarawaks Murum hydroelectric project came online this year

    Credit: Sarawak Energy

    10 Power Engineering InternationalJuly-August 2014 www.PowerEngineeringInt.com

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    Regional profile: Malaysia

    independence and fair play in generation

    scheduling and dispatch.

    In addition, TNB has been divided into

    five business entities in anticipation offull implementation of incentive-based

    regulation (IBR) in 2015.

    The IBR is meant to enhance operational

    efficiency and transparency towards

    maintaining a reliable and sustainable

    electricity supply, according to Malaysias

    Energy Commission. It includes the

    introduction of a fuel cost pass-through

    mechanism (FCPT), which will allow power

    prices to move in line with fuel costs. This will

    stabilize TNB profits and help it to meet CAPEX

    obligations: With the implementation of the

    IBR and FCPT, it is anticipated that the fuel

    cost risks are mitigated, therefore leading

    to better earnings predictability for TNB, the

    company said.

    Over recent years, Malaysia and TNB have

    managed to maintain a healthy reserve

    margin of around 6 GW, or 20 per cent,

    against quickly rising demand. Prices and

    costs have been kept low by cheap domestic

    gas, power price control and subsidies, but

    this fuel cost advantage is fast disappearing

    as domestic gas reserves decline and the

    country becomes increasingly reliant on

    international coal and liquefied natural gas(LNG) markets for its fuel supply.

    So while Malaysia may not be moving

    in the competitive market direction in

    generation or retail, it is recognizing that

    maintaining a costly subsidy system is

    becoming less and less affordable.

    Effective from 1 January of this year,

    electricity tariffs were raised by an average

    of 15 per cent to help phase out energy

    subsidies through the Subsidy Rationalization

    Programme.

    However, this has been the only rise since

    June 2011, and was unpopular among

    sections of business and the public even

    though many consumers enjoy discounted

    rates. More such politically sensitive rises are

    needed, as the government will still have to

    spend RM14 billion ($3.6 billion) annually

    on subsidies and rebates, according to the

    minister for Energy, Green Technology and

    Water, Dr Maximus Ongkili.

    In its financial year ended in August 2013,

    Serving much smaller and more dispersed

    populations, Sabah and Sarawaks powerproviders have experienced dynamic

    change in recent years.

    Part of its efforts to promote itself as a

    heavy industrial destination, the Sarawak

    Corridor of Renewable Energy (SCORE)

    strategy involves a massive increase in

    capacity generation. Projects include the

    2400 MW Bakun hydropower plant (HPP),

    which came fully onstream in 2013; the 944

    MW Murum HPP (operational by this year);

    the 150 MW Limbang HPP (2013); the 1000

    MW Baram HPP (2015), and the 400 MW

    Pelagus (2016) and the 1400 MW Baleh

    HPPs (2019). Additional coal-fired thermal

    power plants are also in the works.

    Sabah Electricity (SESB) has access to

    gas as well as hydropower options, but has

    been hit recently by production shortfalls

    due to operational difficulties and cuts in

    gas supply from Petronas. SESB operates

    410 MW of installed capacity,

    supplemented by seven IPPs with 630 MW.

    East Malaysia

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    Regional profile: Malaysia

    TNBs CAPEX was RM8.5 billion, against a net

    profit of RM4.61 billion on RM37.13 billion in

    revenue. TNB is only able to sustain borrowings

    to make up the difference if returns are stable underlining TNBs need for the ICTP.

    TNB has also incurred substantial losses

    on occasions when state oil and gas

    company Petronas had to cut gas supply

    for technical reasons, forcing TNB to switch

    to more expensive distillates. In response,

    the government has floated proposals to

    allow third-party access to the countrys gas

    networks to ensure more stable supply.

    Some private investors in IPPs have always

    been shielded from fuel price risk, as their

    deals included long-term fixed-price gas

    supply deals with Petronas. Such attractive

    terms had led to criticism that some of the

    older IPP deals were overly generous. An

    increased use of direct negotiation as

    opposed to competitive tendering in some

    awards is once again making the IPP process

    controversial.

    In terms of generation mix, the country is

    set for ever greater reliance on imported coal,

    which is normally cheaper than LNG. This is

    despite the fact that Malaysia still exports

    large quantities of LNG to northeast Asia. The

    price it gets for that gas is among the highestin the world, which means the opportunity

    cost if it were to be used at home is very high,

    and in any case much of it is locked up in

    long-term supply deals. The once strong

    enthusiasm for nuclear energy including

    two 1000 MW units by 2021 collapsed in

    the wake of the 2011 Fukushima disaster

    in Japan.

