Powerinsider vol6 issue4

A S I A ’ S L E A D I N G P O W E R R E P O R T

VOLUME 6 ISSUE 4

FEATURES INSIDE: Japans Hydrogen highway | SCADA Security | Offshore Wind | AsiaWhat’s changed in Hydropower development? | Iran nuclear talks

| Stochastic Optimisation for Simulation of Electricity Markets

ASIA’SHIGHWAYHYDROGEN

Editors NoteWelcome to another edition of Pimagazine Asia. 2015 has moved forward quicker than ever and so has the developments in the Asian energy market. The nuclear debate rages on throughout the region, safety and public opinion being the main topics. Despite the strength and efficiency of Nuclear anywhere in the World, the public along with governments is still scared despite the massive amounts of electricity it can provide. Will public opinion ever change? What else is there to generate massive amounts of electricity on a scale that can be matched by Nuclear? In this edition we revisit some of these issues. As usual, we have tried to cover as many topics as possible that are pertinent to the market place, and we have been undergoing many changes here at Power Insider, changes for the better. A more focused team of professionals, better design, a market leading social media network bringing the very latest news and views from the region. As we go to press, the website is under going some changes, so if your not already subscribed I suggest you log on right away and get yourself registered.

Should I need to remind you, our twitter following is growing day by day, we use this platform as soon as new news is published, so again, please follow us @pimagazineasia Any news, breaking stories or promotions you have planned, please contact me directly [email protected] for your continued support and we look forward to hearing from you

Sean Stinchcombe,

Editor

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Inside This Issue

Features

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20

Japans Nuclear Decision

Japans Hydrogen highway

SCADA Security

Offshore Wind Asia

FG WILSON’S model for expansion

NewsThe latest headlines

Upcoming Events

8

20

24

28

Regulars

08

32

Contents

04 | POWER INSIDER VOLUME 6 ISSUE 4

Anil SardanaTata Power

08

Interviews & Opinions

34

36 42Iran nuclear talks

High- or Medium-Speed Generator Sets:Which Is Right for Your Application?

Stochastic Optimisation for Simulation of Electricity Markets

06

46

38


Regulars

News from

around AsiaHere is a brief summary of the most recent big stories from in and around Asia. Please ensure you are a regular subscriber to our weekly newsletter to stay ahead of breaking news from the region. Keep up to date by following us on Twitter @pimagazineasia

Largest solar plant in Central Asiain spring 2019 “Uzbekenergo” plans to build the first heliostation in Central Asia with the capacity of 100 MW and output of up to 200 million kWh of electricity per year. The project worth USD 310 million will be funded by Asian Development Bank, Fund for Reconstruction and Development of Uzbekistan, and “Uzbekenergo”.

Alstom wins $57 Million China Hydro contactAlstom was awarded a contract worth €57 million1 by The Hainan Pumped Storage Power Generation Co. Ltd. to equip Hainan Province’s first pumped storage power station. Alstom will provide three 200 MW units – pump turbine, motor generator with other key equipment – to the 600 MW new plant. The first unit is due to enter commercial operation on Dec, 2017.

Four Asian countries to sign energy deal Kyrgyzstan, Tajikistan, Afghanistan and Pakistan will sign an agreement on the electric power line project CASA-1000 at the end of July, 2015.Representatives from four countries discussed the project with the World Bank, IDB, USAID, IFC, DFID, EBRD and the Intergovernmental Council Secre-tariat at the meeting in Kazakhstan on June 13.The CASA-1000 electric power line project will supply electricity from Kyr-gyzstan and Tajikistan to Afghanistan and Pakistan.The CASA-1000 project with total esti-mated cost of $997 million will enable to supply 1,300 megawatt of existing summertime hydropower surplus from Kyrgyzstan and Tajikistan in Central Asia to Afghanistan and Pakistan in South Asia.

Thailand Thailand shining bright in Asia Come December, Thailand will have more solar power capacity than all of Southeast Asia combined as record sums of money are poured into the sector in the hopes of nurturing a new energy source to help drive the region’s second-biggest economy.Thailand has been shifting from natural gas with once-plentiful reserves are expected to run out within a decade, forcing it to rely on imported fuel more than any other country in the region except Singapore. A plunge in solar-component costs and subsidized tariffs has also helped feed the country’s solar boom.About 1,200-1,500 megawatts of solar capacity will be connected to the grid this year, requiring as much as 90 billion baht of investment, Pichai Tinsuntisook, chairman of the Federation of Thai Industries’ renewable energy division.


News Desk

Singapore Singapore needs Nuclear to cut emmissions In the next 50 years, Singapore can either choose to continue using natural gas to meet most of its energy needs, or move to nuclear power, said a panellist at an Institute of Policy Studies confer-ence on.Nuclear power is the option if Singapore wants to seriously address climate change and cut carbon emissions, said futurist and business strategist Peter Schwartz, who is also on Singapore’s Research, Innovation and Enterprise Council.“You’re going to continue to need electricity, and renewables will be in-sufficient. You’re either going to have to continue using natural gas or move to nuclear power,” said Mr Schwartz at the session on energy, the environment and the resilience of cities at the Singapore at 50: What Lies Ahead conference

Bangladesh Bangladesh powers ahead on offgrid Solar More than the technology it is the advocacy that allowed the Bright Green Energy Foundation (BGEF) to install more than 145,000 solar home systems (SHS) that benefit eight million rural people in Bang-ladesh. SHS units including solar panels, battery and regulator are not displayed in showrooms. Instead BGEF has been directly promoting the benefits of its environment-friendly technology in the field since 2010, when it was registered. Dipal Chandra Barua, the founder of BGEF, puts his faith in ru-ral-based Green Technology Centers (GTC) managed by women trained as technicians to handle free after sales service that keep the units running for the first five years after installation. Barua says the program provides job opportunities for women, be-sides ensuring affordable off-grid power in rural Bangladesh. “Only if it is cheap and efficient will it work for the poor who need it most. The strategy is responsible for the popularity of the SHS in Bangladesh.

Philippines P95B for Hydro in PhilippinesRenewable energy company Euro Hydro Power (Asia) Holdings Inc. (EPHI) is investing P95 billion for the establishment of hydropower projects in Mindanao.Alan Uy, president and chief executive officer of the company, said Tuesday during the ground-breaking ceremony of its New Bataan mini hydro plant that these projects will have combined capacity of 571 megawatts. The plants, he added, are expected to be set up in the next five years.This, he said, developed after noting the need to augment the power supply in Mindanao. To pursue its plans, EPHI will tap 129 rivers in the island.“Five years ago, we dreamed to come up with a project that will benefit the community that is affordable, reliable and environ-ment-friendly project anchored in the problem to address the power supply in Mindanao,” he said.The first to be constructed was its P490-million mini hydro plant in New Bataan, which has a capacity of 2.4 MW

Korea Vestas wins 26mw order Vestas said the order was made by “one of the largest South Korean conglomer-ates, which has been active in the wind power industry as a project developer and EPC contractor”. Further details about the project and the customer have been kept private at the customer’s request, Vestas added.The manufacturer could confirm it will supply 13 V100-2MW projects to the project, located in the Gangwon Prov-ince, to the north-east of the country.Delivery is due in the second half of 2016 and Vestas will service the ma-chines for ten years.It is the first time Vestas will deliver the V100 to a South Korean project, adding to the 226MW it has already installed there.

JAPANS NUCLEAR

DECISION

Feature

Japan’s energy situation and international dependence

Japan’s shortage of minerals and energy was a powerful influence on its politics and history in the 20th century. Today it depends on imports for over 90% of its primary energy needs. As it recovered from World War II and rapidly expanded its industrial base it was dependent on fossil fuel imports, particularly oil from the Middle East (oil fuelled 66% of the electricity in 1974). This geographical and commodity vulnerability became critical due to the oil shock in 1973. At this time, Japan already had a growing nuclear industry, with five operating reactors. Re-evaluation of domestic energy policy resulted in diversification and in particular, a major nuclear construction program. A high priority was given to reducing the country’s dependence on oil imports. A closed fuel cycle was adopted to gain maximum benefit from imported uranium.


Despite being the only country to have suffered the devastating effects of nuclear weapons in wartime, with over 100,000 deaths, Japan embraced the peaceful use of nuclear technology to provide a substantial portion of its electricity. However, following the tsunami which killed 19,000 people and which triggered the Fukushima nuclear accident (which killed no-one), public sentiment shifted markedly so that there were wide public pro-tests calling for nuclear power to be abandoned. The balance between this populist sentiment and the continua-tion of reliable and affordable electricity supplies is being worked out politically.

Nuclear power has been expect-ed to play an even bigger role in Japan’s future. In the context of the Ministry of Economy, Trade and In-dustry (METI) Cool Earth 50 energy innovative technology plan in 2008, the Japan Atomic Energy Agency (JAEA) modeled a 54% reduction in CO2 emissions (from 2000 levels) by 2050 leading on to a 90% reduction by 2100. This would lead to nuclear energy contributing about 60% of primary energy in 2100 (compared with 10% in 2008), 10% from re-newables (from 5%) and 30% fossil fuels (from 85%). This would mean that nuclear contributed 51% of the emission reduction: 38% from power generation and 13% from hydrogen production and process heat.

In June 2010 METI resolved to increase energy self-sufficiency to 70% by 2030, for both energy se-curity and CO2 emission reduction. It envisaged deepening strategic relationships with energy-producing countries. Nuclear power would play a big part in implementing the plan, and new reactors would be required as well as achieving 90% capacity factor across all plants.

However, following the Fukushima accident, in October 2011 the gov-ernment sought to greatly reduce the role of nuclear power. This appears to have been a significant factor in them losing office in 2012 elections (see later section). The

new government in 2014 adopted the 4th Basic (or Strategic) Energy Plan, with 20-year perspective and declaring that nuclear energy is a key base-load power source and would continue to be utilized safely to achieve stable and affordable energy supply and to combat global warming.

Early in 2011, nuclear energy accounted for almost 30% of the country’s total electricity production (29% in 2009), from 47.5 GWe of capacity (net) to March 2011, and 44.6 GWe (net) from then. There were plans to increase this to 41% by 2017, and 50% by 2030.

IEA figures indicate that in 2013 Ja-pan generated 1059 TWh gross, 338 TWh from coal, 408 TWh from gas (up from 300 TWh in 2010), 9 TWh from nuclear (cf 288 TWh in 2010), 161 TWh from oil (up from 94 TWh in 2010), and 84 TWh from hydro. The country’s nuclear capacity was progressively shut following the March 2011 Fukushima accident. Renewables contribution in 2013 was small: solar 10 TWh, wind 5 TWh, geothermal 2.6 TWh, biomass & waste 41 TWh. Final consumption in 2010 was about 1000 billion kWh, or about 7870 kWh per capita. This dropped to 923 TWh, or 7200 kWh/capita in 2012.

Capacity (IEA figures) at end of 2012 was 295 GWe, this being 46 GWe nuclear, 45 GWe hydro, 36 GWe coal,

47 GWe gas, 41 GWe oil, 16 GWe oil or coal, 50.6 GWe autoproducers’ ‘combustible fuels’, 6.6 GWe solar, 2.5 GWe wind and 0.5 GWe geothermal. In response to nuclear difficulties, coal capacity is planned to increase 21% to 47 GWe by early 2020s.

The electricity market is due to be deregulated in 2016, with legal sep-aration in 2018 between generation, transmission, and distribution.

Development of nuclear program & policy 1950 to 2005

Japan started its nuclear research pro-gram in 1954, with ¥230 million being budgeted for nuclear energy. The Atomic Energy Basic Law, which strictly limits the use of nuclear technology to peaceful purposes, was passed in 1955. The law promoted three principles – democratic methods, independent management, and transparency – is the basis of nuclear research activities, as well as promoting international co-operation. Inauguration of the Atomic Energy Commission (AEC) in 1956 promoted nuclear power devel-opment and utilization. Several other nuclear energy-related organizations were also established in 1956 under this law: the Nuclear Safety Commis-sion (NSC), the Science & Technology Agency; Japan Atomic Energy Research Institute (JAERI) and the Atomic Fuel Corporation (renamed PNC in 1967 – see below).

