Pimagazine Asia

MAY-JUNE 2018

JAPAN’S ENERGY LANDSCAPE

VOLUME 8 ISSUE 6 Renewable Energy & new power reactor global boiler market Reconstruction in Fukushima Hydrogen Energy for the Future

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EDITORS NOTE Welcome to another bumper edition of Pimagazine Asia.

No matter what, energy is a basic human requirement to move us forward. From electrifying a small village so children can study under a bulb as opposed to a candle, to the simple thing of flicking on the radio, something many of us simply take for granted.

At what cost of energy though? From large hydropower projects that relocate thousands of people, to the building of bigger more efficient power stations. This edition we have a great spectrum of energy solutions, looking at the renewable aspect favoured and pushed by many governments around the world, through to the ugly sister of the energy sector Nuclear. In my opinion I am a strong advocate of Nuclear energy. Nowadays anyhow, its relatively clean, new technology ensures efficient generation; they are cost effective and generate electrical power on a massive scale. Japan are no stranger to knowing what works and forging ahead, reports suggest they are even increasing nuclear capabilities, but we take a look at all aspects in this edition.

I hope you enjoy this edition, it’s rammed with great interviews, articles and overviews that I am sure will keep your attention.

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SEAN STINCHCOMBE EDITOR Power Insider Media Limited Ashford Old Farm, Ilton, Somerset. TA199ED T: +44 (0) 7999826118 E: sean@pimagazine-Asia.com www.pimagazine-asia.com Power Insider media limited are the publishers of pimagazine asia. Pimagazine asia is published bi monthly and distributed to senior decision makers throughout Asia and the Pacific. The publishers do not sponsor or other,vise support any substance or service advertised in this publication; nor is the publisher responsible for the accuracy of any statement in this publication.

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Contents

Inside This Issue FEATURES

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12

20 27

47 48

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Company news

Interview with Robert Giglio – Senior Vice President of Strategic Business Development for Sumitomo SHI FW Japan’s Energy Landscape Fukushima Reconstruction Progress New Developments in Energy Policy Energy System Reform and Bolstering Industry Competitiveness Japan’s Nuclear Capabilities

State-of-the-Art Gas Engine Technology Leaves Room for Customer-Specific Innovation

Japan - Energy System Overview

Korea‘s energy intensive industries

POWER INSIDER MAY-JUNE 2018

Company news

640 MW PROJECT IN TAIWAN STARTED

Van Oord has been designated as preferred contractor for a large 640 MW offshore wind project in Taiwan, enabling the company to take a firm first step towards entering the Asian offshore wind market.

The Yunlin offshore wind project is being developed by German project developer wpd, with Van Oord being responsible for the design, manufacturing and installation of the wind farm’s eighty foundations. Preparations for the construction of the facility, to be located eight kilometres off the coast of the Yunlin prefecture, are being made immediately.

The offshore wind strategy in Taiwan is being driven by a desire to phase out nuclear power. High wind speeds, manageable distances in terms of coastal and water depth and a progressive government policy make offshore wind an attractive energy alternative. The aim of the Taiwanese government is to install 5.5 GW of offshore wind projects by 2025.

The Yunlin project is covered by the Taiwanese government’s feed-in tariff (FIT) programme, enabling it to feed power into the Taiwan network covered by a long-term power contract of 20 years.

The Taiwanese government are aiming to connect about 350 MW to the grid by 2020, with the remaining portion following in 2021.

“In Asia, and especially in Taiwan, large investments are being made in offshore wind” said CEO Pieter van Oord. “The Yunlin project is a great opportunity for Van Oord to show our expertise outside Europe. We look forward to working with our local partners to enable the energy transition of Taiwan”.

Financial Close is expected at the end of 2018. The first foundations will be

available for installation at the beginning of 2020, when installation will commence, consisting of monopiles, scour protection, transition pieces and turbines in succession.

The Yunlin project is the first Van Oord offshore wind project in Taiwan and also its first wind contract outside Europe. However, the company is experienced in dredging and other offshore projects in Taiwanese waters.

At the end of 2017, Van Oord also completed one of Taiwan’s largest land reclamation projects.

SUPPLEMENT OF NATURAL GAS IN INDIA BP and Reliance Industries have set up a joint venture company that aims to supply natural gas to the domestic market from its main production blocks and pursue LNG imports in an effort to boost the share of gas in India’s energy basket, the CEO of the new venture said Vinod Tahiliani, CEO of India Gas Solutions, a 50:50 JV between BP and Reliance, said energy reforms and infrastructure projects undertaken by the Indian government would help transport and distribute gas more efficiently in the coming years, which in turn will boost accessibility of the cleaner fuel in Asia’s fast growing energy market.

“We aim to be the most reliable and competitive gas supplier to the Indian market,” Tahiliani told S&P Global Platts in an interview.

“IGS is actively marketing domestic natural gas produced from Block KG D6 and pursuing options to import and market LNG in India to provide tailor-made solutions to help gas customers manage their risk while receiving predictable and sustainable supply,” he added.

India consumes over 5 Bcf/day of natural gas and aspires to double this

consumption by 2022. Gas currently accounts for under 7% of India’s total energy mix compared with the world average of over 20%. Prime Minister Narendra Modi has set a target to boost this share to 15% in the coming years.

In June 2017, Reliance and BP said they would jointly invest up to $6 billion to develop already-discovered deepwater gas fields off the east coast of India, which would help boost gas output by 30 million-35 million cu m/d (1 Bcf/d) in a phased manner over 2020-2022.

The two companies are also moving ahead with the development of the R-Series deepwater gas fields in Block KG-D6, where Reliance made the biggest gas discovery of India.

“With a strong outlook for sustained GDP growth, combined with increasing oil and gas infrastructure and large volumes of new production slated to come online in the future, we can see a very positive outlook for both oil and gas demand and supply,” Tahiliani said. “By complementing its competitive domestic gas supply with advantaged LNG, IGS will create a unique customer offer,” he added.

GROWTH POCKETS

Tahiliani said that with growing environmental and air quality concerns and the focus on the use of cleaner fuel, India’s city gas distribution (CGD) sector is likely to see strong demand for natural gas as compressed natural gas as well as piped gas in the coming years.

“With a diverse and large customer base — residential, transport, industrial and commercial — CGD offers sustainable and steady demand over a long period,” he said, adding that growth in gas infrastructure could further expand the market with new opportunities such as the use of CNG and LNG in freight.

“Also for the power sector, gas is the

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ideal complement to renewables as it can be a lower carbon, cost-effective back-up to the variability of wind, solar and hydropower generation,” he added.

Highlighting the 2018 edition of the BP Energy Outlook, Tahiliani said that India’s energy consumption is expected to grow at 4.2%/year between now and 2040, fastest among all major economies in the world. Gas will be a key part of this growth, with consumption expected to nearly triple from 5bcf/d to 14 bcf/d.

THE PRICE ISSUE Domestic production currently accounts for half of the country’s total gas consumption, Tahliani said, adding that rising oil prices were unlikely to hit India’s gas demand growth. “With gas price increasingly delinked from oil prices, gas becomes more competitive vis-a- vis alternative liquid fuels with rising oil prices. Demand is expected to increase due to higher economic growth, to ensure less dependency on imported crude and a desire to use cleaner fuel,” he added.

Tahiliani said that historically, controlled gas prices had resulted in lower upstream investment in India.

But the government has now provided marketing and pricing freedom for new gas projects and is also pursuing market reforms such as unbundling “content” from “carriage” and developing a gas hub. “This provides the right climate for investment,” he said. “We believe this will lead to investment in gas infrastructure which will enable further growth in the gas market and substitution of liquid fuels. This in turn will culminate in an increase in investments in exploration and production and augment domestic production.”

Tahiliani said that the development of liquid markets increases competition and results in more efficient pricing and the government’s plan to set up 6

POWER INSIDER MAY-JUNE 2018

a gas exchange was a step in the right direction.

The government is aiming to create a gas hub by October 2018.

Tahiliani said as part of the hub plan, the government was aiming for legal, financial and physical separation of network operators from network users. It would also include non- discriminatory access to gas infrastructure and uniform transmission tariffs.

The government plans to ensure that current domestic gas production is released from price and market controls, which will create liquidity at the hub for price discovery, he said, adding that the gas exchange will ensure transparency and access to information for all market participants.

“It also aims for the inclusion of natural gas under the new goods and service tax scheme, which will help the industry,” he said.

$70 MILLION INVESTMENT IN SOLAR POWER

Fourth Partner Energy, a distributed solar solutions provider, announced a $70 million investment from The Rise Fund, a global impact investment fund managed by TPG Growth.

Founded in 2010 by Vivek Subramanian, Saif Dhorajiwala and Vikas Saluguti, Fourth Partner Energy is a distributed energy management company with in-house capabilities across design, engineering, construction, service, monitoring and financing.

With the fund-raise, the company

plans to accelerate its growth through the RESCO (renewable energy service company) model across industrial and commercial, corporate and public sector clients. The company is also looking to expand its operations to other geographies including SouthEast Asia, West Asia and Africa.

“We believe that The Rise Fund and TPG Growth’s global positioning, deep corporate connections and a longterm commitment to this space will ensure that we become the partner of choice for our customers across the region. We are grateful to our committed workforce of over 170 employees across India and to The Chennai Angels and Infuse Ventures for their strong faith in our vision and their support early in the life cycle of the company,” said Subramanian.

The Rise Fund will leverage the extensive investing and business building experience and track-record of TPG Growth’s global network and team to help Fourth Partner Energy grow and develop the businesses, the report said.

“We are excited to partner with Fourth Partner Energy and their entrepreneurial, customer focused team to help them expand their services and grow their market presence. We are particularly excited about the collinearity of their business whereby the more solar systems they deploy, the more they save their customers money and the greater the positive environmental impact,” said Rick Needham, energy sector lead for The Rise Fund.

Company news Fourth Partner Energy has executed over 1,500 projects across 22 states in India and lists Ultratech, Ferrero, Nestle, Sintex, Raymonds, Pepsi, Mars, ICICI Bank, Coca Cola, D- Mart, Schneider Electric, Myntra, Big Basket, BITS, Symbiosis University, IIM- Bangalore and Indian Railways as some of its key clients. The Hyderabad-based company has previously raised funding from clean technology focused fund Infuse Ventures.

The Rise Fund is the global growth equity and middle market buyout platform of alternative asset firm TPG. The fund primarily invests in education, energy, food and agriculture, financial services, growth infrastructure, healthcare, and technology, media, and telecommunications companies that deliver complete returns.

Last year in October, Mint reported that the impact investment fund has raised $2 billion and that India would remain a priority investment destination for the fund.

With approximately $13.5 billion of assets under management, TPG Growth targets investments in a broad range of industries and geographies.

JA SOLAR AWARDED THE “2018 TOP PERFORMER”

BY DNV GL

JA Holdings Co., Ltd. (Nasdaq: JASO), a world leading manufacturer of high- performance solar power JA Solar Holdings Co., Ltd. (Nasdaq: JASO), a world leading manufacturer of high-performance solar power products, today announced that it was awarded the “2018 Top Performer” by DNV GL, a world renowned independent energy experts and certification institute. This is the third time that JA Solar received the award.

In both 2014 and 2016, JA Solar passed the product tests and received the product certification from PVEL (a wholly-owned subsidiary of DNV GL) and won the “Top Performer”.

DNV GL enjoys strong reputation in the photovoltaic industry. Its annual PV Module Reliability Scorecard Report covers the testing and analysis of module products from various manufacturers, and is considered the most comprehensive assessment of PV module reliability. The honour of “Top Performer” is based on DNV GL’s PV Module Reliability Scorecard. The reliability test covers the complete life cycle

of products, which encompasses IEC thermal cycling, damp heat, ultraviolet radiation, dynamic mechanical load, PID attenuation and hot spot testing. The test results provide potential PV equipment buyers and power plant investors with authoritative references.

JA Solar is committed to the research and development of mass-produced, high-efficiency solar modules, which can effectively reduce the levelled cost of electricity (LCOE).

Whether it is the development and mass production of PERC products, or the introduction of 1500V and bi-facial PERC double-glass modules, JA Solar has always been at the forefront of the industry. DNV GL’s “Top Performer” honour further demonstrates JA Solar’s technical strength and ability to provide high-performance, high-reliability solar products.

HYDROPOWER PROJECTS STARTED TO BE SOLDED

Himachal Pradesh’s plans to harness hydropower in a big way have received a jolt with investors reluctant to take up projects. The directorate of energy had invited global bids for 28 hydropower projects on a build own operate and transfer (BOOT) basis with June 19 as the last date for submitting and opening bids, but so far only three bid documents have been sold.

In the past, three attempts to allot these projects with a combined generation potential of around 2,000 megawatt (MW) have remained unsuccessful.

A majority of the projects are proposed in Lahaul-Spiti, Kinnaur and Chamba districts. Himachal Pradesh has total identified potential of 27,400 MW of which only 10,519 MW has been generated so far. Sources said that inaccessible terrain, tough geographical and climactic conditions coupled with stiff opposition from local people and green activists have made the allotment of these power projects a challenge.

According to sources, bid documents have been sold for the 449 MW Dugar hydroelectric project on Chenab river

in Chamba district and 400 MW Seli hydroelectric project, again on the Chenab. Though one more bid document has been sold, the project has not been identified.

Accepting that there was little response, the state’s energy director, Dr Ajay Sharma, said, “We would hold interactions with bidders for allotment.”

Among the districts identified for hydropower generation, Lahaul-Spiti is going to have the bigger projects where locals are already up in arms against the government.

“We will not allow projects beyond 5 MW capacity in Lahaul-Spiti as mega projects would damage the fragile ecology of the tribal district that otherwise falls in seismic zone IV and V,” said Prem Chand Katoch a resident of Sissu village and president of Save Lahaul-Spiti Society. “We would only allow micro and mini hydro projects on nallahs.”

He added that all gram sabhas would be told not to issue no objection certificates (NOC) to any mega project.

Jispa Baandh Jan Sangarsh Samiti (JBJSS), Lahaul-Spiti, convener, Rigzin Samphel Hayerpa believes mega hydro power projects are not feasible for areas like Lahaul-Spiti as these will not only displace people but also end the scope of tourism and agriculture.

He said that instead of hydro projects, the state government should promote solar and wind energy. “A 1,000 MW solar power project was proposed for Spiti valley but never came up,” he says.

Activist Manshi Asher of Himdhara Collective says that of the major rivers, only the Chenab and Satluj in Upper Kinnaur and Spiti remain free-flowing.

She said that given that these are high altitude regions and are ecologically fragile, these should also be declared eco-sensitive zones and no-go for major construction.