    Nevertheless, Malaysia does still have a

    Solar development has been Malaysias

    most popular renewable category by far, but

    a limit on the size of solar installations and

    rationing of applications has kept a lid on

    capacity growth.

    The Small and Renewable Energy

    Programme (SREP), established to monitor

    the renewable energy industry, allows output

    of no more than 10 MW per solar project to

    be sold to the grid through TNB, and has still

    had to restrict applications due to budget

    constraints.

    As a result, many developers are calling

    on the government to lift the cap, review

    what has become a very generous feed-in

    tariff (FiT) system and introduce scaled tariffs.

    However, as noted above, the

    government has also moved forward with

    some direct deals, including the award

    of a 50 MW plant to 1MDB. While the tariffs

    were not disclosed for that deal, observers

    put likely rates at about half the level of

    deals done in January 2012 at around

    95 sen/kWh ($0.31/kWh) for solar farms with

    a size of 1 MW10 MW, under the FiT system

    introduced in December 2011. The lower

    rate takes advantage of economies of scale

    associated with a 50 MW plant.

    Renewable energy accounts for

    only about 1 per cent of total output in

    Malaysia (not including hydro, which makes

    up around 10 per cent), although the

    government had set a target for renewables

    to account for at least 5.5 per cent of power

    generation by 2015.

    In addition to solar and biogas, new

    hydropower projects are coming onstream,

    such as the 250 MW Hulu Terengganu

    hydropower plant, targeted for operation

    by September 2015, and the 372 MW Ulu

    Jelai plant, scheduled to come online in

    December 2015.

    Renewable rationing

    Operational Under Construction Planned

    Thermal Renewables

    5000

    10,000

    15,000

    20,000

    25,000

    30,000

    40,000

    35,000

    30,000

    25,000

    20,000

    15,000

    10,000

    5000

    Operational

    Planned

    Under Construction

    Figure 1. Capacities by status (MW). Analysis based on the selected power plants

    Figure 2. Capacity planning, by status (MW). Analysis based on the selected power plants

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    Regional profile: Malaysia

    few aces up its sleeve. Gas/LNG is not the

    only energy resource present in Sarawak,

    where new hydropower projects, including

    the 2400 MW Bakun plant, are now operating.It is unlikely to bring any immediate benefit to

    Peninsular Malaysia, however, as plans for an

    interconnector have been put on hold for the

    time being, and the power will be directed to

    local consumers in Borneo, including a major

    new industrial park.

    Other plans to bring in power from the

    Indonesian island of Sumatra have been

    proposed but are fraught with complications,

    while links are being strengthened with

    neighbouring Thailand (see interconnection

    table, right).

    More gas may be present in Malaysia, but

    some commentators complain that overseas

    exploratory interest has been distracted by

    the rise of the unconventional gas sector,

    drawing potential investment elsewhere. This

    leaves Peninsular Malaysia ever more reliant

    on international markets for its fuel supply,

    and this along with the implementation

    challenges of nuclear and some renewables

    has left TNB and the government

    increasingly concerned over energy security,

    as well as costs.

    Gas- and coal-fuelled production

    currently represent around 40 per centeach of Malaysias total, with the remainder

    split between hydro, oil and renewables. On

    the demand side, the industrial sector has

    historically dominated electricity sales, but

    has seen a steady decline since 1990, falling

    from 47 per cent then to 44 per cent in 2011

    and a predicted 41 per cent by 2020. The

    commercial sector is expected to overtake

    the industrial by 2030.

    Controversy over IPPs

    In the absence of a competitive market, IPPs

    are seen as providing an essential source

    of private capital, as well as maintaining

    pressure on TNB to keep its costs under control.

    But public concern over the IPP model has

    resurfaced in the face of a move away from

    competitive tendering and towards direct

    negotiations with some potential investors.

    There has been particular concern over a

    move to award the Johor power plant Track

    4A to YTL Power International, a company

    thought to have benefited from generous

    terms in power purchase agreements (PPAs)

    signed in the 1990s.

