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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
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Contents
POWER ENGINEERING INTERNATIONAL
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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,
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Nearly 50 years ago, B&W designed and built the worlds first commercially operated
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2014 Babcock & Wilcox Power Generation Group, Inc. All rights reserved.
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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
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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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13/76www.PowerEngineeringInt.com 11Power Engineering InternationalJuly-August 2014
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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14/7612 www.PowerEngineeringInt.comPower Engineering InternationalJuly-August 2014
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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18/7616
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
www.rs-seliger.de
safely
Connect quickly
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22/7620 www.PowerEngineeringInt.comPower Engineering InternationalJuly-August 2014
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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23/76www.PowerEngineeringInt.com 21Power Engineering InternationalJuly-August 2014
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
Fuel cell
power scales up
Fuel cell
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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