FEATURE: Japans Nuclear Decision


Feature

The first reactor to produce electric-ity in Japan was a prototype boiling water reactor: the Japan Power Demonstration Reactor (JPDR), which ran from 1963 to 1976 and provided a large amount of information for later commercial reactors. It also later provided the test bed for reactor decommissioning.

Japan imported its first commercial nuclear power reactor from the UK, Tokai 1 – a 160 MWe gas-cooled (Mag-nox) reactor built by GEC. It began operating in July 1966 and continued until March 1998.

After this unit was completed, only light water reactors (LWRs) utilizing enriched uranium – either boiling water reactors (BWRs) or pressur-ized water reactors (PWRs) – have been constructed. In 1970, the first three such reactors were completed and began commercial operation. There followed a period in which Japanese utilities purchased designs from US vendors and built them with the co-operation of Japanese companies, who would then receive a license to build similar plants in Japan. Companies such as Hitachi Co Ltd, Toshiba Co Ltd and Mitsubi-shi Heavy Industry Co Ltd developed the capacity to design and construct LWRs by themselves. By the end of the 1970s the Japanese industry had largely established its own domestic nuclear power production capacity and today it exports to other east Asian countries and is involved in the development of new reactor designs likely to be used in Europe.Due to reliability problems with the

earliest reactors they required long maintenance outages, with the av-erage capacity factor averaging 46% over 1975-77 (by 2001, the average capacity factor had reached 79%). In 1975, the Ministry of International Trade and Industry (MITI) and the nuclear power industry launched the LWR Improvement & Stand-

ardization Program. This aimed, by 1985, to standardize LWR designs in three phases. In phases 1 and 2, the existing BWR and PWR designs were to be modified to improve their operation and maintenance. The third phase of the program involved increasing the reactor size to 1300-1400 MWe and making significant changes to the designs. These were to be the Advanced BWR (ABWR) and the Advanced PWR (APWR).

A major research and fuel cycle estab-lishment through to the late 1990s was the Power Reactor and Nuclear Fuel De-velopment Corporation, better known as PNC. Its activities ranged very widely, from uranium exploration in Australia to disposal of high-level wastes. After two accidents and PNC’s unsatisfactory response to them the government in 1998 reconstituted PNC as the leaner Japan Nuclear Cycle Development Institute (JNC), whose brief was to focus on fast breeder reactor development, re-processing high-burnup fuel, mixed-ox-ide (MOX) fuel fabrication and high-level waste disposal.

A merger of JNC and JAERI in 2005 cre-ated the Japan Atomic Energy Agency (JAEA) under the Ministry of Education, Culture, Sports, Science & Technology

(MEXT). JAEA is now a major integrated nuclear R&D organization.

A peculiarity of Japan’s electricity grids is that on the main island, Honshu, the northeastern half including Tokyo is 50 Hz, served by Tepco (and Tohoku), the southwestern half including Nago-ya, Kyoto and Osaka is 60 Hz, served by Chubu (with Kansai & Hokuriku), and there is only 1 GWe of frequency converters connecting them. (Japc has plants in both areas, which are separated by the Itoigawa River.) This frequency difference arises from original equipment coming from Germany and USA respectively. The interconnection is being increased to 2.1 GWe, funded by the utilities. Early in 2013 it was announced that METI will establish a new body to balance electricity supply and demand in wide areas across Japan, as early as 2015. The new body will manage grid and transmission facilities, which are cur-rently owned and managed by utility companies.

More recent energy policy 2002-2011: Focus on nuclearJapan’s energy policy has been driven by considerations of energy security and the need to minimize depend-ence on current imports. The main elements regarding nuclear power were:n Continue to have nuclear power

as a major element of electricity production.

n Recycle uranium and plutonium from used fuel, initially in LWRs, and have reprocessing domesti-cally.

n Steadily develop fast breeder reac-tors in order to improve uranium utilization dramatically.

n Promote nuclear energy to the public, emphasizing safety and non-proliferation.

In March 2002 the Japanese govern-ment announced that it would rely heavily on nuclear energy to achieve greenhouse gas emission reduction


Early in 2011, nuclear energy accounted for almost 30% of the country’s total

electricity production (29% in 2009), from 47.5 GWe of capacity (net) to March 2011, and 44.6 GWe (net) from then. There were plans to increase this to 41% by 2017, and

50% by 2030.

goals set by the Kyoto Protocol. Cabinet endorsed a 10-year energy plan, submitted in July 2001 to the Minister of Economy Trade & Indus-try (METI). It called for an increase in nuclear power generation by about 30 percent (13,000 MWe), with the expectation that utilities would have up to 12 new nuclear plants operating by 2011. In fact only five (5358 MWe net) came on line in that decade.

In June 2002, a new Energy Policy Law set out the basic principles of energy security and stable supply, giving greater authority to the gov-ernment in establishing the energy infrastructure for economic growth. It also promoted greater efficiency in consumption, a further move away from dependence on fossil fuels, and market liberalization.

These developments, despite some scandal in 2002 connected with records of equipment inspections at nuclear power plants, paved the way for an increased role for nuclear energy.In 2004 Japan’s Atomic Industrial Forum (JAIF) released a report on the future prospects for nuclear power in the country. It brought together a number of considerations including 60% reduction in carbon dioxide emissions and 20% popu-lation reduction but with constant GDP. Projected nuclear generating capacity in 2050 was 90 GWe. This would mean doubling both nuclear generating capacity and nuclear share to about 60% of total power produced. In addition, some 20 GW (thermal) of nuclear heat would be utilized for hydrogen production. Hydrogen is expected to supply 10% of consumed energy in 2050 and 70% of this would come from nuclear plants.In July 2005 the Atomic Energy Commission reaffirmed policy di-rections for nuclear power in Japan, while confirming that the immediate focus would be on LWRs. The main elements were that a “30-40% share or more” should be the target for nuclear power in total generation

after 2030, including replacement of current plants with advanced light water reactors. Fast breeder reactors would be introduced commercially, but not until about 2050. Used fuel would be reprocessed domestically to recover fissile material for use in MOX fuel. Disposal of high-level wastes would be addressed after 2010.

In May 2006 the ruling Liberal Dem-ocratic Party urged the government to accelerate development of fast breeder reactors (FBRs), calling this “a basic national technology”.* It proposed increased budget, better coordination in moving from R&D to verification and implementation, plus international cooperation. Japan was already playing a leading role in the Generation IV initiative, with focus on sodium-cooled FBRs, though the 280 MWe (gross) Monju prototype FBR remained shut down until May 2010, and then shut down again a few months later, with prospective restart repeatedly postponed.

METI’s 2010 electricity supply plan showed nuclear capacity growing by 12.94 GWe by 2019, and the share of supply growing from 2007’s depressed 262 TWh (25.4%) to about 455 TWh (41%) in 2019. This is now unachievable. A regular AEC Policy

Planning Council review ceased in 2011 and the Council was disband-ed in 2012.

In March 2011 units 1-4 of the Fuk-ushima Daiichi plant were seriously damaged in a major accident, hence written off for decommissioning, which removed 2719 MWe net from Tepco’s – and the country’s – system. In 2014 units 5&6 joined them in being decommissioned.

At present Japan has 48 reactors totaling 42,569 MWe (net) opera-tional, with two (2756 MWe) under construction, one in indefinite shut-down (Monju), and 12 (16,532 MWe) planned. In the light of mid-2012 policy options Monju is considered more relevant to the R&D section of the Japan Fuel Cycle paper. In 2010 the first of those power reactors then operating reached their 40-year mark (at which stage there was a presumption that some might close down). Some license exten-sions have been approved.

Post-Fukushima energy policy changes, 2011 on

In July 2011 an Energy & Environment Council (Enecan or EEC) was set up by the Democratic Party of Japan (DPJ) cabinet office as part of the National



Feature


Policy Unit to recommend on Japan’s energy future to 2050.* It was chaired by the Minister for National Policy to focus on future dependence on nuclear power. Its initial review was to recommend that nuclear power’s contribution to electricity be targeted at 0%, 15%, or 20-25% for the medium term – a 36% option was dropped.

Meanwhile major Japanese companies such as Mitsui and Mitsubishi started investing heavily in LNG production capacity from Australia and elsewhere eg a 15% stake in Woodside’s Browse LNG project for $2 billion. METI estimat-ed that power generation costs would rise by over JPY 3 trillion ($37 billion) per year, an equivalent of about 0.7 percent of gross domestic product, if utilities replaced nuclear energy with thermal power generation. In February 2012 METI’s minister said that electric-ity costs would need to increase up to 15% while the nuclear plants remained shut.

In July 2012 feed-in tariffs (FiTs) were introduced for solar and wind power. The solar FiT was ¥42/kWh (41 cents US) for ten years, which was reduced in April 2013 to ¥38 for small systems, and to be reduced again in April 2014 to ¥37/kWh residential and ¥32/kWh for systems over 10 kW. The wind FiT in 2012 was ¥23.1/kWh for units above 20 kW, and ¥57.75 for smaller units (of which none had been approved).

Enecan’s “Innovative Energy and Environment Strategy” was released in September 2012, recommending a phase-out of nuclear power by 2040. In the short term, reactors currently operable but shut down would be allowed to restart once they gained permission from the incoming Nu-clear Regulation Authority (NRA), but a 40-year operating limit would be imposed.

Reprocessing of used fuel would continue. Enecan promised a “green energy policy framework” is promised by the end of 2012, focused on burning imported gas (LNG) and coal, along with expand-ed use of intermittent renewables.

This provoked a strong and wide reaction from industry, with a consensus that 20-25% nuclear was necessary to avoid very severe economic effects, not to mention high domestic electricity prices. In the past year increased fossil fuel imports had been a major contrib-utor to Japan’s record trade deficit of JPY 2.5 trillion ($31.78 billion) in the first half of 2012. The Keidan-ren (Japan Business Federation) said the Enecan phase-out policy was irresponsible, as did the lead-ership of the Liberal Democratic Party (LDP).Four days after indicating general approval of the Enecan plan, the DPJ cabinet backed away from it, relegat-ing it as “a reference document” and the prime minister explained that flexibility was important in consider-ing energy policy. The timeline was dropped. Reprocessing used nuclear fuel would continue and there would be no impediment to continuing construction of two nuclear plants – Shimane 3 and Ohma 1. A new Basic Energy Plan would be decided after further deliberation and consultation, especially with municipalities hosting nuclear plants.

However, at the end of 2012 the new Liberal Democratic Party (LDP) gov-ernment promptly abolished Enecan, along with the National Policy Insti-tute, so that METI’s Advisory Commit-tee for National Resources and Energy became responsible for formulating energy plans, while MoE’s Central En-vironment Council focused on climate change matters. The new LDP prime minister ordered a ‘zero-based’ review of energy policies.

In December 2012, after a decisive victory in national elections for the Di-et’s lower house, with 294 out of 480 seats, the LDP took a more positive view of restarting idled nuclear power plants than its predecessor, which had seemed indifferent to electricity shortages and massive LNG and other fossil fuel import costs. (The DPJ won only 57 seats, down from 267) The new government said it would take responsibility for allowing reactor

restarts after the Nuclear Regulation Authority issued new safety standards and confirmed the safety of individual units. After abolishing Enecan it also said that abandoning reprocessing of used fuel was ruled out. Construction of Shimane 3 and Ohma 1 was to con-tinue, and the construction of up to 12 further units could be approved.

In July 2013, elections for the Diet’s upper house gave the LDP 115 seats out of 242. Its coalition partner and another pro-nuclear party won 29 seats. This consolidated the LDP posi-tion and role in reviving the economy, including restoring power supplies. The DPJ with its policy of abandoning nuclear power by 2040 won only 59 seats. The LDP won a seat in every constituency with a nuclear power plant. In Fukushima prefecture the LDP candidate polled more than twice as many votes as the DPJ candidate. In Fukui prefecture, where Kansai Electric Power Co. has 11 units, Japan Atom-ic Power Co. has two units, and the government has the Monju prototype breeder reactor, an LDP candidate beat the DPJ contender, 237,000 votes to 56,000.