    However, both the issuing process and the

    terms of the agreements have evolved since

    the first and most generous IPP contracts

    were handed out by TNB. As a result, analysts

    Interconnection, existing and proposed

    1.Peninsular Malaysia Singapore

    (1986, 2 x 200 MW)

    2. Peninsular Malaysia Thailand

    z HVAC Bukit Ketri Sadao

    (1981, 85 MW)

    z HVDC Gurun Khlong Ngae

    (2001, 300 MW)

    z Rantau Panjang Sg Kolok

    (2015, 2nd 300 MW HVDC)

    3. Peninsular Malaysia Sarawak (2022)

    4. Peninsular Malaysia Sumatra

    (2018)

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    Regional profile: Malaysia

    Power Engineering InternationalJuly-August 2014

    say new IPPs now yield internal rates of return

    on average around 78 per cent, compared

    with the mid-teens for early deals.

    The government is also renegotiatingthe early IPP contract terms as they near

    expiration in 20152017, and new lower

    rates are expected to accompany lengthy

    contract extensions.

    However, according to some in the

    industry, only around 2250 MW of the

    4000 MW contracted out by the original six

    contract holders will be renegotiated.

    YTL has since withdrawn from the 4A

    project bid, but concern remains that

    other IPPs will be awarded in a less than

    transparent manner. Already the direct

    negotiation approach has been extended

    beyond coal and gas plants. Earlier this year,

    state developer 1Malaysia Development

    Bhd (1MDB) signed a 25-year PPA through

    direct negotiation with TNB, for power from a

    50 MW solar park in Kedah the largest in the

    country (see renewables box, page12).

    And in February, 1MDB (and Mitsui)

    won an estimated RM12 billion deal for the

    2000 MW coal-fired power plant Project 3B

    due onstream in 2019 after negotiations with

    government entities, following a competitive

    tender process involving five bidders.

    Early in the tender process, TNB had been

    the clear favourite, with Malakoff the other

    front-runner. YTL was the other unsuccessful

    bidder. 1MDB already owns Tanjong Energy, a

    75 per cent stake in Genting Sanyen Power

    (now known as Kuala Langat Power Plant or

    KLPP), and a 75 per cent stake in the coal-

    powered Jimah Energy.

    In 2011, the government increased the

    allowable percentage of foreign ownership

    in IPPs from 30 per cent to 49 per cent. The

    move encouraged 40 companies to bid forthe 4500 MW Prai power plant tender. Despite

    this, in October 2012 TNB was awarded an

    RM3 billion contract for the first 1000 MW

    1400 MW stage. In total there are about

    27 licensed IPPs operating in the country, with

    over 15 GW of capacity.

    More coal on the slate

    Gas supply interruptions are being made

    worse by fast-depleting domestic gas

    fields, leading to supply shortages. In a

    recent presentation TNB said that although

    combined-cycle gas turbines were the

    most competitive form of generation for

    baseload based on current domestic gas

    prices, as the gas price gradually moves

    towards the international market price, coal-

    fired plants are expected to take over as

    the cheapest option for baseload, with over

    60 per cent of generation expected to be

    from coal in 2019 before dropping back with

    [power] imports from Sarawak and nuclear.

    Malaysias rising appetite for coal comes

    as a number of other major Asian economies

    are seeking to increase reliance on imported

    coal, leading to growing competition for

    supplies and upward price pressure.

    Domestic power producers burn about

    23 million metric tonnes (mmt) of coal annually

    (all imported), and this is expected to rise to

    37 million mmt by 2020. By that year, coal-

    fired electricity is expected to make up42 per cent of Malaysias total generation

    capacity, compared to 33 per cent now.

    Malaysia buys about 70 per cent of its

    coal from Indonesia, with Australia and South

    Africa contributing most of the remainder

    all through TNB, the sole coal importer for the

    power sector. Many other regional consumers

    also buy from Indonesia, the worlds top

    thermal coal exporter with over 300 mmt

    annually. That figure is expected to jump by

    5060 mmt in 2014, but there are signs that

    Indonesian supply growth is slowing.

    Any policy change in Jakarta such

    as moves to increase royalties or a recent

    proposal to ban exports of low-grade coal

    from 2014 could hinder the security of future

    supplies.

    Some analysts have been advising TNB

    to secure overseas coal assets, as India

    and China have done by snapping up coal

    mines in Australia and Indonesia. TNB Coal

    International once owned a coal mine in

    Kalimantan, but ceased operations in 2007.

    Political risk

    Malaysia is fast moving towards developed

    nation status, both in terms of economic

    power and electricity consumption. It is also

    having to face the problems of maturity

    associated with declining domestic energy

    resources, reflected in rising fuel costs.