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ROBERT GIGLIO SENIOR VICE PRESIDENT OF STRATEGIC BUSINESS DEVELOPMENT FOR SUMITOMO SHI FW “CFB can bring high value to countries that have large reserves of low quality lignites, coals and waste coals from mining operations, like: Colombia, Germany, Turkey, Russia, South Africa, Vietnam, Thailand, Indonesia, India, China and Australia. Using conventional PC technology, these low quality fuels drive boiler size, cost, and maintenance and plant downtime way up.”

INTERVIEW WITH: ROBERT GIGLIO Can you tell us about yourself, company & areas of expertise?

My name is Robert Giglio and I am a Senior Vice President of Strategic Business Development for Sumitomo SHI FW (SFW). I started with Foster Wheeler about 24 years ago as a R&D engineer, moved my way up the R&D ladder and then crossed over to market forecasting and business strategy.

I am fortunate to have both the technical, market and business experience since developing business strategies involve all three areas. This connection is strongly emphasized in SFW, which utilizes a dedicated committee of R&D, engineering, technology and business leaders to steer the company’s strategy. I have had the privilege of chairing this committee for over 9 years with the role of connecting our technology strategy to our market strategy.

Please tell us about the Sumitomo acquisition.

On June 23rd of last year, Sumitomo Heavy Industries (SHI) acquired Amec Foster Wheeler’s (AmecFW) businesses related to fluidized bed technologies forming a new company named Sumitomo SHI FW, which we like to refer to as SFW. In a lot of ways, you may not notice a big change since SHI bought AmecFW’s three major fluidized bed operating companies in Finland, Poland and China, as well as, nearly the entire global strategic business development group, which are the faces most familiar to our clients. So our clients will be working with many of the same people and offices they already know from the Global Power Group of Amec Foster Wheeler.

The new SFW Company has about

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POWER INSIDER MAY-JUNE 2018

1000 employees with a portfolio of products and services related to fluid bed boilers, gasifiers and scrubbers, as well as, fabric filters, and specialized metallurgical waste heat boilers.

How is this acquisition good for the market and SFW clients?

Before the merger, the CFB boiler and other fluidized bed products resided in AmecFW as part of a larger product portfolio which included a full range of boiler technologies and air pollution control equipment.

Now as SFW, the product portfolio includes only fluid bed boilers, gasifiers and scrubbers, as well as, fabric filters, and specialized metallurgical waste heat boilers. This reduced portfolio will allow us to focus our talent, energy and quality of service exclusively on these products.

As our former CFB licensee, SHI has been our long time business partner and friend with deep knowledge and experience in fluid bed technology. Together, we will be stronger and more focused on these technology solutions than ever before.

The new SFW Company has delivered about one-third of the operating CFB fleet in the world today and holds the most experienced workforce in the global CFB business. We feel this scale of experience coupled with our global delivery network will allow us to offer the highest value to projects, no matter where they are located.

How will the acquisition be beneficial to Asian clients?

Both AmecFW’s and Sumitomo’s CFB boiler Companies have a long experience and large delivery networks in Asia. Now together as one company

we have increased our business focus, execution resources and experience in the Asian market. This provides a direct benefit to our Asian clients since it allow us to offer them more technology solutions and a broader range of delivery scope.

Asia holds the majority of the world’s fastest growing economies. To support this growth, Asia will continue to need high levels of both new and replacement power and steam capacity. At the same time, Asian governments need to find the right balance of power reliability, affordability and environmental impact for power generation.

Our technology portfolio is strongly focused on fuel-flexible, fluidized bed combustion, gasification and flue gas cleaning technologies which will provide the most flexible solutions for our Asian clients.

Why is this acquisition a good fit for both companies?

For over 16 years, SHI had been a licensee of Foster Wheeler’s (FW) CFB boiler technology supplying 70 CFBs in the small to medium size range, mostly to their home market in Japan.

Whereas, Amec Foster Wheeler’s CFB business was truly global, delivering the full range of CFBs from small industrial, CHP and WTE units to very large ultra-supercritical CFBs for utility power plants.

Sumitomo saw the acquisition as an opportunity to go global and greatly expand the size of their CFB boiler market and business. In addition to the CFB boiler technology, the acquisition included AmecFW’s BFB boilers, fluid bed gasifiers, CFB scrubbers, fabric filters, specialized metallurgical waste heat boilers and a broad spec-

trum of aftermarket services. Like the CFB boilers, these additional products and services had unique market positions driven mainly by their fuel, application and operational flexibility.

What is the market potential for SFW’s CFB boiler technology?

Today, about 80-85% of the global boiler market continues to stay with conventional pulverized coal (PC) technology. PC technology hasn’t changed much over the last 50 years and still carries four fundamental disadvantages: limited fuel flexibility, limited reliability, high air emissions and expensive emission control.

Over the last 40 years, SFW’s CFB boilers have redefined the meaning of fuel flexibility, reliability and clean combustion without back-end controls. This has been noticed by utilities, IPPs, developers and industrial companies who have been selecting CFB boilers more and more.

So, the CFB has lots of room to grow into the global boiler market because of the higher values it offers over conventional boiler technology. Even if the boiler market remains flat or even declines, CFB still has an upside growth potential of 80-85%.

Knowing all the benefits of CFBs why hasn’t CFB technology already taken more of the overall boiler market share?

Most of the global boiler market is in the large coal utility sector. Like most other capital intensive sectors, the utility power market is slow to accept change mainly because people tend to stay with what they know and have experience with.

The CFB market is still predominantly in the small to medium size range serving multiple sectors like industrial, WTE, CHP, district heating and cooling. This is where the CFB was born and is the market segment we still serve the most, because our CFBs are best able to reliably fire a diverse and wide range of challenging fuels demanded by these sectors.

But change is happening, our first large 460 MWe supercritical CFB went on-line at the Lagisza plant in Poland 9 years ago. At that time, this was the world’s first supercritical and largest CFB unit in the world. Last year, we commissioned 2200 MWe of our ultra-supercritical CFBs at the Green Power Plant in Samcheok, South Korea. As of today, we have delivered 42 CFBs, each over 200 MWe in capacity, totaling over 12 GWe of electric capacity.

We heard a lot about CFB boiler technology, what benefits does it bring to the market?

Our CFBs offer value in multiple dimensions. Their fuel flexibility provides power generators and industrial plants with the ability to shop for the lowest cost coals, petcokes and lignites keeping power prices at the lowest levels.

They can co-fire carbon neutral fuels up to high levels and employ highly efficient ultra-supercritical steam technology providing a flexible carbon reduction solution without turning to expensive carbon capture and sequestration (CCS) technology.

Our CFB’s can convert the environmental liability of industrial byproducts and waste into valuable power, steam and heat. Their clean burning process produces the lowest emission without needing expensive air pollution control equipment saving millions in plant construction and operating cost.

And finally, they provide these benefits as a highly reliable and dependable base load capacity option to maintain grid stability.

gy source. But unlike wind and solar, biomass plants can provide dependable energy on-demand which is a big advantage for a renewable energy source.

Looking beyond new build thermal plants, our fluid bed gasifiers can be retrofitted to existing PC coal plants to allow them to co-fire the highest levels of carbon neutral fuels and waste, significantly reducing their carbon profile.

Crossing over to the transportation and chemical sectors, these gasifiers can also be integrated into biomass-to-liquid solutions to produce renewable biofuels and green chemicals.

But the 100% biomass solutions are not a good fit for all markets since the logistics and cost of sourcing large and continuous supplies of biomasses and wastes can be very challenging. This is where our CFBs provides the flexibility to co-fire carbon neutral fuels with more dependable fuels like coals, lignites and petcokes that have well established large-scale supply chains.

In essence, the CFB allows each project to set the balance point between carbon emissions, fuel security and cost of energy. Since biomass supplies

Sumitomo SHI FW built the 74 MWe cogeneration facility at the Petropower Plant in Talcanuano, Chile, which has been successfully operating since 1998.

How do you see the CFB technology fitting into the global trend of carbon reduction?

Our CFB’s can achieve a closed loop on carbon emissions by fully firing carbon neutral biomasses in both small and large plants. This provides a near net zero carbon solution without going to the expensive and uncertain carbon capture and sequestration (CCS) solution.

Further, biomass is a renewable ener-

also vary seasonally, the fossil fuels can fill in as needed, providing energy security to consumers and financial security to project investors.

How do you see the CFB technology fitting into the global trend of renewables?

Globally we see nearly all markets strongly embracing solar and wind, which offer a true zero carbon solution,

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Dangjin Bio-1 in South Korea, which features our multi-fuel CFB technology, produces 105 MWe of power from palm kernel shells, wood pellets and recycled wood chips.

Our advanced biomass CFB will cleanly and efficienly produce 299 MWe of power from carbon neutral biomass at MGT’s Renewable Energy Plant in Teesside, UK. and with dropping plant prices, renewables are growing faster than ever before.

But like biomass, too much wind and solar may not be a good thing.

We are seeing a growing trend of rising energy costs and declining power reliability in markets that have high penetration levels (over 30%) of wind and solar energy, like in Spain, Germany, and Australia. Without large scale energy storage, grid operators scramble to meet load when the winds die down or clouds and stars cover the sky. They are relying more and more on expensive fast-moving peaker-plants fueled by natural gas and oil to manage the growing intermittent capacity. The unwanted result of this is a direct relationship of increasing energy prices with increasing wind and solar capacity.

We at SFW have always believed in keeping all technology and fuel options in the generation mix for a balanced energy portfolio. As with any investment, a balanced portfolio provides the best protection against uncertainty of the future. As we all know too well, the energy sector has significant uncertainty related to changing policy, regulation, fuel availability and technology.

This is another area where the CFB provides value, since the same unit can burn the widest range of fuels, it provides the ability to rebalance the fuel mix without having to build another plant. And, it provides these benefits as a highly reliable and dependable base load capacity option to maintain grid stability.

Where do you see the CFB option providing the most value in today’s markets?

CFB can bring high value to countries that have large reserves of low quality

10 POWER INSIDER MAY-JUNE 2018

lignites, coals and waste coals from mining operations, like: Colombia, Germany, Turkey, Russia, South Africa, Vietnam, Thailand, Indonesia, India, China and Australia. Using conventional PC technology, these low-quality fuels drive boiler size, cost, maintenance and plant downtime way up.

After a long difficult experience with these fuels, many countries simply turn to importing high quality coals or LNG. Today, CFB technology has been proven at the large scale to economically, cleanly and reliably convert these low rank fuels into power and steam, lowering the countries energy cost and improving their energy security.

The CFB technology also keeps the door open for co-firing coals, petcokes

and biomass from either import or domestic sources, when prices or regulations is right, so you don’t have to lock yourself into one fuel source.

In broader Asia, over the last 10 years, high moisture sub-bituminous Indonesia coal exports have exploded, driven by deep price discounts in the 1540% range. The same CFB boiler can fire the full range of these fuels with heating values spanning the 50003900 kcal/kg range, as well as, high quality Australian coals in the 55006000 kcal/kg range, capturing the full arbitrage of this fuel market. PC plant operator are forced to trade reduced plant output, higher downtime and maintenance cost to capture a much smaller range of these fuels. Staying

with PC technology, the only other option is to build another PC plant designed for another narrow fuel range.

India has very low quality domestic coals, which represents their most affordable energy source. Plant operators have struggled for years to burn these coals with conventional PC technology and like Turkey has turned to importing higher quality, more expensive coals.

Concerned about fuel security and raising energy costs, India’s government has begun prioritizing the use of domestic coal over imported coal for future power projects. Some projects are forced to burn a mix of Indonesian and domestic coals, which is a struggle for PC boilers. CFB technology dovetails perfectly with the country’s energy goals and objectives, including India’s ultimate goal for being energy independent.

Japan is another good example where CFB technology can make a difference. The energy situation in Japan is critical right now, given that the country has shut down most of their nuclear power plants. The huge power gap is being filled with expensive LNG and liquid oil. Coal is a very economically attractive base load alternative for Japan.

Historically, Japan has been firing the most premium grade 6,000 kcal/kg Australian coals in its fleet of ultra-supercritical PC boilers to achieve the highest plant efficiency to minimize operating cost. Here, the CFB option can provide high plant efficiency with ultra-supercritical designs, but more importantly, can tap into the much higher cost savings of utilizing lower cost, lower quality Indonesian coals.

Further, we are seeing a declining supply of premium coals globally, limiting supplier competition and Japan’s negotiating position. Large utility scale CFBs would break Japan out of this fuel procurement box.

What trends have you been seeing in the biomass energy markets?

Over the last 10 years, we have witnessed a competition for clean wood between the energy, construction, and furniture industries. After successful lobbying by the construction and furniture industries, governments have shifted their biomass energy programs away from clean woods toward lower quality, recycled and demolition

woods, as well as, agricultural waste streams and byproducts like palm kernel shells and bagasse.

These fuels are much more difficult to burn due their higher level of corrosive alkalis, chlorine and non-combustible debris. Responding to this change in policy, we developed robust CFB designs to help our clients utilize these more challenging fuels.

The impact of this change in policy can

The 510 MWe Soma Power Plant is the largest CFB project ever awarded in Turkey and features two of Sumitomo SHI FW’s CFBs. best be seen at the low end of the size scale (50-100 MWe), where we are seeing a growing market for multi-fuel CHP plants. As an example, we have recently delivered a CFB to a 75 MWe CHP plant that will provide power and heat to the town of Zabrze in Poland.

The plant will be fueled by locally sourced municipal waste, biomass and coal. It is a sustainable, closed-loop energy solution providing energy security, waste recycling and low carbon emissions at the community level.

In Korea and Japan, we are seeing a number of similar multi-fuel power and CHP plants using a combination of local waste and recycled woods, as well as, imported biomass pellets and agricultural byproducts. In Dangjin, Korea, we recently provided a CFB to a 105 MWe power plant in Dangjin, Korea that fires wood pellets, recycled furniture chips, coal and imported palm kernel shells. This plant originally fired mostly coal, until the government changed its fuel import policy.

At the large end of the scale (150300MWe), we are seeing some govern-

ments supporting large scale utility power projects fueled by dedicated biomass and agricultural sources. In Polaniec, Poland, we recently built a 200 MWe power plant that fires biomass and agricultural byproducts and in Teesside, UK we are building a 299 MWe plant that will fire imported wood pellets from North America.

Why do clients choose SFW’s CFBs more than other CFB? Unlike many of our competitors, nearly our entire business is centered around the supply and service of CFB boilers allowing us to focus nearly all our energy, talent and R&D on CFB technology.

Over the last 40 years, we have supplied nearly 500 CFB boilers globally, more than all other suppliers.

We stand out from our competitors due to our experience and constant technology advancement.