In December 2013 a draft of the new 4th Basic (or Strategic) Energy Plan was issued, with 20-year perspective, and declaring the period to 2020 as a special stage to reform energy systems. It said that nuclear energy is a key base-load power source and would continue to be utilized safely to achieve stable and affordable energy supply and to combat global warm-ing. However, the degree of depend-ence on it would be reduced as much as possible consistent with those goals and the maintenance of nuclear technology and expertise. Reactors will be restarted as NRA confirms their safety. Used fuel will receive more attention, and the nuclear fuel cycle will be promoted, including R&D on fast reactors.

In February 2014 METI presented the proposed new 4th Basic Energy Plan to government, which adopt-ed it in April. It lists nuclear as an important one of four base-load


options. Two of the others – hydro and geothermal – are limited, and the other is coal, but though cheap, its pollution works against emissions goals and represents a geopolitical risk. Natural gas/LNG was desig-nated as intermediate between low-cost base-load and peaking oil, and capable of complementing the intermittency of renewables. Renewables were given the most space and will be “accelerated to full introduction” though without targets: solar is seen as useful to supply power during peak demand; large-scale deployment of wind could produce significant power, but this would come from northern areas and would require balancing with as-yet undeveloped storage systems. Nuclear power is present-ed as a quasi-domestic source that gives stable power at low operation-al cost and with low greenhouse gas profile. Nuclear power is an “impor-tant power source that supports the stability of the energy supply and demand structure,” it said.

Later, in October 2014, at least seven of the ten major utilities limited the access of renewable energy to their grids due to potential overloads. The government is addressing the problem by reducing the 2012 high fixed-price feed-in tariffs (FITs).

In January 2015 the Institute of Ener-gy Economics, Japan (IEEJ) released a report looking at four electricity scenarios in 2030 and their impli-cations, for about 1150 TWh (less than 10% up on 2013). They ranged from zero nuclear up to 30% nuclear contribution, with power costs for zero being 42% higher than the 30% nuclear scenario (21.0 vs 14.8 JPY/kWh), and GDP being JPY 10 trillion less. The other metric of obvious significance is energy self-sufficiency, only 7% in 2013, and ranging from 19% in zero-nuclear scenario to 28% in the 30% nuclear one (considering nuclear as quasi-indigenous, as it has been). LNG imports in the zero nuclear scenario are almost as high as in 2013, but reduce 20% from 2013 level in the 30% nuclear one. Reliance

on renewables is 35% in zero-nuclear but only 20% in high-nuclear scenar-io, compared with 13.5% in 2013.

2011-14 Electricity Supply Constraints and Changes and Power Plant SituationThe chairman of Japan’s Federation of Electric Power Companies (FEPC) warned in May 2011 that the organi-zation expected the supply-demand balance in summer 2011 would be very tight in the east coast areas served by Tokyo Electric Power Co (Tepco), Tohoku Electric Power Co (both 50 Hz) and Chubu Electric Power Co (60 Hz). He said that all the utilities on the west coast of Japan will cooperate to transfer electricity to the east coast, noting the significant role of nuclear energy in ensuring a stable power supply*. He stressed the im-portance of the government allowing those reactors currently shut down for mandated periodic inspections to be able to return to service as soon as possible. In particular, the government should help local authorities and residents understand the importance of restarting those reactors currently shut for periodic inspections.

Under Japanese regulations, the default period between inspections

at reactors is 13 months, but chang-es made in 2009 allow operators to apply to increase this to 18 months. Subject to approval, a five-year intro-ductory period would follow, after which the limit could be raised to 24 months between inspections – more in line with international practices.

The median capacity factor for Japanese nuclear plants is about 70% – compared with over 90% for the best performers worldwide – with the country’s inspection requirements a contributing factor to this differ-ence. Most other countries conduct regulatory checks so that utilities can operate their power plants almost all of the time that refueling or major maintenance is not taking place.

Decline in operating capacity

By mid-May 2011, only 17 out of Japan’s 50 remaining nuclear power reactors (apart from Monju and writ-ten-off Fukushima Daiichi 1-4) were in operation. This represented 15,493 MWe, or 35%, of the total remaining nuclear generating capacity of 44,396 MWe. Twenty units, with a combined capacity of 17,705 MWe (40% of total nuclear capacity) were not operating as they had been shut for period-


Feature


ic inspections, while another two units (1700 MWe) had been shut for unplanned inspections or equipment replacement. Units 4&5 at Chubu Electric’s Hamaoka plant were shut down at the government’s request in May 2011 to increase their resistance to tsunamis.

The other nine units – with a com-bined capacity of 8826 MWe (20% of total nuclear capacity) – were shut down during the 11 March earth-quake and have not restarted. These nine reactors – units 1 and 3 of the Onagawa plant, unit 2 of the Tokai plant, all four units at the Fukushima Daini plant and units 5&6 of Fukushi-ma Daiichi – are in cold shutdown and were progressively joined by others as maintenance outages came due. (Four units – Fukushima Daiichi units 1 to 4, total 2719 MWe – were written off and are to be decommissioned. Fukushima Daiichi units 5&6 have joined them in being decommissioned.)After May 2011 the number of operat-ing reactors steadily dwindled to zero.In the summer of 2011 stringent energy conservation measures were applied leading to a 12% reduction in power consumption (relative to 2010) in August, and more significantly, a reduction in peak demand reaching 18%, exceeding the government target of 15%.

Tsunami defences

Chubu Electric Power Co is under-taking increased tsunami and flood-ing protection for the Hamaoka nu-clear power plant, which was closed in response to an extraordinary request from the Japanese prime minister. The plant is in a region of high seismic activity, where a large undersea earthquake can be expect-ed within the next 30 years. Behind a row of sand dunes measuring be-tween 10 and 15 meters high above sea level, the company has erected a new 1.6 km breakwater wall reach-ing 22 meters above sea level. On the main plant site, measures will mitigate general serious flooding in case a tsunami overwhelms the breakwater. They include the water-

proofing of diesel generator rooms and seawater pumps, as well as the installation of pumps in the build-ing basements. Grid connections are to be doubled up, with another set of diesel generators complete with long-term fuel supply installed on ground behind the main plant buildings about 25 meters above sea level. Spare parts for seawater pumps will be kept in a hardened building and heavy earthmoving capability will be maintained.Hokkaido is building a seawall 1.25 km long and up to 6.5 m high at its Tomari site, which is 10 m above sea level.

In April 2012 Kansai announced that it would spend more than JPY 200 billion ($2.5 billion) over four years on defenses against earthquakes and tsunamis at its eleven reactors. Kansai submitted the plans to the government as a precondition for restarting its two Ohi reactors in western Japan.

Stress Tests 2011-12

Nuclear risk and safety reassessments – ‘stress tests’ – along the lines of those in Europe were carried out in 2011. After some confusion the government decided that these would be in two stages.In the primary stage, plant opera-tors assessed whether main safety

systems could be damaged or disa-bled by natural disasters beyond the plant design basis. This identi-fied the sheer magnitude of events that could cause damage to nucle-ar fuel, as well as any weak points in reactor design. The ‘tests’ started from an extreme plant condition, such as operating at full power while used fuel ponds are full. From there, a range of accident progressions such as earthquakes, tsunamis and loss of off-site power were computer simulated using event trees, addressing the effec-tiveness of available protective measures as problems developed. Stage 1 tests had to be approved before reactors are restarted.

In the second stage even more severe events were considered, with a focus on identifying ‘cliff-edge effects’ – points in a potential accident sequence beyond which it would be impossible to avoid a serious acci-dent. This stage included the effects of simultaneous natural disasters. A particular focus was the fundamental safety systems that were disabled by the tsunami of 11 March, leading to the Fukushima accident: back-up die-sel generators and seawater pumps that provide the ultimate heat sink for a power plant.The stage 1 stress test results for indi-vidual plants were considered first by

Status of restart applications and safety reviews

Type Utility Reactors Applied Final plan submitted Notes

PWR Kyushu Sendai 1&2 July 2013 Oct 2014 NRA approval, making final checks

Kansai Takahama 3&4 July 2013 Oct 2014 NRA approval, making

final checks

Kansai Ohi 3&4 July 2013 Quake & tsunami scenarios

Hokkaido Tomari 1-3 July 2013 Quake scenarios pending

Shikoku Ikata 3 July 2013 Quake & tsunami scenarios

Kyushu Genkai 3&4 July 2013 Quake & tsunami

scenarios

ABWR Tepco Kashiwazaki Kariwa 6&7 Sept 2013 NRA doing inspection

J-Power Ohma 1 Dec 2014 NRA reviewingBWR Chugoku Shimane 2 Dec 2013

Tohoku Onagawa 2 Dec 2013 Chubu Hamaoka 4 Feb 2014 J-Power Tokai 2 May 2014 Tohoku Higashidori 1 June 2014 Question re faults nearby Hokuriku Shika 2 August 2014

NISA and then by the Nuclear Safety Commission before being forwarded to the prime minister’s office for final approval. Local government must then approve restart.

In mid-April 2012, after a series of high-level meetings, the Japanese government approved the restart of Kansai Electric’s Ohi 3 & 4 reactors, and urged the Fukui governor and the Ohi mayor to endorse this decision. They restarted in July 2012 and ran through to September 2013, when they were shut down for routine maintenance.

Nuclear plant restartsIn October 2012 the new Nuclear Regulation Authority (NRA), which had taken over from the Nuclear & In-dustrial Safety Agency (NISA) and NSC, announced that henceforth nuclear power plant restart reviews would comprise both a safety assessment by NRA and the briefing of affected local governments by the operators. NRA would base the assessment on safety guidelines formulated in July 2013 after public consultation. In rulemak-ing, the NRA commissioners referred to the guidelines of the IAEA, Finland, France and the USA, as well as the former NISA July 2011 stress test rules and provisional 30-point measures, issued in April 2012, that were applied to the restarts of Ohi 3&4.

In July 2013 four utilities applied for restart of 12 PWR reactors at six sites, two of which – Ohi 3&4 – were already running on interim basis. The units covered by the applications were Kansai’s Takahama units 3&4 and Ohi units 3&4; Hokkaido’s Tomari units 1-3; Shikoku’s Ikata unit 3, and Kyushu’s Sendai 1&2 and Genkai 3&4. Gross capacity is 11,200 MWe, almost a quarter of the nation’s total. These were all among the units well advanced in NISA’s stress test assess-ments in 2012. As of September 2013 the NRA was prioritising six PWR units: Tomari 3, Ikata 3, Sendai 1&2, Genkai 3&4 using four investigation teams with 80 staff. Tepco delayed its application for Kashiwazaki-Kariwa 6&7 ABWRs

pending negotiation with local government, and lodged it in Sep-tember 2013, lining up a further 2710 MWe gross. The Kashiwazaki-Kariwa 6&7 units were the first BWRs to be put forward for restart. Unlike the 12 PWRs referred to above, BWRs require a filtered containment venting (FCV) system. Under the general terms of a nuclear operator’s agreement with lo-cal government, prefectural approval is required for these because any use during an emergency would mean releasing radioactivity in the course of avoiding the kind of hydrogen build-up which caused the explosions at Fukushima, destroying the superstruc-ture of three units there.

In December 2013 Chugoku applied for assessment to restart its Shimane 2 reactor, and Tohoku applied for Ona-gawa 2, both also BWRs. Both com-panies had obtained local govern-ment approval for their applications. Chugoku also plans to apply for an assessment of the Shimane 3 ABWR, almost finished construction, once unit 2 is cleared to restart. J-Power in December 2014 applied for a safety assessment of its Ohma ABWR under construction. In February 2014 Chubu applied for approval to restart Hama-oka 4 BWR, following completion of a major sea wall. It intends to apply to restart unit 3 there in 2015, subject to completing work to conform with NRA regulations, local government agreement, and community accept-ance. Unit 5 (1360 MWe ABWR) will also be ready to restart then. In May 2014 Japco applied to restart its Tokai 2 BWR, an older unit. In June Tohoku applied for restart of its relatively new Higashidori BWR, and in August Hokuriku applied for Shika 2 ABWR, the 8th BWR and 20th overall.

In March 2014 NRA said it would prioritize clearance of Kyushu’s Sendai 1&2 for restart, and in May it said this would be followed by Kansai’s Takaha-ma 3&4. NRA has approved the review reports for these four units, which thus meet safety requirements for restart subject to final changes. Meanwhile a district court has ordered Kansai not to restart its Ohi 3&4 in Fukui prefec-

ture due to public concerns. Kansai, with local government support, has appealed the ruling.