    Linking prices to fuel costs will help controlrising debt while maintaining capacity

    expansion, but public pressure will make any

    price hikes fraught with political risk.

    Eventually, if it is able to bring power prices

    into line with international energy prices,

    there is the option of a more competitive

    market or even part-privatization of TNB, but

    at this stage that looks some way off.

    Jeremy Bowden is a journalist focusing on

    energy matters.

    Visitwww.PowerEngineeringInt.comfor more informationi

    Gas-fired plants such as the Paka CCPP generate around 40 per cent of Malaysias energy

    Credit: Siemens

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    Since the 2011 earthquake that destroyed the Fukushima nuclear complex,Japans energy supply industry has been in crisis. Utilities are haemorrhagingcash on fossil fuel imports and expensive safety upgrades to an idle nuclear fleet,

    the economy is under pressure from high energy prices and the government isseemingly dragging its feet on decisive policy action. David Appleyardexploreshow the Japanese energy sector is responding to these challenges

    A NEW DAWN FORJAPANS POWERSECTOR

    Power Report: Japan

    www.PowerEngineeringInt.comPower Engineering InternationalJuly-August 2014

    Ultimately, Japans energy

    woes stem from its lack of

    any abundant domestic

    resources. The nation supplies

    significantly less than one

    fifth of its total primary energy

    demand from indigenous reserves.

    As a result, according to the US EnergyInformation Administration, Japan is the

    worlds largest liquefied natural gas (LNG)

    importer, consuming well over a third of the

    2012 total global supply. It is also the second

    largest coal importer and the third largest net

    oil importer.

    As an industrial economy, when faced

    with burgeoning energy imports the country

    unsurprisingly adopted an aggressive policy

    of civil nuclear power. Until 2011 Japan wasthe worlds third largest producer of nuclear

    power after the US and France, with some

    26 per cent of its electricity coming from

    the atom.

    However, all that changed almost three and

    a half years ago with the massive earthquake

    and subsequent tsunami that destroyed

    much of units 1-4 of the Fukushima Daiichi

    nuclear complex in March 2011. In the wake

    of the ensuing disaster, the countrys energysupply companies shut down almost all of

    their reactors. Indeed, with these shutdowns,

    Kepcos nuclear power plant in Oi, Fukui Prefecture, was ordered by the

    Fukui District court not to restart in May due to local protest

    Credit: KYODO

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    Power Report: Japan

    www.PowerEngineeringInt.com

    scheduled maintenance and rigorous new

    safety controls in place, all of Japans reactors

    were offline by May 2012. And, although two

    reactors (Kansai Electric Powers Ohi 3 and

    4) were returned to service in mid-2012, they

    were subsequently shut down at government

    request in September 2013. They have

    remained idle since.

    The cost of a nuclear-free Japan

    With well over 40 GW of nuclear capacity and

    48 reactors effectively gathering dust, Japans

    scramble to replace lost power inevitably

    ramped up thermal capacity, and with it

    imports of oil, coal and, primarily, LNG. This has

    had a range of impacts on Japanese energy

    providers and the wider economy.For example, the latest figures available

    from Japans Federation of Electric Power

    Companies (FEPC) reveal CO2 emissions for

    fiscal 2012 from electric power companies

    totalled 415 million t-CO2 at a collective

    intensity of 0.487 kgCO2/kWh. The

    Environmental Action Plan set out by the

    Japanese utility industry envisages a target

    of reducing CO2 emissions intensity by an

    average of approximately 20 per cent from the

    fiscal 1990 level. Unfortunately, even dumping

    270 million tonnes of emissions credits onto

    the market over five years has seen the

    average CO2emissions intensity for the sector

    decrease only 2.6 per cent from 1990 levels.

    This undoubtedly explains why in a

    statement to the UN Conference of the

    Parties (COP19) climate change discussions

    in Warsaw in November last year Nobuteru

    Ishihara, Japans Minister of the Environment,

    said that although the country had hit its

    target on emissions reduction for the first

    commitment period, as the next step, Japan

    has set a target to reduce emissions by

    3.8 per cent compared to the 2005 level in

    2020. This compares with a previous Kyoto

    commitment to a 25 per cent reduction on1990 emissions levels by 2020, to the outrage

    of the environmental movement.