Because we have fired the most diverse range of fuels in CFBs, we have learned the most about what works and what doesn’t work. This experience is invaluable and allows us, along with constant R&D and product improvement initiatives, to continually advance our designs.

Clients also choose us for our reputation of being there when things don’t go right. Technology evolution includes learning from unexpected outcomes, and when this happens on a commercial project, we have shown clients that we have the ability to find a solution that works both technically and commercially.

Many of our competitors license their CFB technology from others, offering designs that haven’t changed in 10 or more years. Others offer CFB’s as part of a much larger portfolio of products, finding it hard to invest a lot in just the CFB since it is not a major part of their business.

We are fortunate to be in the #1 position in the global CFB market. We don’t take this for granted or believe we can slow down our technology or business improvement initiatives because of it. To ensure clients continue to choose our CFBs more than all others, we continue to improve our technology and delivery models to ensure they remain the most reliable, well-designed and competitive units on the market today.

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11

Japan’s Energy Landscape FUKUSHIMA RECONSTRUCTION PROGRESS

PART I

Reconstruction in Fukushima is steadily progressing. In 2011, the Great East Japan Earthquake and ensuing accident at TEPCO’s Fukushima Daiichi Nuclear Power Station marked a turning point for Japan’s overall energy policy. Despite some hurdles and delays, decommissioning and contaminated water management at the station are advancing in accordance with the Mid-and-Long-Term Roadmap toward the Decommissioning of TEPCO’s Fukushima Daiichi Nuclear Power Station.

ISOLATION

Measures such as pumping groundwater from wells and frozen soil walls – underground walls of ice that block the flow of groundwater– have helped reduce the volume of water flowing into station buildings from around 400 m3/day to around 120 m3/day as of March 2017.

Impermeable walls of frozen soil (land side) Groundwater flows into the buildings are prevented by using ice walls created by freezing soil in the ground around the buildings.

Conceptual drawing of the frozen soil wall

Freezing ducts

PREVENTING LEAKAGE

Impermeable walls along the coast have significantly limited the flow of radioactive materials into the sea. METI has confirmed significant improvements in port water quality since installation.

Impermeable steel wall (sea side) Installation of additional water tanks

A 780-meter-long wall of 30-meter-tall steel pipes was constructed on the sea side of Units 1 through 4, which has been gradually improving the water quality in the surrounding sea area.

REMOVAL

Water tanks for storing treated water are being systematically installed to ensure adequate storage capacity.

Multi-nuclide removal equipment (ALPS) continuously purifies contaminated water generated daily. Treatment of all contaminated water in the station trenches was completed in December 2015, marking a significant reduction in risk.

12 POWER INSIDER MAY-JUNE 2018

CONTAMINATED WATER MANAGEMENT

In September 2013, the Japanese government established basic policy measures to prevent further contamination from water used for cooling the nuclear reactor and groundwater flowing into the reactor building.

These preventive and multi-layered countermeasures are based on three basic principles: 1) isolate groundwater from the contamination source; 2) prevent contaminated water leakage; and 3) remove contaminated water.

TOWARD DECOMMISSIONING

In early 2017, remote-controlled cameras and robots captured direct readings inside the primary containment vessels of Unit 1 and Unit 2.

The devices recorded large amounts of data, including images and radiation dosage levels, marking a major step toward decommissioning. The Japanese government continues to support the development of the technology necessary for decommissioning while bringing together innovative solutions from inside and outside Japan.

NEW DEVELOPMENTS IN ENERGY POLICY

PART II

METI has outlined Japan’s policy positions in a newly compiled report called the Long-term Energy Supply and Demand Outlook for FY2030 (the “Energy Mix”). Its target 2030 energy mix is pictured in Graph 1.

To achieve stable supplies of energy, economic efficiency, environmental feasibility and safety, Japan has adopted the following three strategies: 1) strengthen energy security; 2) implement energy conservation and renewable energy policies that consider environmental concerns alongside growth; and 3) balance public interest issues, such as stable supplies of energy and reduced costs, with market liberalization and growing competition.

DECLINE IN GLOBAL UPSTREAM DEVELOPMENT INVESTMENTS

700 600 500 400 300 200

10

20

11

20

12

20

13

20

14

20

15

20

16

20

Oil 3% Renewable Energy Coal 22-24% 26% LNG 27%

Nuclear 22-20%

Due to a slump in oil prices since 2014, the fundamental strength of oil and natural gas development companies has declined and led to a sharp fall in investments in upstream development. Bolstering support for upstream development is a key priority to strengthen the energy security of Japan.

800

0

1

STRENGTHENING ENERGY SECURITY

USD (2015) billion 900

100

G ra p h

17

20

Source: IEA “World Energy Investment 2016”

BOLSTERING SUPPORT FOR UPSTREAM DEVELOPMENT COMPANIES

The Japan Oil, Gas and Metals National Corporation (JOGMEC) Act was revised in 2016 to significantly expand and enhance. JOGMEC’s role of providing risk capital incentives to help upstream development companies invest in new projects.

REALIZING A HIGHLY LIQUID LNG MARKET

Japan is the world’s largest importer of LNG. LNG buying and selling agreements formed by Japanese companies are primarily long-term contracts. However, pricing is linked to crude oil prices and attached destination clauses restrict resale, hindering flexible trading to respond to supply and demand. In May 2016, Japan announced an LNG market strategy to realize a transparent and highly flexible international LNG market. In April 2017, an LNG spot market was opened on the Tokyo Commodity Exchange to improve the reliability of indices and increase transparency.

14 POWER INSIDER MAY-JUNE 2018

RENEWABLE ENERGY FACILITIES IN OPERATION Solar PV

(10,000 kW) 5000

Wind power

Geothermal power

4500

Biomass

3000

9%

5%

2000 1500 1000 500 0

Average annual growth rate

Average annual growth rate

2500

03

20

04

20

05

20

BALANCING ENVIRONMENTAL CONCERNS WITH GROWTH

To realize its Energy Mix Plan, Japan is developing policies that not only achieve comprehensive energy conservation and maximize the introduction of renewable energy, but also reduce the public burden while exploring the future possibilities of hydrogen energy.

REDUCING PUBLIC BURDEN Since July 2012, the capacity of renewable energy facilities in operation has grown at an average annual rate of 29%. Currently, solar energy accounts for the largest share of renewable energy, while wind power, biomass and geothermal energy still have room for growth. The driving force for promoting renewable energy has been the Feed-in Tariff (FIT) Scheme for Renewable Energy, which has spurred a 2.5-fold increase in capacity of facilities in operation since it began four and a half years ago.

However, a growing public burden has limited further gains. The FIT Law was revised in May 2016 in order to (1) eliminate uncommissioned projects and mandate proper project implementation, (2) suppress prices through a tendering system for largescale solar energy projects, and (3) establish medium- and long-term price targets. (Enacted in April 2017)

06

20

29%

Small and medium-scale hydro power

4000 3500

Annual average growth rate

07

20

08

20

09

20

10

20

11

20

Excess Electricity Purchasing Scheme

12

20

13

20

14

20

15

20

Feed-in Tariff Scheme

Renewables Portfolio Standard (RPS) system

HYDROGEN ENERGY FOR THE FUTURE

Japan aims to realize a hydrogenbased society through the following three phases.

Phase 1: Expand use of FCVs, hydrogen stations and Ene-Farms (underway) Phase 2: Introduce hydrogen power generation, establish a large-scale hydrogen supply system (~2030) Phase 3: Establish a CO2-free hydrogen supply system (~2040).

MARKET LIBERALIZATION AND INCREASED COMPETITION

To form an energy market that encourages competition across many different sectors, METI is introducing reform with three key aims: (1) secure stable energy supplies; (2) cut electricity prices; and (3) expand business opportunities for operators and the range of choices for consumers.

Electricity Established in 2015, the Electricity Market Surveillance Commission has examined a regulatory framework that covers retailers, methods for controlling unfair trading in wholesale markets and the future of wheeling charge schemes for transporting energy.

Gas From 2020, a series of phased reforms will kick off the unbundling of regional pipeline networks and the full liberalization of entry into the retail market.

As of May 2017, 190,000 applications have been received for switching contracted suppliers as liberalization steadily progresses.

In addition to promoting efficiency, energy liberalization must benefit households and address issues of public interest. Key ongoing concerns include securing stable energy supplies, which links directly to energy security, as well as ensuring environment protection and universal service.

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15

NUMBER OF FUEL ASSEMBLIES: 392

NUMBER OF FUEL ASSEMBLIES: 615

Dismantling of the building cover completed (November 2016)

Began installation of a platform to access the top floor of the building (September 2016)

NUMBER OF FUEL ASSEMBLIES: 566

Removing fuel from the SFP

CARE FOR EARTHQUAKE DISASTER VICTIMS

As of spring 2017, all area restrictions and evacuation orders* were removed except for the towns of Okuma and Futaba. *Habitation Restricted Areas and Preparation Areas for Lift of Evacuation Order

Areas to which evacuation orders have been issued (Apr 1, 2017)

MUNICIPALITIES WHERE EVACUATION ORDERS WERE LIFTED Municipalities

Date of the lifting of the evacuation order

Tamura City

April 1, 2014

Area 1: Preparation Areas for Lift of Evacuation Order

October 1, 2014

Naraha Town

September 5, 2015

Kawauchi Village

Area 2: Habitation Restricted Areas

June 14, 2016

Katsurao City

June 12, 2016

Minamisoma City Iitate Village

Kawamata Town Namie Town 16 POWER INSIDER MAY-JUNE 2018

Tomioka Town

July 12, 2016

March 31, 2017*

March 31, 2017**

March 31, 2017*** April 1, 2017***

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Electric Power Companies

• Former regular electric power companies (Tokyo Electric Power Co., Inc., Kansai Electric Power Co., Inc., etc.)

• Former wholesale electric power companies (J-POWER [Electric Power Development Co., Ltd.], Japan Atomic Power Co., Inc., etc.)

Electric Power Market (Traditional Regional Monopolies)

Potential Collaboration and Crossover

Electric power sales combined with services from di erent industries

Electricity and gas package sales by gas companies

IT, automobiles, etc.

Electric Power

New Market Entrants

• Electric power companies account for approximately 70% of Japan’s LNG import volume.

Electricity and gas package sales by gas companies

Gas sales combined with services from di erentindustries

Potential Collaboration and Crossover

Create a Comprehensive Energy Market

Expand beyond Japan to cultivate and secure overseas markets

City Gas Market (Traditional Regional Monopolies)*

* Includes competition with • Primary gas companies have already secured other types of energy as well around 4.3 million kW of thermal power as regional restrictions generation capacity (equivalent to the amount generated by four nuclear power units).

Gas Companies • Electric power accounts for 20-30% of • Regular gas companies (Tokyo Gas Co., consolidated operating income of two Ltd., Osaka Gas Co., Ltd.) major gas companies.

• Gas pipeline service providers (INPEX, JAPEX)

New Market Entrants

Collaboration with Other Industries

Petroleum, LPG, etc.

2015 Organization for Cross-regional Coordination of Transmission Operators (OCCTO) established 2016 Full liberalization of retail electricity markets 2020 Legal separation of the power transmission/distribution sector

City Gas 2017 Full liberalization of retail gas rates markets

2020 Legal separation of the commercial pipeline sector (3 major companies

ENERGY SYSTEM REFORM AND BOLSTERING INDUSTRY COMPETITIVENESS

PART III

Japan’s energy companies can help realize safe and stable supplies of energy, improve economic efficiency and achieve environmental feasibility on a global scale.

INDUSTRY TRENDS: DOMESTIC ELECTRIC POWER AND GAS

Liberalization of the electric power retail sector has attracted new market entrants from different industries and spurred competition.

Crossover between the electricity and gas markets is now possible, which will encourage the development of companies able to offer a comprehensive range of energy services.

18 POWER INSIDER MAY-JUNE 2018

COMPANY PROFILE

FY2020 FORECAST

JERA

LNG import volume

(million t) 50 40 30 20

JERA electric power generation capacity Domestic: 90% Overseas: 10%

JERA

KOGAS (Korea Gas Corporation, Korea)

Tokyo Gas

ENGIE electric power generating capacity EU: 30% Outside the EU: 70%

Korea Electric Power Corporation (Korea) ENGIE (France)

10 CPC Corporation (Taiwan) Kansai Electric Power 0

10

Taiwan Power Company (Taiwan) 20

30

40

Enel (Italy)

50

60(million kW)

Thermal power generation capacity (gas, coal)

Source: Prepared by Agency of Natural Resources and Energy with materials provided by JERA.

JERA was established in 2015 with joint investments from TEPCO Fuel & Power and Chubu Electric Power.

JERA aims to integrate and reorganize each function of its thermal power generation business by FY2019 to become the world’s largest energy company for both LNG procurement and thermal power generation. Combining both gas- and coal-fired plants, JERA’s electric power generation capacity will grow to equal that of France’s ENGIE, a major player in gas-fired power generation in Europe. (2020 estimate)

INDUSTRY TRENDS: DOMESTIC AND OVERSEAS PETROLEUM

Domestic oil refiners and primary distributors are actively restructuring their businesses by consolidating refineries and rationalizing distribution. Other initiatives include strengthening the international competitiveness of domestic refineries through collaboration in petrochemicals, as well as developing business in overseas markets and other energy industries.

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Japan’s Nuclear Capabilities ASSESSING NUCLEAR POWER IN JAPAN

∎ Japan needs to import about 90% of its energy requirements. ∎ Its first commercial nuclear power reactor began operating in mid-1966, and nuclear energy has been a national strategic priority since 1973. This came under review following the 2011 Fukushima accident but has been confirmed. ∎ Up until 2011, Japan was generating some 30% of electricity from its reactors and this was expected to increase to at least 40% by 2017. The prospect now is for two-thirds of this, from a depleted fleet. ∎ Currently 42 reactors are operable. The first two restarted in August and October 2015, with a further five having restarted since. 17 reactors are currently in the process of restart approval. ∎ Japan in 2015 produced 1041 TWh of electricity, 409 TWh from natural gas, 343 TWh from coal, 103 TWh from oil, 91 TWh from hydro, 41 TWh from solar and wind, 41 TWh from biofuels and waste, and 9 TWh from nuclear. There were no imports or exports, and final consumption in 2015

20 POWER INSIDER MAY-JUNE 2018

was 957 TWh or about 7500 kWh per capita on average. Total installed capacity was about 324 GWe at the end of December 20151.

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 widespread public protests calling for nuclear power to be abandoned. The balance between this populist sentiment and the continuation of reliable and affordable electricity supplies is being worked out politically.

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.