The reactor restarts are facing significant implementation costs ranging from US$700 million to US$1 billion per unit, regardless of reactor size or age. To March 2014 the cost was put at $12.3 billion so far. The NRA is working to increase its relicensing staff to about 100 people, which could potentially shorten the currently envisaged six-month review timeline. Under a high case scenario developed by Itochu, about 10 reactors could be added every year for a total of up to 35 reactors back online within five years.

Media reports in January 2015 said that Kyushu’s Mihama 1&2, Japan Atomic Power’s Tsuruga 1, Chugoku’s Shimane 1, and Kyushu’s Genkai 1 could be closed down permanently, subject to approval by prefecture authorities in Fukui, Shimane and Saga and approval by METI. All are relatively small (320 to 529 MWe net) and by October 2015 will be more than 40 years old, so that ma-jor expenditure on upgrades is hard to justify even though all of them already have life extension approvals. Two larger units, Kansai’s Takahama 1&2 also reach the 40-year mark in 2015 but these have had significant work done already and the costs of upgrading will be more readily recoverable, though Kansai is uncertain about their future. METI has approved draft provisions for cost recovery for decommissioning all seven units. Final approval for decom-missioning and allocation of costs is expected by mid-2015.

Economic impact of shutdowns

JAIF has said that increased fuel imports are costing about ¥3.8 to 4.0 trillion ($40 billion) per year (METI puts total fossil fuel imports at ¥9 trillion in FY2013). The trade deficit in FY2012 was ¥6.9 trillion ($70 billion), and in 2013 ¥11.5 trillion ($112 billion), up 65% on 2012’s figure. For fiscal 2013 the trade deficit was ¥13.75 trillion ($134 billion), 70% up on FY 2012,



Feature

according to the Ministry of Finance. The total trade deficit from April 2011 to end of March 2014 was thus ¥23.25 trillion ($227 billion), compared with previous surpluses of at least ¥2.5 trillion per year (¥6.6 trillion in 2010).

Generation cost was up 56% from ¥8.6/kWh to 13.5/kWh in FY 2012. Losses across the utilities are about ¥1 trillion per year. The Ministry of Economy Trade and Industry (MITI) said in April 2013 that Japanese power companies had spent an additional ¥9.2 trillion ($93 billion) to then on im-ported fossil fuels since the Fukushima accident. In FY 2012 the additional fuel costs to compensate for idled nu-clear reactors was ¥3.6 trillion ($35.2 billion), mostly for oil and LNG. In 2013 Japan imported a record 109 million tonnes of coal, and plans to build al-most 15 GWe of coal-fired generating capacity were reported.

At the end of 2013 the Japan Busi-ness Federation (Keidanren) said that “By stopping nuclear power plants, national wealth of ¥3.6 trillion ($34.9 billion) per year is flowing overseas” due to increased fossil fuel imports. The ongoing slump of trade bal-ance into the negative could lead to deterioration of government credit and must be addressed “with a sense of crisis.” “There can be no new capital investment in domestic industry which is power-intensive.” Keidanren

urged the government to recognize that economic growth depends on stable and affordable power, and nuclear needs to be part of that rather than continuing undue reliance on LNG. Also the current feed-in tariff to encourage renewables should be reviewed to reduce its burden on the economy.

In June 2014 three major business lobbies – the Japan Business Federa-tion (Keidanren), the Japan Chamber of Commerce and Industry, and the Japan Association of Corporate Executives (Keizai Doyukai) – submit-ted a written proposal to the Industry Minister seeking an early restart of the nuclear reactors. “The top priority in energy policy is a quick return to inexpensive and stable supplies of electricity”, they said.In early 2014 some 92 mostly very old oil-burning generation plants were run-ning to full capacity, and these will be the first to shut down, due both to age and cost of running with imported oil.

Climate change effects

Carbon dioxide intensity from Japan’s electricity industry climbed again in FY2012, reaching levels 39% greater than when the country’s nuclear reactors were operating normally, and taking the sector far beyond climate targets. About 100 million tonnes per

year more CO2 is being emitted than when the reactors were operating, adding 8% to the country’s emissions. Emissions from electricity generation accounted for 486 Mt CO2 (36.2%) of the country’s total in fiscal 2012, com-pared with 377 Mt (30%) in 2010.

Up to March 2011 the CO2 intensity of Japan’s power generation was 350 g/kWh. Over the next year, with progressive reactor shutdowns, it rose to 487 g/kWh in FY 2012. In FY 2013 the country’s overall emissions rose to 1395 million tonnes of CO2 equivalent, the highest since records began in 1990. Among Japan’s climate change goals was for the electricity sector to reduce carbon intensity by 20% from 1990 levels, to 334 g/kWh CO2 on average, over the five years from 2008 to 2012.

On the eve of the UN climate change meeting in Warsaw in November 2013, Japan’s Minister of the Environment an-nounced that his country was changing its CO2 emission reduction target from 25% lower than 1990 levels by 2020 to a 3.1% increase from then, or 3.8% reduction from 2005 levels. He cited the shutdown of Japan’s 50 nuclear power reactors, some possibly for an extended period, as a prime reason for this, forcing reliance on old fossil fuel plant. In FY 2013 emissions were 1.3% up on 2005 levels.

A number of public opinion polls were taken in April and May 2011 following the Fukushima accident. Those in April showed around 50% supported the use of nuclear power at present or increased levels, but as the crisis dragged on the May polls showed a reduction in support to around 40% and a growth in opinion to over 40% of those wanting to decrease it. A steady 15% or so through May- June 2011 wanted it abolished. In March 2013, the proportion opting for increase or status quo had dropped to 22%, while 53% wanted to decrease it and 20% wanted to abolish it.

*source World Nuclear Association, International Energy Agency


Interview

Tata Power joins a small club of Indian corporations that have been in business continuously for 100 years. The com-pany began with a 12 MW hydro unit in Khopoli (near Mumbai) in 1915, which was built by transporting equipment on horse-drawn carriages from Mumbai. Over the years, it has grown into India’s largest integrated power company and is trying to build a global footprint. Tata Power and its subsidiaries now have an installed capacity of close to 8,600 MW.

The journey, though, has not been smooth, especially in recent years. Its biggest bet, the 4,000 MW Ultra Mega Pow-er Project (UMPP) at Mundra, Gujarat, which is based on imported coal, is reeling under losses after the Indonesian government changed its rules on coal pricing in 2011. Losses at Mundra are threatening the viability of the compa-ny. Tata Power’s MD-CEO Anil Sardana, however, is hopeful of better times ahead. He spoke to Forbes India about the challenges facing the company and his vision for Tata Power. Excerpts:

Anil Sardana Age: 55 Designation: CEO and MD, Tata Power Career: Has worked with NTPC, BSES, Tata Power Delhi Distribution Highlights: Has three decades of experience in the power and infrastructure sector

Pima. Four years ago, Tata Power took a call to hold investments in India and look for opportunities overseas. Are you happy with the results?

AS. Let me answer your question with a specific example. In Decem-ber 2011, we bid for a hydel project in Georgia and one in Himachal Pradesh. In February 2012, we were lucky to be awarded both, to put up power plants of roughly 400 MW each. Today, in 2015, we have completed about one-fourth of the Georgia tunnelling and construction work whereas not even a brick has been put up in the Himachal project. It is likely that in 2017, when the Georgia project is complete, the Himachal project will be in the same shape.

Yes, four years ago, we started look-ing globally. In retrospect, we are

very happy about that decision. It is sad that 65 years after independ-ence, we are still unable to guaran-tee quality power to our consumer. This is obviously hurting the entire process of development. Although there are many problems, we have shown that they can be tackled. We were able to turn around a state-owned enterprise [North Delhi Power], which could not be compet-itive for many decades. Today, the same set of employees has achieved global performance standards.

The power business obviously needs a lot of capital and there is so much to do. Commercially, Tata Power is in tremendous pain. Despite the huge opportunities in business, there is little action on reforms on the ground. After the presidential decree in Indonesia, which made our UMPP non-profitable, we have been pleading for government

support to contest it. But we didn’t have any luck. We are going through the corridors of power trying to explain that we can’t continue like this. We continue to supply power from the Mundra project because of our commitments, but that too is in great financial stress. If nothing is done, the project will collapse.

Pima. Has this changed with the new government? Will you look at buying ‘distressed’ power assets?

AS. There is a lot to do if India can open up the power business in a transparent way. Just having a good central government is not enough; we need to see action from the states. We need to align them. States have to let go of (power) distribu-tion to players who can possibly do better. That outlook hasn’t changed



as yet. We continue to believe that the time hasn’t come to divert our attention completely to India. It will be some more time before our investment picks up.

Pima. How have you fared overseas?

AS. We have created four verticals – India & Saarc, Southeast Asia, Middle East and Turkey and Africa. All the four teams pitch for capital [invest-ment in projects]. Our allocation

strategy is to invest in the projects where we have all the clearances and are able to mitigate risk.

Since 2012, we have started imple-menting the following projects and will see the results in the coming years: We have a 235 MW wind farm in Cape Town, South Africa (under construction), 125 MW hydro project in Zambia (to be completed in 2016), 400 MW hydro in Georgia (phase one expected to be completed in 2017),

two distribution circles in Nigeria and imported-coal based thermal plants allocated in Myanmar and in Vietnam.

Pima. Are you considering bidding in the coal auctions? How has the fall in coal prices impacted you? Will you divest in these projects?

AS. Our mines were de-allocated too. But we will look at bidding only after the first two rounds, after the process stabilises. We are mostly into imported coal [Trombay and Mundra]; only our Maithon [Jharkhand] project is based on domestic coal. On the price-vola-tility front, we are careful; we are clear that about half of our fuel demand should be securitised. We are getting out of one of the four mines we hold in Indonesia. We are waiting for the lender’s permission before there is a closure on this. We will look at the other three after this is done.

Pima. How are you planning to celebrate Tata Power’s century?

AS. Our founders were truly vi-sionary. A hundred years ago, they thought of lighting up the region using hydro power.

They started with 12 MW and this has grown to a complex of 450 MW today. In the centenary year, we plan

to start another hydel complex of 450 MW, continuing our commit-ment to clean power. We are also launching a unique initiative – the Tata Power Skill Development Institute through which we plan to train 2,00,000 skilled workers over the next decade. We will train and certify fitters / electricians / welders

in a modular manner. One of their courses will also be on ethics. They can upgrade their skills, and will be paid a stipend while they undergo refresher courses. We hope this will help bridge the skill gap. Over the years, we will ensure that our sup-pliers and contractors hire from this pool of technicians.

We have created four verticals –

India & Saarc, Southeast Asia, Middle East and

Turkey and Africa.

There is a lot to do if India can open up the

power business in a transparent way. Just having a good central

government is not enough; we need to see action from the

states

INTERVIEW: Anil Sardana

Feature


JAPANS HYDROGEN HIGHWAYSince the 2011 onset of the Fuk-

ushima nuclear disaster, Japan has had to drastically revise an

energy policy that had long herald-ed atomic power as its main source of energy.

The new energy policy announced in April last year outlines plans to decrease Japan’s nuclear dependence as much as possible, while boosting renewable energy sources.

At the same time, it also says the government will promote the use of hydrogen to pave the way for a “hydrogen society.”

“Hydrogen, which can achieve high energy efficiency, low environmen-tal burden and capability for emer-gency use, provided appropriate usage, is expected to play a central role as a secondary energy source,” the government’s policy report said.

Reflecting growing demand for alternative forms of energy that are clean and efficient, automakers are set to sell their first commercial fuel-cell vehicles, powered by hydro-gen, starting next year.

“Why do we need to promote hydrogen energy? The Japanese government lays out about four main reasons – energy-saving, (the) environment, energy security and industrial competitiveness,” said

Eiji Ohira, director of the Fuel Cell and Hydrogen Technology Group at the New Energy and Industrial Technology Development Organ-ization (Nedo), a Kanagawa Pre-fecture-based semi-public body in charge of research and development of new energy sources.Hydrogen emits no carbon dioxide when burned, so it is considered clean energy that can greatly help reduce greenhouse gases.

emitting carbon dioxide are just a few of the hurdles.