    No doubt anticipating the outcry, Ishihara

    pointed out that the revised plan required

    Japan to improve its energy efficiency by

    20 per cent when it is already at the worlds top

    level and would see the country enhance

    development and demonstration of

    renewable energy-related technologies such

    as offshore wind power, geothermal power

    and rechargeable batteries. He concluded

    by saying: Japan reaffirms the goal to reduce

    emissions by 50 per cent at the global level

    and by 80 per cent in the developed world

    by 2050 absolutely none of which washed

    with the greens. Naoyuki Yamagishi, leader

    of the Climate and Energy Group for WWF

    Japan observed that the move could

    further accelerate the race to the bottom

    among other developed countries with their

    analysis showing that the latest emission data

    from 2011 show that Japans emissions are

    3.7 per cent above 1990 figures.

    A costly decision?

    Japans more immediate concerns are rather

    more related to its declining if not actuallyspiralling out of control economic outlook.

    International Energy Agency figures indicate

    that replacing the countrys nuclear fleet

    cost the countrys top ten utilities more than

    $30 billion in additional fuel import costs over

    the two years following the Fukushima disaster.

    Reuters reports that the cost of replacement

    fossil fuels is now almost $90 billion, while

    domestic media sources estimate that a

    further $1.6 trillion ($16 billion) has gone

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    Power Report: Japan

    www.PowerEngineeringInt.com

    on upgrades and safety enhancements

    to nuclear plants in order to meet the

    requirements of a stringent new regulatory

    regime. Reportedly, the countrys nuclear plant

    operating companies are sitting on losses

    approaching $50 billion.

    Furthermore, as natural gas, fuel oil and

    coal pours into the boilers of sorely taxed and

    often aging thermal plant, Japan managed

    to spend some $250 billion in total on fuel

    imports in 2012, a third of the countrys total

    imported goods costs. The Ministry of Economy,Trade and Industry (METI) has reportedly

    estimated that power costs would need to rise

    by some $37 billion per year a sizable chunk

    of Japans GDP for thermal to replace all of

    the countrys nuclear capacity. Prior to 2011,

    nuclear had been among Japans cheapest

    sources of electricity, but without it baseload

    power prices have inevitably risen, squeezing

    government, industries and commerce as well

    as consumers.

    This has cost an already weak Japanese

    economy dearly, and rising exports have so far

    failed to arrest the fall of the yen, nor balance

    a crushing trade deficit (estimated at some

    $70 billion) and the weight of soaring fuel

    costs.

    Perhaps more immediate still, a May 2014

    METI report on electricity supply-demandoutlook for this summer pulled no punches

    in setting out the countrys tenuous reserve

    capacity margin. Even with the effects of

    electricity saving taken into account, demand

    during the peak months of July and August is

    expected to top 51.5 GW, assuming normal

    temperatures, and could peak above 53 GW

    given a hot spell.

    Meanwhile, generation capacity is

    estimated to be a little above 55.8 GW in July,

    and likewise should top 56 GW in August,

    largely as a result of the commissioning of

    combined-cycle systems at LNG-fired Chiba

    and city gas-fired group 7 at Kashima, as

    well as an additional 400 MW variable speed

    pumped-storage unit at the hydroelectric

    plant at Kazunogawa. This unit began

    operating in June against an originally

    planned schedule of 2020.

    This gives a reserve margin of 4.9 per cent

    under high-temperature conditions, METI says,

    though its probably fair to say that just about

    every unit in the thermal fleet was orderedinto operation in order to fend off the summer

    onslaught. On 30 June, for instance, Tokyo

    Electric Power Co (Tepco) announced that it

    was preparing to crank up unit 1 of the heavy

    and crude oil-fired Kashima power station.

    Rated at 600 MW, this plant began commercial

    operations in 1971 and has previously been

    held in a planned long-term suspension.

    The government has further called upon

    consumers to conserve electricity between

    9:00 am and 8:00 pm on weekdays from 1

    July through 30 September, which they arguewill deliver a guideline power saving of some

    11.7 per cent.

    METI also requested that Kansai Electric

    Power Co (Kepco) and Kyushu Electric Power,

    where the supply and demand situation is

    expected to be particularly severe, increase

    Previously mothballed, the 600 MW Kashima oil-fired power planthas received a new gas turbine in preparation for restart

    Credit: TEPCO

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    the reserve margin to more than 240 MW in

    total so that the utilities will be able to secure

    the reserve rate of 3 per cent or more as a

    minimum requirement. METI subsequently

    confirmed that Kansai and Kyushu had

    boosted the reserve margin to 434 MW in total.