Nuclear power has been expected to play an even bigger role in Japan's future. In the context of the Ministry of Economy, Trade and Industry (METI) Cool Earth 50 energy innovative technology plan in 2008, the Japan Atomic Energy Agency (JAEA) modelled 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 renewables (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 security 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 government 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.

Earlier in 2011, nuclear energy had 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.

In April 2015 the government announced that it wanted base-load sources to return to providing 60% of the power by 2030, with about one-

third of this being nuclear. Analysis by the Research Institute of Innovative Technology for the Earth estimated that energy costs would then be reduced by JPY 2.4 trillion (USD 20.0 billion) per year compared with the present 40% base-load scenario (renewables being 30%). At the same time, it was reported that 43 coal-fired power projects were planned or under construction, totalling 21.2 GWe and expected to emit 127 million tonnes of CO2 per year. As well as the coal power revival with 20% increased consumption, Japan’s LNG imports increased from about $20 billion in 2010 to $70 billion in 2013. According to a 2011 government report, generation costs per kWh were JPY 9 for nuclear, JPY 10 for wind and JPY 30 for solar. In 2014 the estimates were nuclear JPY 10.1, coal JPY 12.3, LNG JPY 13.7, solar (non residential) JPY 24.3.

The electricity market was deregulated in April 2016 at the distribution level, and the Revised Electricity Business Act 2015 requires legal separation by April 2020 of generation from transmission and distribution. As the first step towards this, the Organization for Cross-Regional Coordination of Transmission Operators (OCCTO) was set up in April 2015 to function as a national transmission system operator (TSO).

All power companies are required to join OCCTO. It will ensure greater interconnection among present utility networks, and increase the frequency converter capacity across the 50-60 Hz east-west divide to 3 GWe by 2021.

OCCTO is expected to invest about JPY 300 billion.

In February 2015 the prime minister said that 80% of Japan’s oil and 20% of its natural gas came from the Persian Gulf through the Strait of Hormuz.

DEVELOPMENT OF NUCLEAR PROGRAM & POLICY 1950-2005

Japan started its nuclear research program 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 – are the basis of nuclear research activities, as well as promoting international co-operation.

Inauguration of the Atomic Energy Commission (JAEC) in 1956 promoted nuclear power development and utilisation. Several other nuclear energy-related organisations were also established in 1956 under this law: the Nuclear Safety Commission (NSC), the Science & Technology Agency; Japan Atomic Energy Research Institute (JAERI) and the Atomic Fuel Corporation (renamed PNC in 1967 – see below).

The first reactor to produce electricity 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 (Magnox) 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) utilising enriched uranium – either boiling water reactors (BWRs) or pressurised water reactors (PWRs) – have been constructed. In 1970, the first three such reactors were completed and

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21

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 licence to build similar plants in Japan. Companies such as Hitachi Co Ltd, Toshiba Co Ltd and Mitsubishi 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 average capacity factor averaging 46% over 1975-77 (by 2001, the average capacity factor had reached 79%). In 1975, the LWR Improvement & Standardisation Program was launched by the Ministry of International Trade and Industry (MITI) and the nuclear power industry. This aimed, by 1985, to standardise 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 establishment through to the late 1990s was the Power Reactor and Nuclear Fuel Development 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, reprocessing high-burnup fuel, mixed-oxide (MOX) fuel fabrication and high-level waste disposal.

A merger of JNC and JAERI in 2005

created 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 Nagoya, Kyoto and Osaka is 60 Hz, served by Chubu (with Kansai & Hokuriku), and there is only 1.2 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 by 2020, funded by the utilities, and METI plans a further increase to 3 GWe in same timeframe.

Early in 2015 METI established OCCTO as a new body to balance electricity supply and demand in wide areas across Japan (see above).

MORE RECENT ENERGY POLICY 2002-2011: FOCUS ON NUCLEAR

Japan's energy policy has been driven by considerations of energy security and the need to minimise dependence on current imports. The main elements regarding nuclear power were: ∎ continue to have nuclear power as a major element of electricity production. ∎ recycle uranium and plutonium from used fuel, initially in LWRs, and have reprocessing domestically.

∎ steadily develop fast breeder reactors in order to improve uranium utilisation dramatically. ∎ promote nuclear energy to the public, emphasising safety and non-proliferation.

In March 2002 the Japanese government announced that it would rely heavily on nuclear energy to achieve greenhouse gas emission reduction goals set by the Kyoto Protocol. A 10-year energy plan, submitted in July 2001 to the Minister of Economy Trade & Industry (METI), was endorsed by cabinet. 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 government 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 liberalisation.* 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% population reduction but with constant GDP. Projected nuclear generating capacity in 2050 was 90 GWe. This would mean

* In November 2002, the Japanese government announced that it would introduce a tax on coal for the first time, alongside those on oil, gas and LPG in METI's special energy account, to give a total net tax increase of some JPY 10 billion from October 2003. At the same time METI would reduce its power-source development tax, including that applying to nuclear generation, by 15.7% – amounting to JPY 50 billion per year. While the taxes in the special energy account were originally designed to improve Japan's energy supply mix, the change was part of the first phase of addressing Kyoto goals by reducing carbon emissions. The second phase, planned for 2005-07, was to involve a more comprehensive environmental tax system, including a carbon tax.

22 POWER INSIDER MAY-JUNE 2018

Difficult industrial wastewater?

Fat, oil, and grease?

High BOD?

Applications

Benefits

 Dairies

 <98% BOD removal

 Soft drinks

 <95% energy saving

 Meat processing

 Low maintenance

 Retrofit existing plants

 Low capex and opex

 Decentralised sewage

 Eco-friendly technology

 Confectionaries

 Modular and scalable

 Breweries

 Easy to operate

 Wineries

 Little or no odour

BioGill is a unique above ground, attached growth bioreactor that delivers highly effective, low cost, and energy efficient water treatment

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23

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 utilised 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 (JAEC) reaffirmed policy directions 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 Democratic 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 disbanded in 2012.

In March 2011 units 1-4 of the Fukushima 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.

POST-FUKUSHIMA ENERGY POLICY CHANGES

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 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 estimated 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

* In April 2007 the government selected Mitsubishi Heavy Industries (MHI) as the core company to develop a new generation of FBRs. This was backed by government ministries, the Japan Atomic Energy Agency (JAEA) and the Federation of Electric Power Companies of Japan. These were concerned to accelerate the development of a world-leading FBR by Japan. MHI has been actively engaged in FBR development since the 1960s as a significant part of its nuclear power business. ** The Atomic Energy Commission (JAEC) and Central Environment Council apparently came under Enecan in 2011, and in 2012 were restored to previous status.

24 POWER INSIDER MAY-JUNE 2018

METI's minister said that electricity costs would need to increase up to 15% while the nuclear plants remained shut.

Meanwhile, costs of nuclear power relative to alternatives were published.

The Institute of Energy Economics of Japan in 2011 put the cost of nuclear electricity generation at ¥8.5 per kWh taking into account compensation of up to ¥10 trillion ($130 billion) for loss or damage from a nuclear accident. Later in the year a draft report for Enecan estimated nuclear generation costs for 2010 to be ¥8.9 per kWh (11.4 US cents).

This included capital costs (¥2.5), operation and maintenance costs (¥3.1), and fuel cycle costs (¥1.4). In addition, the estimate included ¥0.2 for additional post-Fukushima safety measures, ¥1.1 in policy expenses and ¥0.5 for dealing with future nuclear risks. The ¥0.5 for future nuclear risks is a minimum: the cost would increase by ¥0.1 for each additional ¥1 trillion ($13 billion) of damage.

The ¥8.9 figure was calculated based on a model nuclear power plant using average figures from four plants operating over the period since the 2004 estimate, with an output of 1200 MWe and construction costs of ¥420 billion ($5.4 billion). Costs were calculated assuming a discount rate of 3%, a capacity factor of 70% and a 40-year operating life. The 2010 costs for fossil fuel generation, including costs for CO2 measures, ranged from ¥9.5 for

26 POWER INSIDER MAY-JUNE 2018

coal through to ¥10.7 for LNG to ¥36.0 for oil. Projecting forward to 2030 the nuclear cost remains stable but fossil fuels costs increase significantly.

In July 2012 feed-in tariffs (FiTs) were introduced for solar and wind power.

ENECAN PROMISED A “GREEN ENERGY POLICY FRAMEWORK” IS PROMISED BY THE END OF 2012, FOCUSED ON BURNING IMPORTED GAS (LNG) AND COAL, ALONG WITH EXPANDED USE OF INTERMITTENT RENEWABLES. 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. 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 expanded 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 contributor to Japan's record trade deficit of JPY 2.5 trillion ($31.78 billion) in the first half of 2012. The Keidanren (Japan Business Federation) said the Enecan phase-out policy was irresponsible, as did the leadership of the Liberal Democratic Party (LDP).

Four days after indicating general approval of the Enecan plan, the DPJ cabinet backed away from it, relegating it as "a reference document" and the prime minister explained that flexibility was important in considering 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) government promptly abolished Enecan, along with the National Policy Institute, so that METI’s Advisory Committee for National Resources and Energy

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became responsible for formulating energy plans, while MoE’s Central Environment 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 Diet'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 continue, 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 position 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 Atomic Power Co. has two units, and the government had the Monju prototype breeder reactor, an LDP candidate beat the DPJ contender, 237,000 votes to 56,000.

In February 2014 METI presented the proposed new 4th Basic (or Strategic) Energy Plan* with a 20-year perspective to government, which adopted it in April. It said that nuclear energy

* updated every three years, under the Energy Policy law.

28 POWER INSIDER MAY-JUNE 2018

is a key base-load power source and would continue to be used safely to achieve stable and affordable energy supply and to combat global warming.

Two other base-load options – hydro and geothermal – are limited, another is coal, and though cheap, its pollution works against emissions goals and represents a geopolitical risk.

Natural gas/ LNG was designated as intermediate between low-cost baseload 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 presented as a quasi-domestic source that gives stable power at low operational cost and with low greenhouse gas profile. Nuclear power is an "important power source that supports the stability of the energy supply and demand structure," it said, though the degree of dependence on it should be reduced. Used fuel will receive more attention, and the nuclear fuel cycle will be promoted, including R&D on fast reactors.

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 addressed the problem by reducing the 2012 high fixed- price feed-in tariffs (FITs).

In January 2015 the Institute of Energy

Economics, Japan (IEEJ) released a report looking at four electricity scenarios in 2030 and their implications, 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 scenario, compared with 13.5% in 2013.

In June 2015 the government's Plan for Electricity Generation to 2030 was approved. This had nuclear at 20-22% in 2030, renewables 22-24%, LNG 27% and coal 26%. It aims to reduce CO2 emissions by 21.9% by 2030 from the 2013 level, and to improve the energy self-sufficiency rate to 24.3%, from 6.3% in 2012. In July 2015 the government approved the FY2014 Energy White paper (to March 2015). It showed that the percentage of power from fossil fuel had risen from 62% to 88% over four years, and the increased fuel cost due to nuclear shutdowns was JPY 2.3 trillion in FY2011, JPY 3.1 trillion in FY2012 and JPY 3.6 trillion in FY2013 (to March 2014). Household energy expenses had increased by an average of 13.7% over the four years.

In July 2017 the cabinet approved the draft Basic Concept on Nuclear Energy Use, developed over two years

by JAEC, involving public consultation.

It will provide a reference for future decisions about nuclear energy policy.

It outlines eight priority activities in attaining the basic targets for using nuclear energy safely while promoting its benefits. JAEC’s previous policy advice was in July 2005 (see above), but it now plans to review and revise policy every five years.

A draft of the 5th Basic Energy Plan was released in May 2018, with the same electricity percentages as agreed in mid-2015. It presents nuclear power as “an important base-load power source contributing to the stability of the long-term energy supply-and-demand structure,” and states that necessary measures will be taken to achieve nuclear power’s share of 20-22% in the 2030 energy mix. Towards 2050 it proposes moving to a low-carbon scenario.

ELECTRICITY SUPPLY CONSTRAINTS AND CHANGES; POWER PLANT SITUATION, 2011 ONWARDS

The chairman of Japan's Federation of Electric Power Companies (FEPC) warned in May 2011 that the organization 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. However, as noted above, there is a severe constraint on transmission, with only 1.2 GWe of frequency converters available until about 2020.

Under Japanese regulations, the default period between inspections at reactors is 13 months, but changes made in 2009 allow operators to apply to increase this to 18 months. Subject to approval, a five-year introductory 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

30 POWER INSIDER MAY-JUNE 2018

country's inspection requirements a contributing factor to this difference.

Most other countries conduct regulatory checks so that utilities can operate their power plants almost all of the time that refuelling 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 written- 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 periodic 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.

Chubu was spending some JPY 140 billion ($1.7 billion) on seawall defences, which were expected to be complete by the end of 2013 (see following subsection). During the shutdown process for the unit 5 ABWR, a burst pipe in the condenser allowed seawater to enter the main cooling circuit and some 5000 litres reached the reactor itself, but disassembly and inspection to December 2012 revealed no serious corrosion damage to fuel assemblies or other components. It is expected to be ready to restart about mid-2014, subject to NRA clearance.

The other nine units – with a combined capacity of 8826 MWe (20% of total nuclear capacity) – were shut down during the 11 March earthquake 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 Fukushima 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.) In June 2018, Tepco stated that it was likely that the four units at Fukushima Daini would be decommissioned too.

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 DIFFERENCE. After May 2011 the number of operating 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 undertaking increased tsunami and flooding protection for the Hamaoka nuclear 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 expected within the next 30 years. Behind a row of sand dunes measuring between 10 and 15 metres high above sea level, the company has erected a new 1.6 km breakwater wall reaching 22 metres above sea level at a cost of JPY 400 billion. On the main plant site, measures will mitigate gen-

eral serious flooding in case a tsunami overwhelms the breakwater. They include the waterproofing of diesel generator rooms and seawater pumps, as well as the installation of pumps in the building basements. Grid connections are to be doubled, with another set of diesel generators complete with long-term fuel supply installed on ground behind the main plant buildings about 25 metres above sea level.

Spare parts for seawater pumps will be kept in a hardened building and heavy earthmoving capability will be maintained. These works for unit 4 are expected to be completed in September 2016, and for unit 3 a year later.

Hokkaido has built a seawall 1.4 km long and up to 6.5 m high at its Tomari site, which is 10 m above sea level. It was completed in 2014, and one-third of its length is concrete, two-thirds a soil-cement mix. The company plans to add piles reaching bedrock. Japco plans a 1.7 km seawall to protect Tokai 2, requiring 60 m piles in sediments at the north end of it.