Hydrogen alone hardly exists as a natural resource. It needs to be separated from other elements and molecules. It’s mainly known as a key component of water.

Currently, fossil fuels, including naphtha, natural gas and coal, are the main sources of hydrogen, which is generated by a method called “steam reforming,” in which steam is added to methane to yield hydrogen. A huge amount of hydro-gen is also produced as a by-product from the production of caustic soda plants and from coke ovens.

Nedo published a white paper on hydrogen energy in July that states the importance of promoting hy-drogen-related products, which in Japan are expected to develop into a market worth ¥1 trillion by 2030 and ¥8 trillion by 2050.

This would help strengthen Japan’s industrial competitiveness because it has the most fuel cell-related pat-ents in the world. Fuel cells generate power through a chemical reaction between hydrogen and oxygen.

In 2009, Japan took the lead among other countries in selling fuel cells for home use to generate power and heat.

Expectations are high, but so are the challenges.

Setting up expensive hydrogen stations for FCVs, securing sufficient supplies of the gas and coming up with ways to produce it without

FEATURE: Japans Hydrogen highway

“Japan’s competitiveness in the field of hydrogen energy is strong. In particular, our auto industry, which is Japan’s key industry that accounts for 10 percent of the nation’s jobs and 20 percent of exports, is facing fierce global competition, so it is essential to maintain competitive-ness with the new field of FCVs,” the white paper said.

Expanding the presence of fuel cell vehicles is an important step, according to the industry ministry’s road map for a hydrogen society.The first commercial FCV is sched-uled to be released by Toyota Motor Co. by next April with a price tag of around ¥7 million, with the government planning to offer a ¥2 million to ¥3 million rebate to consumers.

FCVs run on electric motors. Unlike gasoline-powered vehicles, they emit only water as exhaust and pro-duce no carbon dioxide.

Although carbon dioxide is emitted in the process of producing hydro-gen, the volume is lower on average than that produced by other means, said Ohira.Still, it’s not quite certain they will take off, given the infrastructure hurdles.

“Setting up hydrogen stations is a huge challenge… there are not many available spaces in the cities and the cost of land is high,” Ohira said.

A hydrogen station network would require numerous storage and de-livery systems. The cost of building a single station is currently about ¥400 million to ¥500 million. So even with government subsidies, a network would require a massive investment.By comparison, the cost of build-ing an express charging station for electric vehicles can be less than ¥10 million, even without subsidies.

Japan plans to have 100 hydrogen stations running in 2015 and 1,000 by 2025.

There are safety issues regarding hydrogen, however, and more and more people are becoming aware of them. The gas in pure form is highly flammable and reminds many of the hydrogen explosions that blew up the concrete reactor buildings at the Fukushima No. 1 plant.

This is an issue in the city of Saita-ma, where Tokyo Gas Co. is trying to build a hydrogen station in the Sakura district.

“They said that a hydrogen station is safe and will not pose problems of the kind that happened at the Fukushima plant, but the station will be dealing with hydrogen… and you don’t know what’s go-ing to happen,” said Miki Kubo, a member of the Saitama Municipal Assembly. “People said a nuclear power plant would never have an accident (like Fukushima), but it did.”

Kubo, who belongs to the Japanese Communist Party, said the construc-tion site is right next to a residential area and an elementary school. Since about 20 residents oppose the plan, construction hasn’t even begun yet, she said.

Then there’s the problem of supply. Were hydrogen to really become a common form of energy, especially for cars, Japan will have to find ways to secure enough of the gas.

According to the industry minis-try, about 300 million cu. meters of hydrogen (at 0 degrees and 1 atmosphere of pressure) are dis-tributed commercially every year. If fuel cell vehicles really expand into the millions and if hydro-gen plants are built that literally generate power from the gas, the country will need to import it, said Ohira.One FCV consumes about 1,000 cu. meters of hydrogen per year, he said.

In that case, hydrogen will need to be imported, but transporting large amounts over long distances would be costly and difficult using today’s technology. And because current production depends heavily on fossil fuels, it can’t be said at present that hydrogen is a completely car-bon dioxide-free form of energy.

The hydrogen white paper thus says Japan should obtain the gas from water using electrolysis, with the process being powered by such


Feature


renewable energy sources as solar and wind. That will allow hydrogen to be produced without carbon emissions.

But that won’t be easy either, because generating power from re-newable energy remains expensive and unreliable due to its reliance on the weather.

Industries are increasingly pressing pushing for the adoption of hydro-gen fuel technology because they sense potential market opportuni-ties worldwide.

But problems abound, including the comparatively high cost of fuel-cell vehicles and the need for specialized hydrogen fuel stations. Also unresolved is how to gener-ate, transport and store hydrogen in a sustainable way.

FCVs run on electricity generated from the oxidization of hydrogen to create water.

In a rare move, Toyota Motor Corp. announced last week that it will allow other firms to use its near-ly 6,000 patents related to fuel cells. It said it wants to spread the technology globally while spurring competition for further develop-ment.

Toyota began selling its fuel cell-powered Mirai sedan in Japan in December, becoming the world’s first carmaker to offer an FCV for general use. It is preparing to launch what it calls “the ultimate eco-car” in the United States and Europe this summer.

The world’s largest carmaker takes the view that environmentally friendly cars can benefit society only when they are in widespread use.

“We’ve determined that it is im-portant to increase the number of supporters in order to realize a hydrogen society,” Toyota President Akio Toyoda told reporters following the patents announcement.

FCVs debuted in the early 2000s, and Japanese carmakers and sup-pliers have led the development of the technology, accounting for more than half of the global patent applications related to fuel cells and hydrogen stations.

Toyota’s decision might be wel-comed at a time when rivals Honda Motor Co., Nissan Motor Co., Daimler AG and General Motors Co. are pre-paring to roll out FCVs of their own over the next few years.

“It’s an unusual decision to promote development,” Toshiyuki Shiga, vice chairman of Nissan, said.

The move highlights, however, au-tomakers’ skepticism as to whether costly FCVs, which face competition from other environmentally friendly technologies, are a commercially viable transportation option.

The Mirai, which means “future” in Japanese, costs a hefty ¥7.2 million, al-though a government subsidy knocks around ¥2 million off the price.

Toyota plans to produce only 700 units this year, while acknowledging the price is still high and pledging further efforts to cut costs.

The success of FCVs largely depends on how a wide network of hydrogen fueling stations is created. While there are only a few in Japan, the government is in the midst of a hydrogen station blitz.In June, the Ministry of Economy, Trade

and Industry drew up a road map for bringing about a “hydrogen society” in which the gas even plays a central role in homes powered by fuel-cell batter-ies, which, like those in FCVs, emit only water and heat as byproducts.

The long-term strategy also refers to the need to build large supply chains and establish methods to produce hydrogen more efficient-ly and without emitting carbon dioxide.

As part of the road map, the gov-ernment will set up 100 hydrogen fueling stations this year in major cities.

Each station costs ¥400 to ¥500 mil-lion to build, compared with about ¥100 million for a petrol station, due to the extra equipment required for storage, which involves heavy compression and chilling the gas to subzero temperatures.

“So far, it is unprofitable. We want to lower building and operating costs,” said Ichiro Uchijima, executive vice president of JX Nippon Oil & Energy Corp.

The firm opened a hydrogen station in Kanagawa Prefecture last month, and plans to manage 40 stations by the end of March 2016.JX sells hydrogen that can run an FCV for 1 km for about ¥10, which means its running costs are almost on par with that of hybrid cars. Ma-jor gas distributors, including Tokyo Gas Co. and Iwatani Corp., have set prices at similar levels.

FEATURE: Japans Hydrogen highway


Iwatani accounts for over 50 percent of the industrial hydrogen and equipment market in Japan. Its un-usual approach will involve building stations at convenience stores to popularize the technology. Cooper-ating with Seven-Eleven Japan Co., Iwatani looks to open the first station this fall in Aichi Prefecture, where Toyota is headquartered.

Sources say Japan aims to halve station-building costs by 2020, the year around which the road map sees a “remarkable expansion” in public use.Tokyo will host the Summer Olym-pics that year, which the govern-ment hopes will be an opportunity to showcase the technology with hundreds of FCVs on the road.Toyota said as much by offering its FCV patents through 2020, although those related to hydrogen stations will be freed up indefinitely.

However, Tokyo plans to spend ¥45.2 billion on fuel-cell vehicle subsidies and hydrogen stations for the 2020 Olympics as part of Prime Minister Shinzo Abe’s plan to reduce the na-tion’s reliance on nuclear power.

Thirty-five hydrogen fuel stations will be built in the capital, which is in negotiations with Toyota Motor Corp. and Honda Motor Co. to put 6,000 hydrogen cars on its roads by 2020, said Makoto Fujimoto, who heads the planning team at the metropolitan government’s energy department.

The nation is investing in hydrogen power as it continues to struggle with the aftermath of its worst peacetime nuclear disaster, in 2011. Spending on hydrogen infrastructure comes as Tokyo’s government is under pressure to rein in costs as it prepares to host the quadrennial games.

“The Olympics are a good oppor-tunity to showcase new technol-ogies,” said Hiroshi Takahashi, a research fellow at Fujitsu Research Institute. “It’s also a significant chance to attract new investment

and update the city’s transpor-tation system to make it fuel-cell friendly.”Last week, Toyota delivered its first Mirai fuel-cell model to Abe. After a short test drive at his official residence, Abe declared it was “very comfortable” and said he wants “all ministries and agencies to have” the Mirai.

“It’s time to introduce a hydrogen era,” he told reporters on Jan. 15.

The central government is plan-ning hydrogen distribution facil-ities as it supports Toyota, which pioneered hybrid vehicles, to help popularize what the carmaker sees as the next generation of auto technology. Abe has said Japan intends to create a “hydrogen society,” with cells powered by the element also powering homes and office buildings.

Japan’s fuel-cell subsidies are bigger than the incentives that China, the U. S. and Europe are offering for elec-tric-vehicle buyers. They are also more than triple the ¥950,000 of incentives Japan offers buyers of Mitsubishi Motors Corp.’s all-electric i-MiEV.

The country is paying ¥10 billion a day to buy natural gas after the triple reactor meltdown forced the shutdown of all of its nuclear plants, Fujimoto said.

Under the Tokyo Metropolitan Gov-ernment’s plan, the city aims to have 100,000 hydrogen passenger vehicles, 100 hydrogen buses and 80 refueling stations by 2025. Buyers of fuel-cell vehicles in Tokyo will be entitled to

about ¥1 million of subsidies, on top of the ¥2 million provided by the central government, he said.

More than 80 percent of the costs of building hydrogen stations will be subsidized by the Tokyo government, capping the costs for operators at ¥100 million, or about the same as building a gasoline station, according to Fujimoto. The government may cover the costs entirely for small-business owners, he said.

Toyota President Akio Toyoda told reporters last week that the auto-maker was considering increasing production after receiving about 1,500 Mirai orders – 60 percent of which are from government offices and corporate fleets – in the first month, compared with its target of 400 by the end of 2015.

Fuel cells are considered environ-mentally friendly because they con-vert hydrogen to electricity, leaving water vapor as a byproduct

Efforts to make FCVs commercially viable have long suffered from the chicken or egg question – more cars must be built to increase fueling stations, and more stations must be built to increase cars.

Toyota rejects the concern, how-ever, with its president saying it is more like a relation between “flowers and bees” instead. “They help each other and then create a new society.”

The opportunities for fuel cell and hydrogen are certainly in abundance in Japan, from a domestic perspec-tive and also international perspec-tive. Companies on the international front need to ensure they get there message to market in front of the right people in the right place at the right time and of course nurture relationships to ensure they stand the best chance of proving their technology. For now at least Japan is ensuring its positions on driving the hydrogen economy.

As part of the road map, the

government will set up 100 hydrogen

fueling stations this year in major cities

SCADA SecurityBy: Chris Day,SCADA securityconsultantfor MWR InfoSecurity

The beginning of 2015 saw one of the biggest cyber events ever take place. Unfortunately, it was drowned out by the news of the various divisions of Sony being hacked. At the same time, the German gov-ernment quietly admitted it had suffered a sophisticated cyber attack against an industrial facility – a steel mill – which resulted in equipment damage, production downtime and which could have potentially cost lives. This event was only the second time ever a cyberattack had resulted in physical damage.