    As part of a series of measures, the

    government instigated full inspections of

    all 86 of the countrys thermal power plants

    in a bid to prevent unexpected shutdowns.

    They concluded: With the increase in

    Japans dependency on thermal power

    plants for electricity supply following the

    Great East Japan Earthquake, the frequency

    of unexpected shutdowns of such plants

    remains high, mainly due to the aging of the

    plants, which highlights the risks involved in thesupply-demand balance of electricity.

    METI had expressed particular concerns

    about 31 thermal plants, based on their age

    and problems that had occurred previously.

    They noted: The situation of the supply-

    demand balance of electricity is still expected

    to be much more severe this summer and

    significant uncertainty remains.

    The policy response

    With public sentiment towards nuclear power

    at an understandably low ebb a numberof subsequent nuclear safety scandals

    having rocked public confidence still further

    the government has been reluctant to give

    even the countrys most modern and safe

    nuclear installations the go-ahead to resume

    operations. Indeed, close to 20 plants have

    now made applications to power up and the

    government has so far continued to stall.

    According to the World Nuclear Association

    (WNA), back in July 2013 four utilities had

    already applied to restart 12 pressurized water

    reactors (PWR) at six sites, including Kansais

    Ohi units 3 and 4 and Kyushus Sendai 1 and 2,

    following exhaustive batteries of stress testing

    and, in some cases, the construction of giant

    sea walls to protect the plants against any

    future tsunami event.

    But, with the reality of the situation

    becoming clear, and with justified if pre-

    existing concerns over the security of energy

    supply finally spilling over into outright anxiety,

    the government cracked in April with Cabinet

    approval of a new 4th Basic Energy Plan.This proposal explicitly recognizes nuclear

    power, alongside hydro, geothermal and coal,

    as an important baseload power source.

    In a statement, Makoto Yagi, FEPC chairman

    and also president of Kepco, described

    the decision as highly significant, though

    according to Reuters the minister of Economy,

    Trade and Industry, Toshimitsu Motegi, told

    reporters after the meeting that the plan

    makes clear we will reduce reliance on

    nuclear power through a variety of measures.

    LNG was further designated as anintermediate resource between baseload

    and peaking oil, and capable of balancing

    renewables which were given the most

    policy focus, and are set to be accelerated to

    full introduction according to reports on the

    proposals.

    Alongside the new energy plan, the

    government is also proceeding with its strategy

    for full deregulation of the countrys energy

    market, which is due to take place in 2016,

    followed by separation between generation,

    transmission and distribution in 2018.

    The bill to revise the Electricity Business

    Act for full retail deregulation of the electric

    power system was enacted in June, though

    the FEPC noted that in spelling out the

    detail of the plans it is necessary to build a

    robust mechanism for ensuring that there is

    sufficient supply capacity to meet the national

    electricity demand in the future.

    In a statement, Yagi also called upon

    the government to improve the business

    environment to ensure that the nuclear powerbusiness can continue to operate stably

    over the long term even in an increasingly

    competitive environment.

    The outlook for renewables

    With METI minister Motegi highlighting the

    role of future renewable energy capacity and

    the government setting up a ministerial-level

    group to study promoting renewables further,

    the new Basic Energy Plan aims to exceed

    previous proposals, which had envisaged

    up to 20 per cent of power coming fromrenewables by 2030.

    Japan is now only just embarking on its

    programme of renewable feed-in tariffs (FiTs),

    with the 1 July, 2014 launch of the second-year

    initiatives under the Green Power Project by

    the Agency for Natural Resources and Energy

    Power Report: Japan

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    Power Report: Japan

    (ANRE). The FiT is supported by a surcharge on electricity prices, which

    from April 2014 to September 2014 is $0.05/kWh.

    Currently, METI figures give Japans renewable energy as accounting

    for just 2.2 per cent of total electricity generation. Nonetheless, there is

    evidence that interest in Japans renewable sector is growing.

    In June, GE Energy Financial Services (GE EFS) said that it is to invest

    in the 32 MW Kumenan solar photovoltaic (PV) power project, together

    with project developer Pacifico Energy. Financing was supported by a

    11 billion loan from The Bank of Tokyo-Mitsubishi UFJ and The Chugoku

    Bank Ltd. Additional financial details were not disclosed.

    Located in the prefecture of Okayama, Kumenan is expected to begin

    commercial operations in the first quarter of 2016. It will sell power to a

    regional utility through a 20-year power purchase agreement.