In April 2012 Kansai announced that it would spend more than JPY 200 billion ($2.5 billion) over four years on defences 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 operators assessed whether main safety systems could be damaged or disabled by natural disasters beyond the plant design basis. This identified the sheer magnitude of events that could cause damage to nuclear 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 effectiveness 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 accident. 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 diesel generators and seawater pumps that provide the ultimate heat sink for a power plant.

The stage 1 stress test results for individual plants were considered first by 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.

Late in March 2012 NISA had received stage 1 assessments for 17 reactors – 12 PWRs and 5 BWRs. Three of these – Ohi 1&2 and Ikata 3 – had been approved by NISA and two confirmed

by NSC. In September NISA finished reviewing those for six units: Hokkaido’s Tomari 1&2, Kansai’s Takahama 3&4 and Kyushu’s Sendai 1 & 2. Its findings and comments were forwarded to the new Nuclear Regulation Agency (NRA), which is now responsible for approving restarts. It appears that at least 12 stress test assessments

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31

then remained at the review stage, including Hokuriku’s Shika 1&2, Genkai 2, 3&4; Mihama 3; Tsuruga 2; Higashidori 1; Takahama 1; Kashiwazaki-Kariwa 1&7; Ohi 1 and Ikata 1.

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 RESTARTS AND RETIREMENTS

In October 2012 the new Nuclear Regulation Authority (NRA) which had taken over from the Nuclear & Industrial 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. The assessment would be based on safety guidelines in the New Regulatory Requirements formulated by NRA in July 2013 after public consultation. In rulemaking, 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.

Apart from local government consent, the NRA procedures are: • Construction plan application by operator.

• Permission for design change in reactor installation licence.

• Approval of plan for construction works.

• Approval of operational management system and safety programs, and engineering work program.

• Completion of integrated review.

• Inspection before start-up.

• Inspection after start-up.

• Final approval.

The NRA pre-operational inspections, with reference to the engineering work program, took 134 days to complete at Kyushu Electric's 890 MWe Sendai 1127 days at the 890 MWe Sendai 2 and 156 days at Shikoku Electric Power's 890 MWe Ikata 3, the country's three operating reactors at April 2017.

PWR restart applications: In July 2013 four utilities applied for restart of 12 PWR reactors at six sites, two of which

32 POWER INSIDER MAY-JUNE 2018

– 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 assessments in 2012. In 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. In May 2014 NRA added Takahama 3&4 to the priority list. In March 2015 Kansai applied to restart Mihama 3 PWR and Takahama 1&2 PWRs, all with increased seismic rating and tsunami assumptions. In November 2015 JAPC applied for a safety review of Tsuruga 2. Fuel was loaded in to Ikata 3 in June 2016, with 56 fresh fuel assemblies and 101 already-used assemblies (including 16 MOX ones). It restarted in August and resumed commercial operation in September.

grid connected in May, unit 3 in June.

A district court earlier ordered Kansai not to restart Ohi 3&4 in Fukui prefecture due to public concerns. Kansai, with local government support, appealed the ruling. Following the mayor of Ohi giving his consent at the end of August 2017, and the prefecture governer approving in November 2017, Ohi 3 was restarted in March and unit 4 in May 2018.

Kyushu Electric Power restarted Genkai 3 in March 2018. Genkai unit 4 restarted in June 2018 BWR restart applications: Tepco delayed its application for Kashiwazaki-Kariwa 6&7 ABWRs pending negotiation with local government, and lodged it in September 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 local government, prefectural approval is required

Sendai 1 was the first reactor to restart and connect to the grid, in mid-August 2015, followed by Sendai 2 in October, Takahama 3 in February and Takahama 4 in March 2016.

However, a district court injunction then forced Kansai to shut down the Takahama units. Pending resolution of the injunction, Kansai removed the fuel from both units. The Osaka High Court lifted the injunction in March 2017. The two Takahama units were re-loaded in April-May 2017, unit 4 with four MOX fuel assemblies among its 157, and unit 3 including 24 MOX assemblies. Unit 4 started up and was

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 superstructure of three units there.

Tepco is setting up a new emergency response centre (ERC) near units 5, 6&7 at the Kashiwazaki-Kariwa plant, designed for 1.5 times the 1209 Gal peak ground acceleration assessed for that location (compared with 2300 Gal for the area of units 1-4). It expects the new ERC to be operational in mid2018. Tepco said in May 2017 that it

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STATUS OF RESTART APPLICATIONS AND SAFETY REVIEWS hopes to restart units 6&7 by March 2020, units 1 and 5 by March 2022, and to return units 3&4 to service by March 2025, then to restart unit 2 a year later. In October 2017 the NRA confirmed that units 6&7 met the new regulatory standards â&#x20AC;&#x201C; the first BWRs to do so. While units 1, 6&7 have been shut since shortly after the Fukushima accident in 2011, Kashiwazaki-Kariwa 2, 3&4 have been shut since a major earthquake in Niigata prefecture on 16 July 2007.

In December 2013 Chugoku applied for assessment to restart its Shimane 2 reactor, and Tohoku applied for Onagawa 2, both also BWRs. Both companies had obtained local government 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 Hamaoka 4 BWR, following completion of a major sea wall. It applied to restart unit 3 there in June 2015, subject to completing work to conform with NRA regulations, local government agreement, and community acceptance.

Seismic rating is 1200 Gal. Hamaoka 5 (1360 MWe ABWR) will not be ready to restart with the other two, due to a seawater leak through the condenser

34 POWER INSIDER MAY-JUNE 2018

After NRA final approval and local government approval, unit 1 connected to grid 14 Kyushu Sendai 1&2 July 2013 Oct 2014 August, unit 2 on 21 October 2015. Unit 2 shut down for steam generator replacement over four months in mid-2018.

After NRA final approval and local govt approval, unit 3 grid connection 1/2/16. Unit 4 restarted end Feb 2016.

Both then shut down due to court Kansai Takaha ma 3&4 July 2013 Oct 2014 injunction. Removed fuel in AugSept 2016.

Injunction lifted March 2017. Reloading fuel from April 2016. Unit 4 restarted and grid connected in May 2017, unit 3 in June 2017.

PWR Upgrade plan approved by NRA, April 2015, NRA final approval, unanimous resubmit local govt. approval, agreed seisShikoku Ikata 3 July 2013 May 2015 mic rating Ss 1000 Gal. Back on and March grid 15 August 2016, commercial 2016 operation Sept 2016.

NRA approved upgrade plans, works completed, Ss increased to 856 Gal. NRA approved construction plans Aug 2017. Unit Kansai Ohi 3&4 July 2013 3 restarted March 2018, commercial operation April 2018. Unit 4 restarted May 2018.

After NRA and local government approval, unit 3 restarted March Kyus hu Genkai 3&4 July 2013 2018, commercial operation May. Unit 4 restarted June 2018.

Operating total PWR: 8 (first five all 870-890 MWe gross, next ones 1180 MWe gross) in May 2011 needing further remedy, and in 2016 an application for a safety review is expected. 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 to then.

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. From FY 2011 to March 2017 the total cost is estimated at JPY 1900 billion ($17.4 billion) for eight companies, according to a JAIF survey. In FY 2015 the expenditures to meet new regulatory requirements were JPY 267 billion ($2.4 billion) â&#x20AC;&#x201C; about one-quarter of total nuclear- related expenditures for six utilities. The NRA aimed to increase its relicensing staff to about 100 people, to shorten the envisaged six-month review timeline.

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STATUS OF RESTART APPLICATIONS AND SAFETY REVIEWS

PWR

Hokkaido

Tomari 1-3

July 2013

Kansai

Mihama 3

March 2015

Kansai

Takahama 1&2

March 2015

JAPC

Tsuruga 2

November 2015

Tepco

Kashiwazaki Kariwa 6&7

September 2013

EPDC/ J-Power

Ohma 1 (under construction)

December 2014

NRA reviewing

Chugoku

Shimane 2

December 2013

NRA reviewing.

December 2013

Tohoku

Onagawa 2

Chubu

Hamaoka 4

Chubu

Hamaoka 3

February 2014 June 2015

JAPC

Tokai 2

May 2014

Toho ku

Higash idori 1 June 2014

Hokuriku

Shika 2

BWR

August 2014

Seismic approval finalised.

NRA has approved upgrade plans (and given licence extension).

Work program filed with NRA. NRA compliance approval, seismic rating Ss increased to 700 Gal, expect restart 2019 following licence extension.

Company says ground motion Ss is 800 Gal, but NRA has expert report suggesting seismic problem.

IAEA OSART review to mid- July 2015. Agreed Ss 1200 Gal for units 5-7 in Jan 2016. (2300 Gal proposed for southern part of site with units 1-4.) Revised application Aug 2017. NRA approval for restart January 2018. Tepco expects restart April 2020.

NRA reviewing, Ss 1000 Gal agreed Aug 2017, construction work by March 2021, restart then.

NRA reviewing, local govt opposed to restart.

NRA reviewing.

NRA reviewing, Ss 900 Gal agreed Oct 2016, needs seawall. Local governor opposed. Applied for licence extension.

Question re faults nearby, construction work by March 2022.

Safety engineering work to March 2018, NRA review under way but concern re seismic fault.

Operating total BWR & ABWR: 0 Total all applications: 26 (25 operable in 2018)

AS A RULE, IF ONE NUCLEAR PLANT WITH A CAPACITY OF 1 GWE STOPS OPERATION FOR ONE YEAR IN AN AREA WHERE ANNUAL DEMAND IS ABOUT 100 TWH, TOTAL FOSSIL FUEL COSTS INCREASE BY JPY60 BILLION AND THE ENERGY-RELATED CO2 EMISSIONS INCREASE BY 4 MILLION TONNES CO2.

36 POWER INSIDER MAY-JUNE 2018

In July 2016 the Institute of Energy Economics, Japan estimated that seven reactors could restart by the end of March 2017, 12 more in the following year to March 2018, with significant reduction in fossil fuel imports. In relation to local judicial rulings which might hinder restarts, the report noted: “As a rule, if one nuclear plant with a capacity of 1 GWe stops operation for one year in an area where annual demand is about 100 TWh, total fossil fuel costs increase by JPY60 billion and the energy-related CO2 emissions increase by 4 million tonnes CO2 (7% locally). The average electricity unit cost will increase by JPY400/MWh (1.8%).” Decommissioning small old units: In mid-March 2015, METI’s Agency for Natural Resources and Energy (ANRE) revised the accounting provisions in the Electricity Business Act, whereby, the electric power companies can now calculate decommissioning costs in instalments of up to ten years, instead of one-time as previously. This enhanced cost recovery provision was to encourage the decommissioning of older and smaller units.

A few days later, Kansai announced that Mihama 1&2 PWRs (320 & 470 MWe net) would be retired, and Japan Atomic Power Co (Japco or JAPC) said it would decommission its Tsuruga 1 BWR (341 MWe), all in Fukui prefecture. Then Chugoku Electric Power Co announced the decommissioning of its Shimane 1 BWR (429 MWe net) in Shimane prefecture, and the Kyushu Electric Power Co did the same for its Genkai 1 PWR (529 MWe net) in Saga prefecture. By October 2015 all would be more than 40 years old, so that major expenditure on upgrades would be hard to justify even though all of them already had life extension approvals. Then in March 2016 Shikoku announced that Ikata 1 (538 MWe net) would be retired, due to the estimated JPY 170 billion cost of upgrades required on the 39-year-old unit for licence extension to 60 years.

Announcement of Ikata 2’s retirement followed in March 2018.

In May 2015 the NRA said that three faults running below Shika 1 (505 MWe BWR) may still be active. In July 2015 its expert panel said that activity could not be ruled out, and in April 2016 the NRA said that the fault could be active. Hokuriku is seeking review of the finding.

Tepco is considering the future of three Kashiwazaki-Kariwa reactors – units 2, 3&4. These have been shut down since a major earthquake in July 2007. The mayor of Kashiwazaki wants Tepco to close one unit as a condition of his approval to restart units 6&7.

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, 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 imported fossil fuels since the Fukushima accident. In FY 2012 the additional fuel costs to compensate for idled nuclear 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 almost 15 GWe of coal-fired generating capacity were reported.

At the end of 2013 the Japan Business 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 balance 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 recognise 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 Federation (Keidanren), the Japan Chamber

of Commerce and Industry, and the Japan Association of Corporate Executives (Keizai Doyukai) – submitted 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 April 2015 the Institute of Energy Economics, Japan (IEEJ) said that an important economic role of nuclear power in the past was to reduce extreme dependence on imports, and this policy had saved Japan from sending ¥33 trillion ($276 billion) overseas. “We are effectively living on these savings and we may lose about two-thirds by 2020 if we stay on this course,” due to the “drain of national wealth” caused by ¥3.6 trillion ($30 billion) being spent on imported fuel each year simply to compensate for idled reactors.

In early 2014 some 92 mostly very old oil-burning generation plants were running to full capacity, and these will be the first to shut down, due both to age and cost of running with imported oil.

In March 2017 METI announced that the new levy on household electricity bills to support feed-in tariffs for renewables would be increased

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37

to JPY 9504 (US$ 83) per year for FY2017. The national total borne by consumers would be JPY 2140 billion ($18.77 billion).

In August 2017 the IEEJ in its Economic and Energy Outlook for FY2018 said that it expected at least ten reactors to be online by March 2019, generating 65.6 TWh/yr and representing 7% of total electricity. These would contribute JPY 500 billion to GDP. In a high case scenario, 17 reactors are online then, providing 99 TWh/yr.

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, compared 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 shut-downs, 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 announced 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 0.8% up on 2005 levels and 10.8% higher than 1990, at 1408 Mt CO2. Early in 2015 the Research

IN NOVEMBER 2013, JAPAN’S MINISTER OF THE ENVIRONMENT ANNOUNCED 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.

Institute of Innovative Technology for the Earth said that CO2 emissions were 10.8% above 1990 levels.

Early in 2015 the government was considering a target of 20% reduction in greenhouse gas emissions from the 2005 level by 2030, which might be achieved with 45% of electricity generation being nuclear and renewables.

The ruling LDP was reported to be in favour of 30% CO2 reduction.

In March 2017 the Ministry of Environment (MOE) said that increased construction of coal-fired plants as agreed with METI cut across CO2 emission targets (26% reduction from 2013 by 2030), and it urged utilities to employ CCS technology.

REACTOR DEVELOPMENT, 1970 ONWARDS

In the 1970s a prototype Advanced Thermal Reactor (ATR) was built at Fugen. This had heavy water moderator and light water cooling in pressure tubes and was designed for both uranium and plutonium fuel, but paticularly to demonstrate the use of plutonium. The 148 MWe unit, started up in 1978, was the first thermal reactor in the world to use a full mixed-oxide (MOX) core. It was operated by JNC until finally shut down in March 2003.