Following Stuxnet, the computer worm designed to attack industrial

programmable logic controllers and ruined almost a fifth on Iran’s nuclear centrifuges, this is also the second publicly disclosed cyber attack against SCADA (superviso-ry control and data acquisition) equipment which has been formal-ly investigated and attributed to a sophisticated remote attacker. This in itself is a rare event and demon-strates the credible and increasing risk to SCADA equipment, or com-puter systems used for gathering and analysing real time data. It is an unfortunate truth that a risk typically needs to be demonstrat-ed in the wild repeatedly before it is addressed with the resolve ap-propriate to the potential impact of a successful attack.

However, unlike Stuxnet which fea-tured sophisticated air-gap hopping methods to gain access, this attack

is reported to have used less exotic, yet still credible spear-phishing (email spoofing fraud) and social-en-gineering techniques. The steel mill attackers were able to infiltrate the corporate network by sending a tar-geted phishing email that appeared to have come from a trusted source in order to deceive the recipient employee into downloading mal-ware to his / her computer. Once the attackers obtained a foothold on the corporate system, essentially, they were able access to the steel mill by successively working their way into production networks to access the system’s plant equipment controls.

In this particular attack on the un-named German steel mill, attackers manipulated and disrupted control systems to such a degree that a blast furnace could not be properly shut down, resulting in “massive” – albeit unspecified – damage. This event demonstrates how gaining access to and attacking SCADA systems doesn’t necessarily need to employ expensive or overly sophisticated techniques.

I have personally spent many years scoping, conducting and reporting SCADA system computer security assessments. In practically all my assessments, across several different sectors, I have noticed one common theme; a reluctance to admit or lack of understanding of connectivity be-tween corporate and SCADA systems.

I believe I understand why this situation exists; it is typical to see an organisation’s IT and engineering as separate departments. Yet, to enable

Case Study


Case Study


greater exploitation of SCADA meta-data (such as manufacturing output or power consumption) and a lowering of infrastructure costs, it is increasingly common to find SCADA and corporate networks connected. In many instances, this fusion of net-works is focused on maintaining the functionality of the corporate and SCADA systems by each group of specialists – the SCADA and network engineers. The discussion of the se-curity implications of such a merger is often absent. It is at this junction, the known and unknown security issues of two networks have been combined into one, vastly increasing attackers’ chances of gaining access and having a negative effect against corporate or SCADA systems.

Also, we stand no hope of effec-tively dealing with cyber attacks

against SCADA if we don’t improve our ability to share knowledge with the wider SCADA community. If organisations do not acknowl-edge security issues or attempt to diminish the credible, demonstrat-ed threat for PR purposes, they are merely burying their heads deeper in the sand and perpetuating the problem. By recognising and sharing details of these attacks, we can make effective defensive countermeasures and strategies based on experience and under-standing gained from studying real life attacks.

In summary, if we are connecting corporate and SCADA systems to-gether we must ensure this union is forged securely so the networks do not share their security weaknesses with one another. These weakness-

es could be in the form of vulner-able Internet exposed corporate network services, remote access for SCADA maintenance engineers or outdated SCADA workstations laden with historic vulnerabilities and operating systems. To enable robust security when combining networks, we need to be aware of the latent risks in each of the net-works we are combining. We also need to also investigate the tech-nologies present in each network to understand if new security risks would be created when combining them. Without this understanding, and an appreciation of in-the-wild attacks, we will be unable to imple-ment effective defensive strategies and measures we need to protect SCADA systems and the Industrial and critical processes that exist upon them.


Feature

Offshore

Wind AsiaA ten-company consortium headed by Hitachi Zosen Corporation (Hitz) has re-ceived the go ahead to explore the possibility of an offshore project off the coast of Niigata prefecture in Japan.

Hitz was formerly a member of the Hitachi Group, but is now inde-pendent.

The Hitachi turbine was judged to be economically viable, especially in the absence of progress on the 7MW SeaAngel from Mitsubishi Heavy Industries, noted observers connected to the project.

The turbines will be located ap-proximately 2 kilometres offshore in water depth of 10-35 meters, in an area referred to as the Iwafu-neoki. This would allow the devel-opers to use conventional founda-tions. Local fishing cooperatives raised objections to positioning wind turbines closer to shore, said Chikau Otaki, a section chief in the new energy promotion department at the Murakami City hall.

Kimiaki Yasuda, a professor of Nagoya University, was among the first to introduce the possibility of an offshore wind power project to Murakami City last year, Otaki noted. Yasuda is also head of the Stakeholder Management Re-search Laboratory at the university, and his expertise in dealing with local stakeholders is likely to have swayed the fishing cooperatives in their decision, observers say.“We had good feedback from the fishing cooperatives following Yasu-

da’s involvement,” Otaki said.

Other offshore projects either went through extended negotiations with the cooperatives or have yet to reach agreement on project condi-tions. Fishing cooperatives contin-ue to maintain powerful legal rights over fishing grounds.

The Murakami project must under-go a lengthy official environmental assessment, and construction is unlikely to commence until 2020, with the launch of commercial operations set for 2024, according to HItz.

There is some excitement regarding the project, however, as it is the first example of a commercially-based offshore wind power project in

open waters, said Chuichi Araka-wa, a professor in the engineering faculty at the University of Tokyo. Previous commercially targeted projects have all been located inside port areas.

Murakami City is promoting the advanced project as an anti-global warming project and as a way to reju-venate the region. Hits’s spokesman points out that it was the municipal-ity that approached the company, and not the other way around.

Yasuda and Arakawa are mem-bers of a Murakami City-based assessment sub-committee, along with Takeshi Kinoshita, professor emeritus at the University of Tokyo, Tetsuro Nagata, former president of Eurus Energy, and Masanori Miya-hara, a former deputy director-gen-eral of the Fisheries Agency.

It is uncertain at this stage whether a technical adviser will be appoint-ed, but Yasuda and Arakawa are viewed as strong candidates for the position.

The project was passed by the Mu-rakami City, Iwafuneoki wind power generation promotion committee on 5 February, Otaki said. Murakami City lies to the north of the prefec-ture, and is close to the border with Yamagata prefecture.

The turbines will be located approxi-

mately 2 kilometres offshore in water

depth of 10-35 meters, in an area referred to as the

Iwafuneok

FEATURE: Offshore Wind Asia


However, things are moving quickly in China.

Since it was founded in 1993, the China Longyuan Power Group has been committed to the develop-ment of green energy generation. By the end of 2013 it owned or controlled a total of 14.1GW of generating capacity, with wind accounting for the vast majority of its business – 11.9GW of in-stalled capacity by the end of last year. Longyuan is now indisput-ably China’s leading wind-power developer. The company’s remain-ing 2.2GW of capacity is made up of solar, tidal, biomass and geothermal sectors.

Longyuan runs six large wind zones in the northern and southeastern coastal part of Chi-na. The 11 provincial areas that accommodate these zones all boast rich wind resources. At the end of 2013 wind installations here accounted for more than 80 % of the company’s total wind capacity. But in recent years, Longyuan has quickened its pace of developing projects in both central and coastal areas, where curtailment is less severe. In 2011 it commissioned the country’s first large-scale low-wind speed farm in east China’s Anhui province.

New regions

Since then, its wind business has extended to Shanxi, Shaanxi, Jiangxi and Guizhou provinces in central China and to Shandong and Jiangsu provinces in eastern coastal areas. Last year, the firm had 2.76GW of wind projects approved by the National Energy Administra-tion (NEA), more than 70 % of which were located in these areas. In a subsequent NEA-approved plan of wind sites, released in February, Longyuan had 28 projects totaling 1.5GW, 90 % of which were in these areas.

As well as pioneering low-wind speed development in China, Longyuan has been at the forefront in other areas. In October 2013 it commissioned five Goldwind 1.5MW turbines 4,700 meters above sea level in Naqu, Tibet, still comfortably the highest wind farm in the world. The plan is to install

33 such turbines in two phases in Tibet, where wind power was unknown before.

Offshore ambitions

Longyuan has also been leading China’s offshore wind development. It operates 257MW of the country’s

482MW of installed offshore capac-ity, and its inter-tidal site at Rudong in Jiangsu province has served as the testing ground for the country’s offshore products. Almost all the major domestic manufacturers have installed their multi-megawatt prototypes there.

Over the past few years, Longyuan has gained much experience in offshore wind. It currently owns two 800-tonne self-hoisting crane vessels, designed for installing offshore turbines in water depths of up to 30 meters. Together they are capable of installing 300-350MW of offshore turbines a year. Longyuan president Li Enyi said in August that the devel-oper is aiming to boost its operating offshore capacity to 1GW by the end of 2016.

Longyuan is also now looking beyond China for future growth. Its Canadian subsidiary, Longyuan Canada Renewables, is close to commissioning the 91.4MW Duf-ferin wind project in Ontario, using GE turbines. It has also successfully tendered for 244MW in two projects in South Africa, and preparatory work is under way for projects in the US and eastern Europe. The growing Latin-American market is also being targeted for future development.

Murakami City is promoting the advanced project as an anti-global warming project and as a way to rejuvenate the

region


Editorial

FG WILSON’S MODEL FOR EXPANSIONNew F Model sizes to be launched

as Chinese Dealer network grows

The 32-125 kVA range of genera-tor sets, which complements the existing suite of FG Wilson product ranges, has proved extremely popu-lar with customers across the world with its design providing a more diverse and competitive product offering across multiple customer segments such as domestic, retail and industrial.

Uncompromising on quality, avail-ability and expert local support, these models deliver uncomplicated power assurance with the quality ex-cellence which the world has come to expect from FG Wilson. Until now the 32-125 kVA range has only been

available in 50 Hz but customers will soon be able to be purchase this in 60 Hz.

Plans are also advanced for the launch of the F Model range in a number of different sizes – both smaller and larger – to meet the ris-ing demand for the product in coun-tries such as China, Brazil, Russia and Africa. Over the next 18 months the range will become available in 9.5-22 kVA, 150-165 kVA, 200-220 kVA, 275 kVA and 340-390 kVA.

An exclusive feature of the F Model range which has been an important factor in its success during the first

year on the market is the introduc-tion of the FG Wilson engines to the proven and trusted FG Wilson generator set core design. Coupled with robust, world-renowned com-ponents, the F models deliver a high quality, ready-to-run product that meets industry standards for the value-utility market.

Running in tandem with the suc-cessful launch of the F Model range has been the growth of FG Wilson’s official Dealer network across China. During 2014 FG Wilson expanded its Dealer network in China with the recruitment of five high-quality companies which has improved its reach across four key provinces – Shandong, Jiangsu, Hunan and Sichuan.

These new Dealers will work along-side one of the most long-standing Dealers in the region, FG Wilson Hong Kong, who have been pro-viding high-quality diesel and gas generator sets as well as expert ad-vice and specialist technical support to Hong Kong, China, Macau and Taiwan since 1991.

Our Dealer recruitment is ongoing and we are engaging with a num-ber of firms with a proven pedigree to establish new Dealers in areas including Jiangsu, Anhui, Fujian, Jiangxi, Hubei, Henan, Hainan,

Less than a year since FG Wilson launched its hugely-successful F Model range, the leading global manufacturer of diesel and gas generator sets will be expand-ing the range further throughout the next 18 months.

EDITORIAL: China expansion


Guizhou, Yunnan, Gansu, Shanxi, Inner Mongolia, Jilin, Heliongjiang, and Ningxia.

Neil McDougall, Retail Global Sales Director, commented:

“FG Wilson is continually searching for opportunities to consolidate our po-sition as the leading global manufac-turer of diesel and gas generator sets. The expansion of our Dealer network in China and the upcoming launches of our ever-popular F model range in a number of new sizes are very tangible examples of FG Wilson ensuring all of our customers’ needs are fully met.

“The F Model product range has delivered on our promise of provid-ing performance, serviceability and durability with a FG Wilson engine and a simplified choice of options. The

forthcoming introductions of the new F model sizes will allow us to compete in even more new markets and broad-en our customer base further.