    David Nason, president and chief executive officer of GE EFS, noted:

    Our investment in Kumenan advances our global growth into new

    markets with a strong risk-return profile.

    On a somewhat larger scale, just days after the GE announcementPhotovolt Development Partners GmbH comprising Kyocera, Kyudenko,

    ORIX corporations and Mizuho Bank revealed that they have reached

    a basic agreement to investigate the possibility of operating a 430 MW

    solar power plant on the island of Ukujima, off Sasebo City in Nagasaki

    Prefecture.

    An investment of approximately 150 billion is envisaged to execute

    the scheme, which would generate an estimated 500 GWh per year.

    According to its backers, the goal is to see construction commence

    during the 2016 financial year. A 60 km undersea cable would connect

    Ukujima to Kyushu Island and the Kyushu Electric company for power

    supply under the national FiT programme, which pays around

    $0.37/kWh.Recent analysis from IHS highlights Japan as a key market in its

    forecast of a 15 GW global PV market in the final quarter of 2014, with just

    Japan and the UK responsible for 42 per cent of global installations in

    Q1. In fact, IHS predicts Japan as the worlds number two market in 2014,

    behind only China.

    Furthermore, Japan is also pushing its technical and research abilities,

    centred on the prefecture of Fukushima. In one example, it is aiming to

    become a new hub for solar research following the April opening of an

    Energy Institute in conjunction with Fraunhofer ISE, the European solar

    energy research institute. In other renewable sectors, Fukushima is also

    the location of one of Japans floating offshore wind research installations,

    with a pilot 2 MW turbine installed in 2013 and a pair of 7 MW machines

    planned.

    Although Japan has only around 40 MW of offshore wind capacity

    installed to date, there are reports that the government is planning to

    revise the FiT regime further, boosting support for offshore wind at the

    expense of solar. According to an advisory document submitted to the

    government by an expert panel, the FiT for offshore should be increased

    to around $0.35/kWh, with onshore unchanged at $0.21/kWh, for

    20 years. The solar tariff would reportedly fall to around $0.31/kWh under

    the same proposals.

    Energy sector outlook

    While renewable energy capacity in Japan is undoubtedly set to

    accelerate rapidly, starting as it has from a relatively small contribution, itwill inevitably take time to grow. This is particularly true if the government is

    to secure the support of the electorate, already labouring under rocketing

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    Power Report: Japan

    energy prices and roundly disenchanted with

    the apparent U-turn on a nuclear future for

    Japan.

    And what of Japans nuclear future?

    Although the WNA recently reported that

    the Nuclear Regulation Authority (NRA) is

    prioritizing six units for restart, with Kyushus

    Sendai units expected to come online first,

    followed by Kansais Takahama 3 and 4, the

    group acknowledges that the reactor restarts

    are facing significant implementation costs

    ranging from $700 million to $1 billion per unit,

    regardless of reactor size or age.

    Analysis from Reuters this year indicates

    that the high cost of upgrades, together with

    local opposition or more stringent regulations

    on seismic resilience, will see as many astwo thirds of the countrys reactors ultimately

    never resume operations. Mycle Schneider,

    an independent energy consultant, is quoted

    as saying: I think it is unavoidable that the

    Japanese utilities will write off most of their

    nuclear assets and move on. Given the slim

    realistic prospects for a major nuclear share,

    the challenge will be flexibility and the whole

    baseload concept flies out of the window.

    The government believes that, as the

    currently idling nuclear capacity resumes

    operations, the proportion of fossil fuel

    generation with diminish. If so, this line is

    somewhat belied by the investment that

    Japans corporate giants such as Mitsui and

    Mitsubishi are ploughing into LNG production

    capacity. There is also evidence of a concerted

    programme of thermal upgrades underway.

    An example comes from the February

    commissioning of another unit at the Kashima

    power station which has been remodelled

    to combined operation from single-cycle.

    Initially comprising three 268 MW units with a

    37.1 per cent thermal efficiency, each of the

    gas-fired units now produces 420 MW, adding

    around 460 MW to the total output of the

    plant. The upgrade also increased the thermalefficiency to about 57 per cent, owner Tepco

    says.