Construction of a 600 MWe demonstration ATR was planned at Ohma, but in 1995 the decision was made not to proceed.

Since 1970, 30 BWRs (including four ABWRs) and 24 PWRs have been brought into operation. All the PWRs, comprising 2-, 3-, and 4-loop versions (600 to 1200 MWe classes) have been constructed by Mitsubishi.

ABWR

The first ABWRs (of 1315 MWe) were Tokyo Electric Power Co’s (Tepco’s) Kashiwazaki-Kariwa units 6&7 which started up in 1996-97 and are now in commercial operation.

These were built by a consortium of General Electric (USA), Toshiba and Hitachi. Four further ABWRs – Hamaoka 5, Shika 2, Shimane 3 and Ohma 1 – are in operation or under construction, and eight of the planned reactors in Japan are ABWR. These have modular construction.

Hitachi-GE talks of its 1500 MWe class “global unified ABWR”, and is developing a high-performance 1800 MWe class ABWR. Hitachi was also developing 600, 900 and 1700 MWe versions of the ABWR 38 POWER INSIDER MAY-JUNE 2018

APWR

The 1500 MWe class APWR design is a scale-up of the four-loop PWR and has been developed by four utilities with Mitsubishi Heavy Industries (MHI) and (earlier) Westinghouse.

The APWR is in the process of being licensed in Japan with a view to the first 1538 MWe units being constructed at Tsuruga (units 3&4). Approval by Fukui prefecture was given in March 2004. It is simpler than present PWRs, combines active and passive cooling systems to greater effect, and has over 55 gigawatt days per tonne (GWd/t) burn-up. It will be the basis for the next generation of Japanese PWRs. The APWR+ is 1750 MWe and has fullcore MOX capability.

MHI is now marketing its 1700 MWe APWR in the USA and Europe, and lodged an application for US design certification in January 2008. The US-APWR was selected by TXU (now Luminant) for Comanche Peak, Texas, and by Dominion for its North Anna plant, though both these projects are on hold. The 1700 MWe EU- APWR was accepted as meeting European Utility Requirements in 2014. (MHI also participated in developing the Westinghouse AP1000 reactor, but after Westinghouse was sold to Toshiba, MHI is developing PWR technology independently.

ATMEA1

The Atmea1 has been developed by the Atmea joint venture established in 2007 by Areva NP and Mitsubishi Heavy Industries to produce an evolutionary 1100-1150 MWe net (3150 MWt) three-loop PWR using the same steam generators as EPR. This has 37% net thermal efficiency, 157 fuel assemblies 4.2 m long, 60- year life, and the capacity to use mixed-oxide fuel only. Fuel cycle is flexible 12 to 24 months with short refuelling outage and the reactor has load-following (100-25% range) and frequency control capability. It has three active and passive redundant safety systems and an additional backup cooling chain, similar to EPR. It has a core-catcher and is available for high-seismic sites.

The first units are likely to be built at Sinop in Turkey, then possibly in Vietnam. Following an 18-month review, the French regulator ASN approved the general design in February 2012. Canadian design certification is under way.

POWER REACTORS OPERATIONAL IN JAPAN Post- Fukushima Planned restart shutdown

Fukushima II-1

BWR

Fukushima II-2

BWR

Fukushima II-3

BWR

FUKUSHIMA II-4

BWR

GENKAI 2

PWR

GENKAI 3

PWR Chugoku

GENKAI 4

PWR

HAMAOKA 3

BWR

HAMAOKA 5

ABWR

Higashidori 1 Tohoku

BWR

Ikata 2

PWR

Ikata 3

PWR

KashiwazakiKariwa 1 KashiwazakiKariwa 2 KashiwazakiKariwa 3 KashiwazakiKariwa 4 KashiwazakiKariwa 5 KashiwazakiKariwa 6 KashiwazakiKariwa 7

1067 MWe 1067 MWe 1067 MWe 1067 MWe 529 MWe 1127 MWe 1127 MWe 1056 MWe 1325 MWe 1067 MWe 538 MWe 846 MWe

TEPCO

April 1982

TEPCO

February 1984 Shutdown*

TEPCO

June 1985

Shutdown*

TEPCO

August 1987

Shutdown*

Kyushu

March 1981

Kyushu

March 1994

April 2018

Kyushu

July 1997

June 2018

Chubu

August 1987

Chubu

January 2005

Tohoku

December 2005

Shikoku

March 1982

Shutdown

Shikoku

December 1994

August 2016

BWR

1067 MWe

TEPCO

September 1985

BWR

1067 MWe

TEPCO

September 1990

BWR

1067 MWe

TEPCO

August 1993

BWR

1067 MWe

TEPCO

August 1994

BWR

1067 MWe

TEPCO

April 1990

ABWR

1315 MWe

TEPCO

November 1996

ABWR

1315 MWe

TEPCO

July 1997

Kansai

December 1976

Kansai

March 1979

Mihama 3

PWR

Ohi 1

PWR

Ohi 2

PWR

Ohi 3

PWR

Ohi 4

PWR

Onagawa 1

BWR

Onagawa 2

BWR

780 MWe 1120 MWe 1120 MWe 1127 MWe 1127 MWe 498 MWe 796 MWe

Kansai Kansai

December 1979 December 1991

Shutdown* 2024

2022

2036 Shutdown Shutdown March 2018

Kansai

February 1993 May 2018

Tohoku

June 1984

Tohoku

July 1995

2024

* In June 2018, Tepco stated that it was likely that all four units at Fukushima Daini will be decommissioned.

Japanese reactors under construction

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39

POWER REACTORS OPERATIONAL IN JAPAN Post- Fukushima Planned restart shutdown

Onagawa 3

BWR

Sendai 1

PWR

Sendai 2

PWR

Shika 1

BWR

Shika 2

ABWR

Shimane 2

BWR

Takahama 1

PWR

Takahama 2

PWR

Takahama 3

PWR

Takahama 4

PWR

Tokai 2

BWR

Tomari 1

PWR

Tomari 2

PWR

Tomari 3

PWR

Tsuruga 2

PWR

796 MWe 846 MWe 846 MWe 505 MWe 1304 MWe 791 MWe 780 MWe 780 MWe 830 MWe 830 MWe 1060 MWe 550 MWe 550 MWe 866 MWe 1110 MWe

Tohoku

January 2002

Kyushu

July 1984

August 2015

2024

Kyushu

November 1985

October 2015

2025

Hokuriku

July 1993

Hokuriku March 2006 Chugoku Kansai Kansai

February 1989 November 1974 Novembe r 1975

2034 2035

Kansai

January 1985

February 2016

2025

Kansai

June 1985

February 2016

2025

JAPC

November 1978

Hokkaido

June 1989

Hokkaido

April 1991

Hokkaido

Decembe r 2009

JAPC

February 1987

Fukushima II = Fukushima Daini In 2006 NISA ordered Hamaoka 5 and Shika 2 to be shut down due to problems with steam turbine blades. They were then restarted at lower power levels – 1212 and 1108 MWe net respectively. In 2011 Hamaoka 5 reverted to the above net power level.

Shimane 3

ABWR

1373 MWe

Chugoku

Ohma 1

ABWR

1383 MWe

EPDC/ JPower

December 2005, suspended 2011 May 2010, suspended 3/11 to 10/12

Deferred. Seeking permission to apply to NRA Start-up end 2023, comm operation 2024

NEXT-GENERATION LWR

In mid-2005 the Nuclear Energy Policy Planning Division of the Agency for Natural Resources and Energy instigated a two-year feasibility study on development of next-generation LWRs. The new designs, based on ABWR and APWR, are to lead to a 20% reduction in construction and generation costs and a 20% reduction in spent fuel quantity, with improved safety and three-year construction and longer life. They will have at least 5% enriched fuel and a design life of 80 years with 24-month operating cycle, and be deployed from about 2020.

In 2008 the Nuclear Power Engineering Center was established within the Institute of Applied Energy to pursue this goal, involving METI, FEPC and manufacturers. The project is expected to cost JPY 60 billion over eight years, to develop one BWR and one PWR design, each of 1700-1800 MWe. The government, with companies including Toshiba and Hitachi-GE, will share the cost of these.

The PWR is to have thermal efficiency of 40%. Basic designs are to be finished by 2015, with significant deployment internationally by 2030.

Fukushima II = Fukushima Daini In 2006 NISA ordered Hamaoka 5 and Shika 2 to be shut down due to problems with steam turbine blades.

They were then restarted at lower power levels – 1212 and 1108 MWe net respectively. In 2011 Hamaoka 5 reverted to the above net power level.

LIFE EXTENSION AND 30-YEAR REVIEWS

Power reactors are licensed for 40 years and then require approval for life extension in 10-year increments.

At 30 years, the regulator must review and approve the utility’s ageing management plan for each reactor.

Following the Fukushima accident, the government tightened requirements for approving life extension beyond 40 years, which became the default limit.

Operators can apply for up to 20-year licence extensions from 40 years, allowing possible 60 years as in the USA.

TEN-YEAR EXTENSIONS

The Nuclear & Industrial Safety Agency (NISA) granted a 10-year licence extension for Fukushima Daiichi 1 in February 2011, after technical review and some modifications in 2010. However, this was destroyed in the 2011 accident.

40 POWER INSIDER MAY-JUNE 2018

JAPANESE REACTORS PLANNED AND PROPOSED Tsuruga 3 Tsuruga 4 Higashidori 1 Tepco

APWR APWR

1538 1538

ABWR

1385

Kaminoseki 1

ABWR

1373

Chugoku

Sendai 3

ABWR

1590

Kyushu

ABWR

1385

Tepco

deferred

ABWR

1380

Chubu

deferred

TBD

ABWR

1385

Tohoku

deferred

TBD

ABWR

1373

Chugoku

2018 (deferred 6/11)

TBD

Higashidori 2 Tepco Hamaoka 6 Higashidori 2 Tohoku Kaminoseki 2

JAPC JAPC

deferred deferred deferred 6/2012 (deferred 3/11) 3/2014 (deferred 4/11)

TBD

12,947 MWe

Total Planned (9) Fukushima I-7

ABWR

1380

Tepco

Fukushima I-8

ABWR

1380

Tepco

Namie-odaka Total proposed (3)

ABWR

1385

Tohoku

4/2012 (suspended) 4/2012 (suspended) suspended

4145 MWe

* According to METI FY2010 plan, unless updated by company.

TBD = to be determined.

Tsuruga 3&4 and Tepco's Higashidori 1 were undergoing final safety assessment by regulatory authorities. The units listed as Fukushima I-7&8 and Namie-Odaka will be built elsewhere if at all.

42 POWER INSIDER MAY-JUNE 2018

In March 2010, local government approved life extension to 2016 for JAPC’s Tsuruga 1, which started commercial operation in March 1970 in order to bridge the gap until units 3&4 at Tsuruga come on line. (Construction of the two units was due to start later in 2010 and commissioning of the first was due in March 2016.)

Then Kansai applied for a 10-year licence extension from November 2010 for its Mihama 1 PWR. NISA approved Kansai’s long-term maintenance and management plan for the unit and granted a life extension accordingly in June 2010, which was then agreed by local government. Kansai in July 2011 applied for approval of its ageing management plan for Mihama 2, and NISA granted this in July 2012. In February 2014 the NRA approved Chugoku’s Shimane 1 BWR for ten-year extension. In October 2014 Kyushu applied for a ten-year extension for Genkai 1, but in April 2015 all five of these were decommissioned.

Kyushu applied for life extension of Sendai 1 in December 2103, and this with its ten-year ageing management plan was approved by NRA in August 2015. It applied for Sendai 2 in November 2014 and this was approved 12 months later.

In March 2012 NISA and METI approved Shikoku Electric’s strategy for managing ageing and hence approved operation of its Ikata 2 PWR for 40 years, and in 2014 approved the same for Tepco’s Fukushima Daini 2 and Tohoku’s Onagawa 1 BWR. Despite the approval for continued operation of Fukushima Daini 2, Tepco stated in June 2018 that it is likely all four units of the plant will not be restarted. In June 2014 Kansai sought approval for Takahama 4, which joined Takahama 3 and Kyushu’s Sendai 1 in being reviewed at 30 years and approved for age-related degradation issues. In January 2015 the NRA approved these issues being handled together with engineering work involved with Kansai meeting safety requirements for the restart of the two Takahama units. In November 2015 the NRA approved ten-year licence extensions for Takahama 3&4, as well as for Sendai 2. However, the other reactors cannot be restarted until the NRA assesses that they conform to its 2013 safety guidelines.

PARTICULAR PLANTS: MOST UNDER CONSTRUCTION AND PLANNED

Chugoku’s Shimane 3 was to enter commercial operation in December 2011, but this was delayed to March 2012 because control rod drives had to be returned to the manufacturer for modification and cleaning. The startup date was then deferred until evaluation of the Fukushima accident could be undertaken. It was 94% complete when construction was suspended in March 2011. Chugoku finished building a 15 m high sea wall in January 2012, and then extended this to a total length of 1.5 km to also protect Shimane 1&2.

60-YEAR LICENCES

Kansai applied for 20-year life extension of Mihama 3 and if it had not been granted it was to be finally shut down in December 2016. In October 2016 NRA approved a major works program and in November granted the 20-year licence extension, to 2036. In June 2017 Kansai confirmed its plans for upgrading the reactor by 2020 to take it to 60 years. Much of this will be in improving seismic robustness.

Kansai applied for ten-year cold shutdown of Takahama 2 to defer any decision on its future beyond its 40th anniversary in 2015, and in April 2015 the NRA approved a ten-year life extension for it. In November 2014 the NRA had approved a 10-year life extension for Takahama 1. Then Kansai applied to extend the operating lives of both Takahama units (1&2) to 60 years. The NRA confirmed that they meet new safety standards, with seismic rating upgraded to 700 Gal, and in June 2016 the NRA approved licence extension to 60 years, the first units to achieve this under 2013 revised regulations. They are both progressing through the restart process.

In November 2017 Japco applied to the NRA to extend the licence for the Tokai 2 BWR by 20 years.

With construction now almost complete, Chugoku in May 2018 sought permission from the local government to apply to the NRA for pre-operation safety assessment to enable it to start.

Seismic rating of the unit is 1000 Gal. Chugoku plans to apply for a safety assessment to clear the way for it to start, so that construction can be completed, once unit 2 is cleared to restart.