“Such new product introductions are part of Caterpillar’s strategic plans to position FG Wilson as the volume brand within its Electric Power Divi-

sion for all diesel and gas generator sets from 6.8-750 kVA.

“The expansion of our Dealer network in China comes just six years after the relocation of FG Wilson’s Asia Power Systems (APS) to a 28,000m2 world class facility in Tianjin, purpose built to fulfil increasing demand. Highlight-ing our policy of continued investment in our world-class manufacturing fa-cilities across the globe, the APS plant in China is one of the main source plants for the recently-opened Product Distribution Centre (PDC), located at Antwerp, Belgium.”

With manufacturing plants located in the UK, Brazil, China, India and the USA, FG Wilson’s ‘One Global Stand-ard’ guarantee ensures that every one of its generator sets is designed and manufactured to the same glob-al standard.

For more information about FG Wilson please visit www.fgwilson.com.For more information, contact Mark Sterling on 07858 045418 or email [email protected]


WHAT’S CHANGED IN HYDROPOWER DEVELOPMENT?

The political discourse on hydro-power has also changed over the past decade. The environmental movement has broadened its focus from local environmental issues to global issues like climate change. Middle income countries, espe-cially the governments of Brazil, Russia, India, China, and South Africa (BRICS), are increasingly financing hydro and have become more assertive in advocating infra-structure development. The World Bank Group supports sustainable and responsible hydro projects of various sizes and types, depending on local need.

The potential for hydropower is arguably highest in Africa. On one hand, the stakes are high as only one third of Africans has access to modern energy. On the other hand, the opportunities are enor-mous as only 8 % of Africa’s vast hydro potential is developed. This

is lower than any other continent. Hydro can light up Africa.

Sustainability front and centerEnvironmental and social sustain-

ability have made considerable progress in the past decade with a number of international guidelines developed to measure the sustain-ability of hydropower projects, such as the IHA’s Hydropower Sustainabil-ity Assessment Protocol.

Implementing environmental and social management plans during construction and after commis-

sioning has often proven harder than writing them. The hydropower community should continue to learn and to incorporate lessons from what works in practice. And

while know-how for responsibly managing environmental and social impacts has improved considerably, the challenge is always in applying this consistently and efficiently.

Financial sustainabilityThe standing of hydropower suffers from real and perceived pre-con-struction and construction delays.

In the past decade, hydropower development has picked up after a sharp decrease in the 1990s. The late 1990s was characterized by escalating debates over large dams. At the World Bank, our investments in hydropower declined by 90% between 1992 and 2002. However, globally, between 2005 and 2011, newly installed hydropower capacity just outpaced new generation capacity from all other renewables combined. This growth was driven by hydropower development in Asia, especially in China.

The World Bank Group supports sustainable and responsible hydro projects

of various sizes and types, depending on local need

Feature

FEATURE: What’s changed in Hydropower development?


A review by some academics at the University of Oxford on cost over-runs attracted attention recently but it’s important to remember that most of the hydropower projects, which now generate 16 % of the world’s electricity, are “no regret” investments. Hydropower projects often deliver benefits beyond

predictions. For example – Itaipu, a hydropower project jointly con-structed by Brazil and Paraguay, is highlighted in the Oxford paper. There were indeed cost overruns. It took 11 years between signing the treaty that originated the project in 1973 and the first power being gen-erated in 1984. But the benefits have been enormous. Itaipu generated nearly 100 TWh in 2013 – providing 72 % of the power used in Paraguay and 17 % in Brazil. In constant dol-lars, revenues generated from the project amount to nearly six times the actual cost of construction. The two governments have shared about $ 10 billion in royalties. This is why political leaders and policy analysts in Brazil agree that Itaipu was a very good investment.

Still, cost overruns and delays continue to be a concern for large infrastructure projects including hydropower. This is often due to over-optimistic and outdated cost and construction time estimates. But often, lack of government capacity and resources to drive projects for-ward is a serious cause of escalating cost and project duration.

The 2012 commissioning of the 250 MW Bujagali project on the Nile in Uganda was a milestone as it was the first full-scale private hy-dro project in Sub-Saharan Africa.

Bujagali is a success but coming to financial close on a complex project financing structure with multiple public and private sourc-es of financing – with overlapping requirements – took a long time. In 2002, the Ugandan President Museveni told Reuters: “I am not happy because a project that

should have taken two years has taken seven years to start.”

Since Bujagali’s financial close in 2007, no other large scale privately financed hydropower project has come to financial close in Sub-Saha-ran Africa. Given hydro’s investment profile, it comes as no surprise that private financing for hydropower has lagged compared to invest-ments in thermal generation. Firstly, hydropower is capital intensive with construction accounting for up to 80 % of total project costs. Secondly, the normal economic life of a hy-dropower project is far longer than that of a thermal generation plant. Thermal plants are standardized and pose few surprise risks. Hydropow-er plants are site specific and pose geological and hydrological risks

that need to be shared by private developers and governments.

Large hydropower has traditionally been developed with cheap public money and, as a result, off takers and policy makers have come to

expect very low generation costs. Private developers and financiers require commercial rates of re-turn. In developing countries, loan maturities are often limited to five to 10 years. Given the high capital expenditure of hydropower, the cost of capital has a strong impact on the production costs. Take the case of the 147 MW Adjarala Hydroelectric Project on the Mono River between Togo and Benin. With a concessional financing package, the levelized generation cost would be below 7 US cents / kWh. Purely commercial financing would nearly triple that unit cost.Higher unit costs of hydropower will have to be anticipated if govern-ments want to increase the pace of hydro development using private financing. At the same time, the cost of commercial financing could be brought down through risk miti-gation instruments and combining public and private financing. In most cases, levelized unit costs of hydro-power beat other technologies even if the costs of commercial financing are reflected.

At present, most concessionaires sell their energy exclusively to one state-owned utility. However, the number of projects, which sell energy to industrial users or export power to neighboring countries, is growing. This could enhance the attractiveness of hydropower for private financiers going forward.

Hydropower is already an important source of revenue for countries like Lao PDR, Nepal, and Bhutan.

The rapid expansion of the mining industry can be a game changer for hydropower in Africa. Historically,

Firstly, hydropower is capital intensive with construction accounting for up to 80 % of

total project costs

Secondly, the normal economic life of a hydropower project is far longer than that

of a thermal generation plant


mines have developed cheap hy-dropower resources for self-supply – leaving households in the dark or paying for more expensive sources of energy. The World Bank Group promotes grid-based arrangements in which mines sell into the grid, co-invest in the grid, or mines serve as anchor demand for independ-ent power producers. Hydropower capacity that could be developed through grid-based arrangements with the mining industry in Sub-Sa-haran Africa (excluding South Africa) is estimated at 3-5 GW by 2020.

Non-traditional financiers – such as Brazil, China, and India – often seem attractive to government officials frus-trated about the high cost of private-ly-financed projects and the time-con-suming arrangements needed to set up projects financed by international financial institutions.

Some interesting findings are emerg-ing from an on-going review being undertaken by the Cooperation in International Waters in Africa (CIWA) program at the World Bank on the role of China and Brazil as new fi-

nancers of major water infrastructure in Africa. The review identified 17 hydropower projects between 2000 and 2013 that received some level of finance from Chinese banks. When complete, these projects will add nearly 7 GW of power. The total cost of these projects is about $ 13 billion, of which roughly half is coming from Chinese financiers.

Preliminary results debunk some of the myths circulating about Chi-nese-financed hydropower in Africa.

For instance, Chinese hydropower financing does not extensively use re-source-backed financing in exchange for future mining revenue flows. Contrary to what many people think, several Chinese-financed projects have an international engineering consultancy firm overseeing construc-tion by a Chinese contractor. The anal-ysis indicates that projects backed by non-traditional financiers face many false starts and delays.

All in all, the financial news is mixed. Too many hydropower projects have suffered from false starts. Doing bet-ter in the future will require a push to develop hydropower-specific models to attract private financing. It will also require finding stream-lined structures for mixing and matching various sources of project financing – including Western and non-traditional financiers.

Physical sustainabilityIn the past two decades, hydro-power has shifted from an engi-neering-dominated sector to a more holistic business model. This

broadening of the hydropower business has been at the core of the hydropower renaissance. However, this move to a more integrated ap-proach could over time risk diluting attention to engineering aspects and to physical sustainability.

The physical sustainability of assets depends on the quality of design and construction, as well as on the operation and maintenance of infrastructure after commission-ing. Technical quality starts at the

design phase. Quality construction only happens after comprehensive project preparation.

The World Bank Group has expanded its role in support of project prepa-ration. The bank is, for instance, providing technical assistance to the preparation of the 4,800 MW Inga 3-BC project in the Democratic Repub-lic of Congo. By supporting studies according to international standards, we will help to improve the quality of the project and reduce cost overruns and delays later on.

While the technical quality of con-struction of the new generation of hydro projects have generally been good, we have noticed some excep-tions in which governments awarded a contract but failed to adequately monitor progress. Widespread use of fixed price engineering, procurement and construction (EPC) contracts has increased the visibility of govern-ments and developers on costs but these contracts require strong inde-pendent oversight and control.

Operation and maintenance of hydropower infrastructure will gain urgency as new projects come on-line. In Sub-Saharan Africa, most hydropower projects coming on-line in the coming years are publicly owned and financed with support from donors and non-traditional financiers. New asset management models need to be developed and rolled out as these new dams are commissioned.

In conclusion

Hydropower development has changed. The sector is starting to establish a track record on environ-mental and social sustainability. This will need to be accompanied by a push to develop hydropower specific models to attract private financing. As we embrace the new integrated approach to hydropower, attention to the physical sustainabil-ity of hydropower assets should also be deepened.

Feature

Hydropower capacity that could be developed through grid-based

arrangements with the mining industry in Sub-Saharan Africa (excluding South Africa) is estimated at 3-5 GW by 2020



Top ministers have met seeking to conclude an unprecedented nuclear deal with Iran, on the eve of a deadline aiming to draw the curtain on almost two years of high-stakes negotiations.

After crisscrossing the world since September 2013 chasing a complex accord to cut off Iran’s pathways to developing nuclear arms, exhausted world powers warned Tehran now was the time to strike an accord or walk away.

US Secretary of State John Kerry, who met four times on Sunday with his Iranian counterpart Mohammad Javad, acknowledged that at the eleventh hour the talks still “could go either way”. “All the cards are on the table,” added French For-eign minister Laurent Fabius, as he arrived back in Vienna for the final stretch with Tuesday’s deadline looming.

There is no appetite to extend the talks once again after a series of missed deadlines, especially since the broad outlines of the deal were already hammered out in April.

If all sides were prepared to make hard choices, then “we could get an agreement this week. But if they are not made, we will not,” Kerry warned, adding that if there was “ab-solute intransigence” the US would walk away. “The main question is to know whether the Iranians will accept making clear commitments on what until now has not been clarified,” Fabius added.

The global powers, Britain, China, France, Germany, Russia and the United States, are trying to pin down a deal putting a nuclear bomb out of Iran’s reach in return for lifting a web of sanctions against the Islamic republic.

Some of the hardest issues still left have bedeviled the talks since the start, probing allegations that in the

past Iran sought nuclear weapons, finding a mechanism to lift the sanc-tions, and ensuring Iran can contin-ue to have nuclear energy without the capacity to build a bomb.

“The time is now… We are very close,” said the EU’s foreign policy chief Federica Mogherini, adding the atmosphere was “constructive, positive”.

“I see the political will… now it is a matter of seeing all together if this political will manages to translate into political decisions.”Germany’s Foreign Minister Frank-Walter Steinmeier flew back into the Austrian capital late Sunday, along with Russia’s top diplomat Ser-gei Lavrov. There was no confirma-tion when their Chinese and British counterparts were due, although they were expected on Monday.

SIGNS OF BREAKTHROUGH

Signs were emerging that some of the issues had been resolved by teams of experts who were now waiting for the ministers to sign off on their months of behind-the-

scenes work.In another indication of a break-through senior officials from the UN watchdog, the International Atomic Energy Agency (IAEA), were flying to Tehran for talks.