    Meanwhile, some estimates suggest coal

    capacity could increase by some 21 per cent

    to 47 GW by the early 2020s, and with good

    reason. In May, for example, planning for a

    500 MW integrated coal gasification

    combined-cycle (IGCC) project at Tokyo

    Electric Powers Hirono power station, again in

    Fukushima, moved ahead with the submission

    of its environmental impact assessment to the

    regulatory authorities.

    For the immediate future, Japans energy

    sector will likely become more diverse as

    pragmatism sees the most viable stations

    in the nuclear portfolio return to service and

    new or refurbished thermal capacity and

    renewables come online steadily to meet

    the shortfall. Short-term, that almost certainly

    signals volatility for Japans troubled energysector and its consumers. But a power-

    hungry market and high prices also flag an

    opportunity for a whole host of energy sector

    propositions, new and well-established alike.

    David Appleyard is a journalist focusing on

    the energy sector.

    Visitwww.PowerEngineeringInt.comfor more informationi

    For the immediate

    future, Japans energysector will likelybecome more diverse

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    South Korea is an energy-

    intensive country with a

    growing population, high urban

    population density and little

    available land. In the wake of

    a scandal involving falsified

    nuclear plant safety certificates, the nation

    aims to reduce its reliance on nuclear power

    to 29 per cent of its energy mix by 2035.

    Due to a lack of domestic resources,

    imported fuels currently meet around

    97 per cent of South Koreas energy demand.

    In 2013, the country was the worlds second-

    largest importer of liquefied natural gas

    (LNG), the fourth-largest coal importer, and

    the fifth-largest oil importer.

    In a move to clean up its energy mix,

    South Korea has had a green growth

    policy in place since 2008, with the goal

    of increasing its use of renewables to

    20 per cent of the generation mix by 2027.Among its renewables-friendly policies, the

    nation has feed-in tariffs (FiTs), a renewable

    heat obligation and a renewable portfolio

    standard.

    However, its terrain is hilly and thus not

    particularly well-suited for large solar or wind

    farms. In the past few years South Korea has

    shown a growing interest in fuel cell power,

    with a number of projects in the works.

    Enter US-based FuelCell Energy. In

    February the firms South Korean partner,

    independent power producer Posco Energy,

    completed the worlds largest fuel cell

    power plant, the 59 MW Gyeonggi Green

    Energy park in South Koreas Hwasung City,

    which uses FuelCell Energys technology.

    PEispoke with Tony Leo, FuelCell Energys vice

    president for applications and advanced

    technology development, and Kurt Goddard,

    vice president for investor relations, about

    Gyeonggi, stationary fuel cell power, research

    and development, market prospects and the

    firms plans for the future.

    How a fuel cell power plant works

    Fuel cells convert chemical energy from

    hydrogen-rich fuels into electrical power

    and heat in a low-emission electrochemical

    process.

    Similar to a battery, a fuel cell is comprised

    of many individual cells grouped together

    to form a so-called fuel cell stack. Each cell

    contains an anode, a cathode and an

    electrolyte later. When a hydrogen-rich fuel

    such as natural gas or biogas enters the fuel

    cell stack, it reacts electrochemically withthe ambient air (oxygen), producing electric

    current, heat and water. But differently from a

    battery, which has a fixed supply of energy

    and can be depleted, fuel cells can generate

    electricity as long as fuel is supplied.

    FuelCell Energys Direct Fuel Cell power

    plants are based on carbonate fuel cell

    technology, in which the electrolyte is made

    up of potassium and lithium carbonates.

    Carbonate fuel cells can generate hydrogen

    from multiple fuel sources in a process called

    internal reforming, which has been patented

    by FuelCell Energy. The company says this

    process offers a competitive edge because

    it allows readily available fuels to be used.

    Fuel cell energy

    Interest in fuel cell poweris growing in marketswhere large-scale cleanenergy developmentis desired but spaceis limited for solar orwind parks. The newest

    development is theworlds largest fuel cellpower park in HwasungCity, South Korea.Tildy Bayarspoke withFuelCell Energy, thecompany behind it

    The 59 MW Gyeonggi Green Energy Park in Hwasung City, South Korea is the worlds largest

    Credit: FuelCell Energy

    22 Power Engineering InternationalJuly-August 2014 www.PowerEngineeringInt.com

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    Fuel cell energy

    And because there is no fuel combustion,

    power production emits almost no NOx, SOx

    or particulate matter, the firm says.

    Inside the power plant is the fuel cellstack or, for multi-megawatt power plants,

    a module that contains multiple stacks. The

    incoming fuel is processed by the mechanical

    balance of plant


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