Seismic rating of the unit is 1000 Gal. The Electric Power Development Corp (EPDC), also known as J-Power, is building its Ohma nuclear plant – 1383 MWe Advanced Boiling Water Reactor (ABWR) – in Aomori prefecture. Construction of unit 1 was due to start in August 2007 for commissioning in 2012, but was delayed by more stringent seismic criteria, then delayed again in 2008, and commenced in September 2009. Seismic criterion is now 650 Gal. Construction was suspended

for 18 months after the Fukushima tsunami, with it 38% complete – JSW had completed manufacturing the major components. J-Power in mid-2012 affirmed its intention to complete and commission the unit, and announced resumption of work in October. In September 2015 the company said that it plans to complete construction by the end of 2021, and have it in commercial operation in 2022. It applied to the NRA for a safety review in December 2014, and in 2016 aspects of the safety review were being negotiated with the NRA. Apart from the Fugen experimental Advanced Thermal Reactor (ATR), this will be the first Japanese reactor built to run solely on mixed oxide (MOX) fuel incorporating recycled plutonium.

It will be able to consume a quarter of all domestically-produced MOX fuel and hence make a major contribution to Japan’s “pluthermal” policy of recycling plutonium recovered from used fuel.

Tepco struggled for two years with the loss of its Kashiwazaki-Kariwa capacity – nearly half of its nuclear total – following the mid 2007 earthquake. While the actual reactors were undamaged, some upgrading to improve earthquake resistance and also major civil engineering works were required before they resumed operation. Overall, the FY2007 (ending March 2008) impact of the earthquake was estimated at JPY 603.5 billion ($5.62 billion), three quarters of that being increased fuel costs to replace the 8000 MWe of lost capacity. The Nuclear & Industrial Safety Agency (NISA) approved the utility’s new seismic estimates in November 2008, and conducted final safety reviews of the units as they were upgraded and then restarted, the first in May 2009. Tepco undertook seismic upgrades of units 1 and 5, the two oldest, restarting them in 2010.

In 2011 a one-kilometre southern seawall was constructed, but apparently some of this is on sediments and assumed Ss of 650 Gal. However the southern part of the site, with units 1-4, has proposed Ss of 2300 Gal. Units 5-7 are rated 1200 Gal since January 2016.

Review of earthquake design criteria meant that construction of Tepco’s Higashidori 1&2 and Fukushima Daiichi 7&8 were delayed, requiring investment in coal-fired (1.6 GWe) and gas plant (4.5 GWe of LNG) to fill the gap. However, METI approved Tepco’s

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Higashidori 1 in December 2010 and NISA approved it in January 2011, allowing Tepco to begin work on the site. Work stopped after the Fukushima accident, though JSW started manufacturing major components in 2011 after the accident. Tepco before this had forecast its overall nuclear capacity increasing from 24% of total in FY2007 to 27% of total in 2017, and nuclear output increasing from 23% to 48% of total supply in the same period. It then announced suspension of plans to build ABWR units 7&8 at Fukushima Daiichi. In 2012 it was reported that it could not afford to proceed with Higashidori, and in December 2017 Tepco said it was seeking a partner to build and operate the plant.

The three approved plants are to be allowed to complete construction, despite the government’s plans for scaling back nuclear power by 2040, according to the trade minister in September 2012.

Tohoku’s Higashidori 2 on the adjacent site as Tepco’s was scheduled for construction start in 2016, though the company has yet to decide whether to proceed. The site is in Higashidori-mura, on the Pacific coast, near Mutsu on the eastern side of the Shimokita Peninsula in Aomori prefecture. The company is building a 2km seawall to protect the site.

Chubu’s Hamaoka 1&2 reactors, closed in 2001 and 2004 respectively for safety-related upgrades, remained shut down following the mid 2007 earthquake. In December 2008 the company decided to write them off (JPY 155 billion, $1.7 billion) and

44 POWER INSIDER MAY-JUNE 2018

build a new one there. Modifying the two 1970s units to current seismic standards would cost about double the above amount and be uneconomic.

The 540 and 840 MWe units (515 & 806 MWe net), which started operation in 1976 & 1978, will be replaced by a single new one, Hamaoka 6, to start operating in 2020, though in April 2011 the company deferred construction start until 2016. Hamaoka is the company’s only nuclear site, though it said that it recognizes that nuclear needs to be a priority for both “stable power supply” and environment. However, the shutdown of units 3-5 in May 2011 by government edict for modification has set back plans.

Japan Atomic Power Co first submitted plans for its Tsuruga units 3&4 to NISA in 2004, and after considerable delay due to siting problems, they

TOHOKU’S HIGASHIDORI 2 THE SITE IS IN HIGASHIDORI-MURA, ON THE PACIFIC COAST, NEAR MUTSU ON THE EASTERN SIDE OF THE SHIMOKITA PENINSULA IN AOMORI PREFECTURE. THE COMPANY IS BUILDING A 2KM SEAWALL TO PROTECT THE SITE.

were approved by the Fukui prefecture. JAPC then submitted a revised construction application based on new geological data to NISA in October 2009. The approval process, including safety checks by METI, was expected to take two years, but the process then passed to the new NRA. In December 2012 the NRA said that a fault zone directly beneath the existing Tsuruga unit 2 reactor (operating since 1987) was likely to be seismically active, and in May 2013 it endorsed an expert report saying that the reactor poses a risk in the event of a major earthquake. An international review group investigating the faults with a massive excavation concluded in 2014 that the faults were not active, but the NRA accepted another report in March 2015 saying that there was an active fault, making its restart unlikely. The matter may have implications for the planned units 3&4 and also for unit 1.

JAPC would need to spend JPY 140 billion ($1.75 billion) on civil engineering for site preparation, including land reclamation and a breakwater before construction start for units 3&4.

Construction – estimated at JPY 770 billion (US$ 7.4 billion) – was due to start in March 2012 with commercial operation in 2017-18. This would be the first Mitsubishi APWR plant, with each unit 1538 MWe. JAPC planned to continue operating Tsuruga 1 beyond its scheduled shutdown date of 2010 and obtained an extension of the licence to 2016, due to the delay with the new units. Some of the power will be supplied to Chubu.

Kyushu Electric Power Co. filed a draft environmental statement ith METI in October 2009 for its Sendai 3 plant, also an APWR, but 1590 MWe. The Ministry of Environment told METI that the project was “absolutely essential, not just for ensuring energy security and a stable supply of electricity... but also to reduce greenhouse gas emissions.” Local government has given approval. In 2010 METI began the process of designating it a key power source development project.

Subject to METI and NISA approval, Kyushu expects to start construction in March 2014, for commercial operation in December 2019.

Chugoku Electric Power Co plans to build two Kaminoseki ABWR nuclear power units on Nagashima Island on the Seto Inland Sea coast in Kaminoseki Town, Yamaguchi prefecture. Some site works commenced but then halted after the Fukushima accident – 40%

of the site is to be reclaimed land. The small island community of Iwaishima a few kilometres away has long opposed the plant. In October 2012 Chugoku confirmed its intention to proceed and awaited a safety assessment from the NRA. In August 2016 the Yamaguchi prefectural government renewed a licence for Chugoku to reclaim land for the plant.

Tohoku Electric Power Co planned to build the Namie-Odaka BWR nuclear power plant from 2017 at Namie town in Minami Souma city in the Fukushima prefecture on the east coast, but indefinitely deferred this project early in 2013.

FURTHER PROPOSED PLANTS

In September 2010 Tepco, Japan’s biggest utility, said it planned to invest JPY 2.5 trillion ($30.5 billion) on low-carbon projects domestically by 2020 to generate more than half of its power free of carbon. Most of this capacity will be nuclear. Two ABWR plants for Tepco are listed as planned, and two as proposed.

Early in 2011 Chubu Electric Co announced that it intended to build a new 3000-4000 MWe nuclear plant by 2030, with site and type to be decided.

Beyond the planned Hamoka 6 ABWR, this is listed as 3x1350 units proposed in the WNA Reactor Table.

Following the decommissioning of two

old Mihama reactors in 2015, Kansai and local government have discussed reviving earlier proposals to replace them at that site with units 4&5.

FAST NEUTRON REACTORS

The Joyo experimental fast breeder reactor (FBR) has been operating successfully since it reached first criticality in 1977, and has accumulated a lot of technical data. It is 140 MWt, and has been shut down since 2007 due to damage to some core components.

The upper core structure had to be replaced, and this was completed in 2014.

The 280 MWe Monju prototype FBR reactor started up in April 1994 and was connected to the grid in August 1995, but a sodium leakage in its secondary heat transfer system during performance tests in December 1995 meant that it was shut down after only 205 days actual operation, until May 2010.* It then operated for 45 days but late in August 2010 it shut down again, due to refuelling equipment falling into the reactor vessel. This was retrieved in June 2011 and replaced with a new one, allowing potential restart in 2012. It has three coolant loops, uses MOX fuel, and produces 714 MWt, 280 MWe gross and 246 MWe net.

Monju’s oversight and ownership passed to the JNC (now JAEA), and the Minister for Science & Technology was eager to see it restarted. In September

2014 the NRA approved JAEA’s management reorganisation for Monju, with its restart being contingent upon NRA approval of a new maintenance program. However, in November 2015 the NRA called for the ministry to find a new owner and operator for Monju, due to failure of safety checks. It said that the JAEA was “not competent to operate” Monju. The JAEA responded to NRA officials, asserting: “No entities other than the JAEA can manage Monju.” MEXT was reported to be in favour of persevering with Monju, while METI was keen to scrap it, partly to get rid of the bad image. The Fukui governor reminded the panel that Monju was positioned in the national Strategic Energy Plan to become an international research base for studies on waste volume reduction, the mitigation of danger, and other improvements to technologies related to nuclear non-proliferation. The cabinet rejected a FY2016 budget request from MEXT for JPY 10 billion to prepare Monju for restart. In December 2016 the government confirmed plans to decommission it, despite Fukui local government being adamantly opposed to this. The government cited the need to spend more than JPY 540 billion ($ 4.6 billion) to meet the NRA’s new regulatory standards as its reason for the decision.

The government’s draft decommissioning plan is expected to take 30 years and cost more than JPY 375

* A Supreme Court decision in May 2005 cleared the way for restarting it in 2008, but this was put back to May 2010. METI confirmed early in 2010 that Monju’s seismic safety under new guidelines was adequate, and NSC approved its restart and operation for a three-year period, prior to “full operation” in 2014.

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45

billion ($3.2 billion). This includes JPY 225 billion for maintenance, JPY135 billion for dismantling the plant and JPY15 billion for defuelling to mid2022 and preparations for dismantling.

JAEA also undertakes FBR and related R&D at Oarai in Ibaraki prefecture, near Tokai-mura.

Originally in 1960s the concept was to use fast breeder reactors (FBRs) burning MOX fuel, making Japan virtually independent regarding nuclear fuel.

But FBRs proved uneconomic in an era of abundant low-cost uranium, so development slowed and the MOX program shifted to thermal LWR reactors.

From 1961 to 1994 there was a strong commitment to FBRs, with PNC as the main agency. In 1967 FBR development was put forward as the main goal of the Japanese nuclear program, along with the ATR. In 1994 the FBR commercial timeline was pushed out to 2030, and in 2005 commercial FBRs were envisaged by 2050. This evidently remains the plan: a demonstration breeder reactor of 500-750 MWe by 2025, and commercial 1500 MWe units by 2050.

In 1999 JNC initiated a program to review promising concepts, define a development plan by 2005 and establish a system of FBR technology by 2015. The parameters were: passive safety, economic competitiveness with LWR, efficient utilisation of resources (burning transuranics and depleted

ORIGINALLY IN 1960S THE CONCEPT WAS TO USE FAST BREEDER REACTORS (FBRS) BURNING MOX FUEL, MAKING JAPAN VIRTUALLY INDEPENDENT REGARDING NUCLEAR FUEL.

46 POWER INSIDER MAY-JUNE 2018

U), reduced wastes, proliferation resistance and versatility (include hydrogen production). Utilities are also involved, with CREIPI and JAEA. Phase 2 of the JNC study focused on four basic reactor designs: sodium-cooled with MOX and metal fuels, helium-cooled with nitride and MOX fuels, lead-bismuth eutectic-cooled with nitride and metal fuels, and supercritical water-cooled with MOX fuel. All involve closed fuel cycle, and three reprocessing routes were considered: advanced aqueous, oxide electrowinning and metal pyroprocessing (electrometallurgical refining). This work is linked with the Generation IV initiative, where Japan has been playing a leading role with sodium-cooled FBRs. The JAEA 2006 budget gave a significant boost to R&D on the fast breeder fuel cycle with an increase to JPY 34.6 billion.

Some work has been done by JAEA on reprocessing of used fuel from fast reactors, with higher plutonium levels.

FEPC envisages aqueous reprocessing which recovers uranium, plutonium and neptunium together, and minor actinides being added to the MOX pellets for burning. JAEA is part of a project under the Generation IV International Forum investigating the use of actinide-laden fuel assemblies in fast reactors – The Global Actinide Cycle International Demonstration (GACID).

In April 2007 the government selected Mitsubishi Heavy Industries (MHI) as the core company to develop a new generation of FBRs, notably the Japan Sodium-cooled Fast Reactor (JSFR) concept, though with breeding ratio less than 1:1. This would be a large unit to burn actinides with uranium and plutonium in oxide fuel. It could be of any size from 500 to 1500 MWe. The demonstration JSFR model was due to be committed in 2015 and on line in 2025, and a 1500 MWe commercial unit was proposed by MHI for 2050.

From July 2007 Mitsubishi FBR Systems (MFBR) has operated as a specialist company. It was responsible for a joint bid with Areva for work on the US Advanced Recycling Reactor project and is part of the Japanese involvement with the French Astrid project.

In May 2014 Japan committed to support the development of the French Astrid fast reactor project, and in August 2014 JAEA, Mitsubishi Heavy Industries and Mitsubishi

FBR Systems concluded an agreement with the French Atomic Energy Commission (CEA) and Areva NP to progress cooperation on Astrid. Astrid is envisaged as a 600 MWe prototype of a commercial series of 1500 MWe sodium-cooled fast reactors which is likely to be deployed from about 2050 to utilise the abundant depleted uranium available by then and also burn the plutonium in used MOX fuel. Astrid arises from a 2006 French government commission to the CEA to develop a fast neutron reactor which is essentially a Generation IV version of the sodium-cooled type which already has 45 reactor-years’ operational experience in France.

In 2016 the government’s Conference on Fast Reactor Development met several times to formulate policy. It reiterates the need to promote the nuclear fuel cycle based on the government’s Strategic Energy Plan, as well as R&D on fast reactors to develop world-class technology. Further aims are to commercialize and establish fast reactors as the international standard, while achieving high levels of safety and economy at the same time.

PUBLIC OPINION

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.