After talks in Iran last week, IAEA chief Yukiya Amano said the agency could complete by the end of the year a stalled probe into allegations that before 2003, and possibly since, Iran had sought to develop nucle-ar arms. A deal also holds out the prospect of bringing Iran back into the diplomatic fold, amid a myriad of global challenges and conflict.

Zarif said in an English YouTube message that an accord could “open new horizons to address important common challenges”, denouncing the “growing menace of violent extremism and outright barbarism” in a reference to the Islamic State militant group.

“I think it would be very difficult to imagine Secretary Kerry at this point walking away, this close to the finish line,” Iran expert Suzanne Maloney from the Brookings Institution told AFP. “I just don’t think there’s any real likelihood that this collapses.”

IRAN NUCLEAR TALKS

Feature

HIGH- OR

MEDIUM-SPEED

GENERATOR SETS:

WHICH IS RIGHT FOR YOUR APPLICATION?

By Joel Puncochar, Senior Marketing Manager, Cummins Power Generation

Are High-speed Generator Sets Ready for Prime Time?

While high-speed generator sets are most commonly associated with standby emergency power, they offer significant cost and efficiency benefits for prime appli-cations—even when maintenance intervals are taken into account. These advantages can no longer be ignored, as the capacity of high-speed generator sets continues to grow, encroaching into nodes that could be supported only by medi-um-speed generators as recently as a decade ago.

Today, we will address common concerns about the use of high-speed generator sets, particularly for prime applications. Exactly where the line between “high” and “medium” speed is drawn can vary between companies and even individuals. We will be comparing high-speed generator sets operat-ing at 1,500 – 1,800 rpm to medi-um-speed generator sets operat-ing at 1,000 rpm or less.

The Business Case for High-speed Applications

Total cost models vary between high- and medium-speed generator sets, but four major economic com-ponents are central to any compari-son of life cycle costs over time:

n Initial capital costsn Fuel consumption costsn Frequency of service intervals

and associated costs per instancen Frequency of major overhaul

intervals and associated costs per instance

While high-speed generator sets are capable of continuous, indefinite oper-ation, the practical application of these four factors suggests they are most cost-effective for prime power applica-tions where annual run-time is limited to a range from hundreds of hours to a few thousand hours per year. Specific examples where high-speed generator sets tend to offer superior economy and reliability include:n Utility peaking, where generator

sets augment base load power plants;

n Industrial and commercial peak shaving; and

n Temporary or short-term power installations

n Standby

Capital CostThe most commonly cited ad-vantage of high-speed generator sets is the significantly lower initial cost associated with their smaller, more efficient design. Depending on the application, capital costs alone can be as much as 50 percent lower than a medium-speed generator of comparable capacity. This is be-cause power output is a function of speed. Medium-speed systems require a larger engine displace-ment, alternator and chassis to produce a comparable amount of power and thus are heavier, larger and more expensive.

In addition, the smaller size and weight of high-speed generator sets directly translates into installation, transportation and infrastructure cost savings because of smaller size and weight.

Feature


Operating Cost ComparisonsWhile the factors that reduce the up-front costs of high-speed generator sets are well understood, there is less recognition of the additional advantages that reduce their total cost of ownership over time.

Ease of MaintenanceAmong the most common concerns regarding high-speed generator sets are the shorter intervals between maintenance and overhaul cycles, which are often believed to imply higher overall maintenance costs.

This is not necessarily the case in practice because the smaller size of high-speed engines makes them easier and less expensive to over-haul and maintain. In the case of prime applications, total operating and maintenance costs across the

life cycle may not be significantly different compared to equivalent medium-speed systems.

Fuel Economy Many popular medium-speed gen-erator sets have seen no significant technological advancement in fuel economy in the last 30 years, thus fuel consumption is no better than modern high-speed generator sets. These older design generator sets typically deliver around 4.2 kWh per liter of diesel at rated load, but fuel economy is considerably worse for loads of less than 100 percent. Fuel consumption for modern medi-um-speed generator sets can be 3 – 5 percent lower than older products.

By contrast, today’s state-of-the-art, high-speed diesel engines are capable of providing up to 4.3 kWh per liter of diesel from 75–100 percent load. One factor that makes this possible is the fuel injection system used on high-horsepower

engines, capable of injecting fuel at up to 2,200 bar to provide a clean-er—and more efficient—combus-tion formula. Modern high-speed engines also use electronic control modules (ECMs) to continuously optimize engine performance and fuel efficiency.

While a few of the newer medi-um-speed systems provide similar or slightly better fuel efficiency, fuel consumption of many high-speed generator systems across the full range of loads is compa-rable to most traditional medi-um-speed engines. However, fuel consumption is a consideration point when evaluating options for systems that consistently see very long hours of operation. In such cases, the cost premium associated with newer medium-speed designs could be recouped in only a few years. This is less of a factor for shorter-hour applications, where the same cost recovery can take many years.


Feature


Stochastic Optimisation

for Simulation

of Electricity Markets

Sai Koppolu and Dr. Randell Johnson

IntroductionFor a Day-ahead Unit Commitment (UC), System operator must make certain commitment decisions ‘now’ e.g. for slow start thermal plant; and cannot perfectly anticipate certain variables such as load, wind, solar generation, or random outages. So, when a thermal unit is committed:

n It costs money to start the unit especially if it is ‘cold’

n There is a minimum time before it can be taken offline

n There may be restrictions on how long it takes to reach full power

When a thermal unit is de-commit-ted:

n There is a minimum time before it can come online again

n The unit cools and is more costly to start again

Aim is to find the optimal on/off decisions for thermal generating units in the next 24 hours given our knowledge of the form of the uncertainty in these variables and we don’t know the actual future values of these variables but we do know their probability distributions. So, our Objective is to minimize the expected production cost includ-ing start-up costs, fuel costs and shortage cost. Simulating a number of ‘independent samples’ can give ambiguous results because each sample has perfect foresight for example: units on in some samples and off in others; or starting and stopping at different times. Hence, we need a method for making sense

of the uncertainty.

This can be done using Stochastic Unit Commitment (SUC) in PLEXOS 411. Stochastic unit commitment (SUC) refers to the optimization of unit commitment decisions under uncertainty. To enable SUC, first the simulation phase must be running in stochastic mode. For ST Schedule the setting Stochastic Method is set to “Scenario-wise Decomposition” to invoke this mode. Stochastic Unit Commitment in PLEXOS is a:

n 2-stage optimization problemn Dispatch decisions have to be

taken in advance of uncertainty (first stage decision).

n Output: Optimal dispatch deci-sions considering all outcomes of random variables (and their probability).

The Theory of Stochastic Optimisation (SO)

The most widely applied and stud-ied stochastic programming models are two-stage linear programs. Here the decision maker takes some

action in the first stage, after which a random event occurs affecting the outcome of the first-stage decision. A recourse decision can then be made in the second stage that com-pensates for any bad effects that might have been experienced as a result of the first-stage decision. The optimal policy from such a model is a single first-stage policy and a collection of recourse decisions (a decision rule) defining which sec-ond-stage action should be taken in response to each random outcome, where the first (or second) stage decisions must take integer values then we have a stochastic integer programming (SIP) problem which are difficult to solve in general. As-suming integer first-stage decisions (e.g. “how many generators of type x to build” or “when to turn on/off this power plant”) we want to find a solution that minimises the total cost of the first and second stage decisions.

For this purpose, PLEXOS uses sce-nario-wise decomposition.For Example:

Feature


Paths are “decomposed” into discrete scenarios with discrete probabilities. Scenario wise decomposition assigns probabilities to each scenario: Similar paths are combined, Unlikely paths are removed, and Probabilities are recom-puted. For example, it is unlikely that wind can be high during mornings (HI) and, therefore unlikely to be low during the day (M2).

Assume the distribution a> of uncertain inputs can be evaluated as discrete scenarios having probabil-ities the two-stage SIP can be formulated:

Scenario wiseDecompositionof 2-stage SIP Formulation

subject to

Three Wind Periods: n Morning n Mid-day n Night

If wind is low in any period:n 50% chance that wind remains low n 50% chance it increases to mid

If wind is mid in any period:n 33% chance decreases to low n 33% chance it remains mid n 33% chance it increases to high

If wind is high in any period:n 50% chance that wind remains high n 50% chance it decreases to mid 17 possible paths, or “scenarios”

Initial Problem Scenarios Sample Reduction

FEATURE: Stochastic Optimisation for Simulation of Electricity Markets


Copies of the first-stage variable have been introduced for each scenario. The last constraint, known as non-an-ticipativity constraints guarantee that the first-stage variables are identical across the different scenarios. In other words there are certain decisions that must be made ‘now’ and some that are made ‘later’ and the non-anticipa-tivity constraints ensure that we do not anticipate what we cannot see coming when optimising those ‘now’ decisions.

Setting up Stochastic Simulations in PLEXQS®

Set of uncertain inputs ш can con-tain any property that can be made variable in PLEXOS:

n Loadn Fuel pricesn Electric pricesn Ancillary services pricesn Hydro inflowsn Wind energyn Solar, etc.

Number of samples S limited only by computing memory. First-stage variables depend on the simulation phase and remainder of the formu-lation is repeated S times.PLEXOS implements SO in LT Plan, MT Schedule, and ST Schedule for differ-ent types of first-stage decisions.

LT Plan:

n Timing and size of new generator and transmission builds and tim-ing of retirements MT Schedule:

n Hydro storage managementn Emissions ST Schedule:n Centralised day-ahead unit com-

mitment

n Price-based unit commitment (PBUC)

Step-wise procedure:1. Define stochastic input data

using Variable objects (Endoge-nous or Exogenous)

2. Point properties at the Variables3. Set the number of samples you

want to evaluate in the Stochas-tic object

4. Select “Scenario-wise Decompo-sition” in the phase settings e.g. ST Schedule

5. Identify the first-stage decisions6. Set up the results you want to

see including sample results

First-Stage Decisions

First stage decisions in PLEXOS” are identified by setting the properties with names that include the term “Nonanticipativity” which simply means decisions that must be made without the benefit of foresight. Set these properties only for the elements that are first stage i.e. depending on the application, not all Generators or Lines or Storages should have this set (see table).

The non-anticipativity value is interpreted as a financial penalty of allowing foresight in making the first-stage decision. A ‘penalty’ of -1 means “infinity” or, do not allow foresight. Values > 0 enter the ob-jective function and allow decisions between scenarios to vary to an increasing degree (lower penalty means more foresight).

Solving the SIP

Problem is now S times larger than deterministic case; however

there are no more integer varia-bles associated with the first stage (since they are defined to be equal when non-anticipativity is -1). Issue is memory consumption of a large problem. 64-bit version of PLEXOS is popular with those using this tech-nique e.g. common to see problems now with > 4 million non-zeros using > 4GB RAM.

Conclusions

With grids integrating more re-newables there is a clear need to account for uncertainty in decision making. Modern optimisation codes can solve two-stage stochas-tic optimisation problems with integers in both first and second stage. Application to System Operator problem shows efficien-cy improvements can be gained in day-ahead unit commitment problem as SO solution provides a more conservative and robust unit commitment solution for the day-ahead market and also because SO is embedded at the deepest level of the optimisation the outcomes respect all input constraints including security-constrained transmission, fuel, emissions, etc., so one expects the SO- based DA schedule to yield in real-time dispatch:n Less congestionn Less use of emergency genera-

tion/load management solutions n More conservative/robust ancil-

lary services dispatch

References[1] Energy Exemplar Internal presentations on Price Based Unit Commitment (PBUC) with Stochastic Unit Commitment & Stochastic Modelling using Variables in PLEXOS

Class Property Phase Description

Generator Build Non-anticipativity LT Plan Build decisions are first stage

Generator Retire Non-anticipativity LT Plan Retire decisions are first stage

Line Build Non-anticipativity LT Plan Build decisions are first stage

Line Retire Non-anticipativity LT Plan Retire decisions are first stage

Storage Trajectory Non-anticipativity MT Schedule Storage trajectory is first stage

Generator Unit Commitment Non- anticipativity ST Schedule On/off decisions are first stage

Generator Unit Commitment Non- anticipativity Time ST Schedule Number of hours ahead that on/off decisions are first stage

Feature

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