A poll taken in February 2015 by the Mizuho Information & Research Institute of Japan asked whether or not the respondent would use nuclear-generated electricity if the costs were the same or less than they were that month, and 67% said “yes”. Only 32% replied in the negative. This contrasts with a number of media polls with voluntary and hence non-representative participation, and the distortion is compounded by a 2012 news media survey finding that 47 of the 50 most popular press outlets in Japan said they were antinuclear. *Sources; www.world-nuclear.org www.iea.org

Japan - Energy System Overview GENERAL INFORMATION Population (2016) GDP (2016)

377 000 km2

8th compared to IEA countries

126.8 million

11.2% of IEA population

4496 billion USD 2010 prices and PPPs

* PPP = Purchasing Power Parities

ENERGY SYSTEM TRANSFORMATION

ELECTRICITY GENERATION: 1017.8 TWH

SUPPLY AND DEMAND 2016 TPES: 423.8 Mtoe, 5% renewables (IEA average 10%)

450

Mtoe

Neti mpor t

16% renewables (IEA average: 24%)

Heat

Tr ansform ation and other losses

Electricity

Gas 41%

Other renewable

300

Biofuels and waste

Commer cial

Natural Gas

Residential

Production

TPES

TFC* (by fuel)

Hydro 8% Solar 4%

Coal

Coal 34%

*Demand data are for 2015

TFC* (by sector)

Geothermal 0.2%

FUEL SHARES COMPARED TO IEA AVERAGE

Fuel TPES (%) IEA average* (%) IEA range (%) Coal 28 17 0-69 Oil 42 36 7-58 Gas 24 27 2-40 Hydro 2 2 0-43 Nuclear 1 10 0-44 Biofuels 2 6 2-27 Wind 0 1 0-7 Geothermal 0 1 0-23 Solar 1 1 0-3 * IEA Average - total supply per fuel / TPES for 29 IEA countries

KEY ENERGY INDICATOR DEVELOPMENT, 1990-2015 140

Index (1990=100)

Population TPES

TFC

100

CO 2 emissions CO2 emissions

80 1990

1995

2000

2005

2010

2015

PRODUCTION AND SELF SUFFICIENCY, 2016 200

Mtoe

3.0%

150

2.0%

100

1.0%

50 0

OilN

atural gas

Coal

0.0%

Self

IEA average (%) 28 2 27 13 19 3 6 0 2

FUEL

Wind 0.5%

IEA range (%) 0-84 0-10 1-51 0-96 0-73 0-26 0-42 0-18 0-13

ENERGY AND CARBON INTENSITY (2016)

ENERGY SECURITY

Production TPES

Electricity (%) 34 7 41 8 2 4 1 0 4

TPES per capita (toe/cap) Electricity consum ption per capita (MWh/cap) Em issions* per capita (tCO2/cap) Energy intensity (TPES) (Mtoe/USD PPP million) Em ission* intensity (tCO2/ USD PPP million)

GDP (USD 2010 prices and PPPs

120

Biofuels & waste 4%

Oil

Indu stry

0

Nuclear 2%

Renewables

Nuclear

Tr anspo rt

150

Oil 7%

Crude Oil Imports Exports Oil Products Imports Exports Natural gas Imports Exports Coal Imports Exports ELECTRICITY Imports Exports

Japan

IEA average

3.34

4.42

8.99

9.88

7.75

94

256

8.69

96

193

ENERGY IMPORT/EXPORT QUANTITY IMPORT/EXPORT COUNTRY 162.1 Mt 0 Mt 39.5 Mt 18 Mt

Saudi Arabia (37.7%) -

United States (20.7%) Australia (24.9%)

116.5 bcm Australia (27.7%) 0 bcm 189.4 Mt 0 Mt 0 TWh 0 TWh

Australia (63.7%) Indonesia (100%)

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Note: 2016 data are estimated So urce: IEA Wo rld Energy B alances 2017

Country size

47

Korea‘s energy intensive industries

S

outh Korea retains industries that are considered highly energy intensive (i.e., petrochemicals, steel etc.), with imported energy sources meeting almost 96% of its energy requirements, as the country lacks sufficient natural resources. In 2016, approximately 528,656 GWh of electricity power was generated in South Korea, with coal representing approximately 40% of total electricity generation. South Korea was ranked as one of the top ten CO2 emission countries in the world. South Korea submitted its Intended Nationally Determined Contribution (INDC) to the United Nations Framework Convention on Climate Change, with the target of substantially reducing Korea’s greenhouse gas emissions by 37% from Business As Usual (BAU) level by year 2030.

Generally, in terms of deployment, the supply of new and renewable energy was 6.08 million TOE for 2009 and 13.2 million TOE in 2015, respectively, with a 2009-2015 CAGR (Compound Annual Growth Rate) of 14%.

South Korea has taken measures to expand the deployment of new and renewable energy. State-owned power generation companies (GENCOs) and independent power producers (IPPs) that generate over 500MW are required to include a certain percentage of renewable energy in their production portfolio. GENCOs and IPPs that meet the 500MW threshold must generate 10% of electricity from renewable energy by 2023. (The mandated RPS 10% quota by 2022 has recently been postponed to 2023, with revised RPS quota % in the intervening years as shown in the below table).

As of 2017, there are 18 companies that fall within the Renewable Portfolio Standard (RPS) quota percentage mandate and are thereby required to include a certain percentage of new and renewable energy in their power production portfolio: Korea Hydro & Nuclear Power (KHNP) • Korea Southern Power (KOSPO) • Korea Midland Power (KOMIPO) • Korea Western Power (WP)

48 POWER INSIDER MAY-JUNE 2018

• Korea East-West Power (EWP) • Korea South-East Power (KOEN, formerly KOSEP) • Korea District Heating Corporation • K-water • SK E&S • GS EPS • GS Power • POSCO Energy • MPC Yulchon Generation • Pyeongtaek Energy Service • Daeryun Power • S-Power • Pocheon Power • Dongducheon Dream Power

According to the 7th Basic Plan for Long-term Electricity Supply & Demand, which was released in 2015, as per power generation energy mix plans in terms of installed capacity, the renewable energy segment is targeted to increase from 7,335 MW in 2015 to approximately 32,890MW by 2029.

Fuel Cell Deployment, Households

Fuel Cell Supply Status Year 2011 2012 2013 2014 2015 Fuel 63,344 82,510 122,416 199,369 230,173 cell Source: Korea Energy Agency, Unit: TOE (Ton of Oil Equivalent)

SUB-SECTOR BEST PROSPECTS

Fuel Cells – With ROKG policy support, this industry is expected to grow in the future. The deployment and supply of fuel cells has increased and has a 2011-2015 CAGR (Compound Annual Growth Rate) of 38%.

Based on government subsidies, the deployment of fuel cells to residential households has modestly expanded.

Moreover, with the Renewable Portfolio Standard (RPS) quota percentage increasing year over year, fuel cells for power generation have sustained consistent deployment in South Korea to date.

Year

2010

2011

2012

2013

2014

2015

Total

Number of Households

957

292

245

232

207

316

2.2

Installation Unit Cost (1,000KRW/kW)

60,0

54,0

51,0

51,0

41,8

37,7

-

Source: Korea Energy Agency, Weekly Brief Issues of Energy (March, 2016)

Fuel Cell Deployment, Power Generation Year 2012 2013 2014 2015 Total Site(s) 3 14 5 4 26 MW 11 104 35 14 163 In collaboration with U.S. solution providers, South Korea’s POSCO Energy has made strides in the stationary fuel cell segment, with the deployment of molten carbonate fuel cell (MCFC) technology. Gyeonggi Green Energy (58.8MW [2.8MW X 21 hydrogen fuel cells], MCFC Technology), situated in Hwasung City, Gyeonggi Province, is considered one of the largest fuel cell parks in the world, with potential capacity to produce power for approximately 140,000 homes. Recently, South Korea completed the 20 MW Noel Green Energy project, located in Sang-am/Seoul. For phosphoric-acid fuel cells (PAFC) technology, previous installations include the Busan International Finance Center, the Korea South-East Corporation (KOEN, previously known as KOSEP), GS Power, and others.

ENVIRONMENTAL SOLUTIONS

In July of 2016, the Ministry of Trade, Industry, and Energy (MOTIE) announced plans to reduce emissions from coal-fired power plants, through the endeavors below. This announcement was in line with public sentiment to improve air quality in South Korea, given the issues with a high concentration of micro-dust in 2016 and again in 2017.

• Close and retire ten coal fired power plants (those at or approaching 30+ years of operation). Enhance efficiency via retrofitting and decrease emissions through emission reduction technology for the other 43 units.

• For 20 units (thermal coal-fired power plants) under and/or planned for construction from the previous 4th to 6th Basic Plan for Long-term Electricity Supply and Demand, stronger and higher emission standards and requirements can be applied.

• The emission reduction efforts can include power plants in the Chungnam region of South Korea, with targets as follows:

In 2016, approximately 200MW of new capacity was added to wind, thereby wind power generation surpassed 1GW in terms of installed capacity. For offshore wind endeavors, Korea Offshore Wind Power (KOWP) is a special purpose company engaged in the Southwest Offshore Wind Project and the construction of a 2.5GW offshore wind farm on the coast of Jeollabuk-do Province. The company is comprised of GENCOs and the public utility giant, KEPCO. KOWP aims to make Korea one of the top three offshore wind energy countries by 2020.

The following is a three-stage plan for KOWP’s Southwest Offshore Wind Project, subject to change: • Stage 1: Develop Test Bed Scale: 80MW, duration 2011~2018 • Stage 2: Achieve Track Record Scale: 400MW, duration 2018~2020 • Stage 3: Develop large Offshore Wind Farm Scale: 2,000MW, duration 2020~

South Korea now recognizes and incentivizes combined, hybrid solar (photovoltaic) & energy storage systems (ESS) installations, by way of giving higher multipliers and weight to the Renewable Energy Certificate (REC). According to the 4th Renewable Energy Basic Plan (2014-2035) which is released every five years, South Korea is targeting to increase percentage shares within the new and renewable energy mix: solar (photovoltaic) power from approximately 2.7% (2012) to 14% (2035). The new and renewable energy share (%) target for wind power is 18.2% (2035).

Demand Response (DR) – Although not applicable to South Korea’s Renewable Portfolio Standard (RPS) quota, Demand Response (DR) has grown substantially since its inception in 2014.

Also known as the ‘Negawatt’ market, electricity users, such as industrial factories and commercial buildings, would save electricity during a specified timeframe and be compensated for saving electricity.

Solar (Photovoltaic) and Wind, installed capacity] Year

2010

2011

2012

2013

2014

2015

Solar (photovoltaic) 650,33

9729,15

71,024,315

1,555,035

2,481,298

3,615,198

Wind

418,713

491,524

583,430

644,793

852,584

366,769

Source: Korea Energy Agency (KEA), Unit: kW

Emission

2015

Target 2030

Improvement (%)

Sulfur Oxides, SOx (ppm)

49

15

decrease by 69%

Nitrogen Oxides, NOx (ppm)

80

10

decrease by 88%

dust (mg/Sm3)

6

3

decrease by 50%

PHOTOVOLTAIC AND WIND

Since the introduction of the Renewable Portfolio Standard (RPS) in 2012, solar (photovoltaic) capacity has increased at a Compounded Annual Growth Rate (CAGR) of 52%, while wind power increased by a CAGR of 20%.

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49

DR SERVICE PROVIDERS

According to the Korea Power Exchange (KPX), as of November 2016, there were 14 qualified Demand Response (DR) service providers (also known as load aggregators) in South Korea: • EnerNOC Korea www.enernoc.co.kr • Gridwiz www.gridwiz.com • Manage On www.kodrm.com • Byuksan Power www.bspower.co.kr • Enercle www.enercle.com • S1 www.s1.co.kr • KT www.kt.com • POSCO ICT www.poscoict.co.kr • Korea ENTEC www.k-entec.co.kr • Others Since its inception in November 2014, the number of Demand Response (DR) consumers or participants has increased 2.5 times, as of November 2016, with diverse industrial sectors represented.

ELECTRIC VEHICLES (EVS)

To deter negative factors associated with conventional gasoline- and diesel-based automobiles, South Korea is expanding efforts to promote the deployment of electric vehicles (EVs), with a target of 250,000 EVs by 2020.

To further this effort, the country is providing purchase subsidy incentives, with plans to increase relevant infrastructure. EV purchase subsidies to incentivize the purchase of eligible EVs are as follows: • National government offers 14 million KRW (US$12,727) in subsidies for the purchase of high-speed EVs. • Local governments also offer EV purchase subsidies, which differ by region. For instance: • Ulleungdo (Island) can offer a subsidy of 12,000,000 KRW (US$10,900) • South Jeolla Province, Suncheon can offer a subsidy of 8,000,000 KRW (US$7,270) • Seoul Metropolitan City can offer a subsidy of 5,500,000 KRW (US$5,000) • Busan Metropolitan City can offer a subsidy of 5,000,000 KRW (US$4,545) Furthermore, as of February 2017, there were approximately 2,526 EV chargers installed across the country (1,139 fast chargers and 1,387 slow chargers). The government plans to increase the number of public EV fast 50 POWER INSIDER MAY-JUNE 2018

Year

November 2015

November 2016

Demand Response Resources (MW) 1,520

November 2014

2,889

3,885

# of Customers

1,519

2,223

861

Source: Korea Power Exchange (KPX), media outlets, etc. chargers to 3,000 by 2020. To date, the Ministry of Environment (MOE), the Korea Electric Power Corporation (KEPCO), and others have been active in increasing EV charging infrastructure across South Korea.

OPPORTUNITIES

As of 2015, KEPCO’s wholly-owned power generation subsidiaries, collectively referred to as the GENCOs, produced approximately 80% of the nation’s power generation, while local Independent Power Producers (IPPs) generated approximately 17% of the electricity. KEPCO is a state-owned power company and is responsible for the nation’s transmission and distri-

THE GENCOS ARE ONE OF THE PRIMARY END-USERS OF NRE PRODUCTS AND SERVICES. IT PRODUCED APPROXIMATELY 80% OF THE NATION’S POWER GENERATION

bution. The GENCOs are one of the primary end-users of NRE products and services. The trend of shifting the power source to NRE will continue under the Renewable Portfolio Standard (RPS) requirements.

The six GENCOs are: • Korea Hydro & Nuclear Power Company (KHNP): www.khnp.co.kr • Korea South-East Power Company(KOEN, formerly KOSEP): www.koenergy.kr • Korea Midland Power Company(KOMIPO): www.komipo.co.kr • Korea Western Power Company(KOWEPO): www.iwest.co.kr • Korea Southern Power Company(KOSPO): www.kospo.co.kr • Korea East-West Power Company (EWP): www.ewp.co.kr Independent Power Producers (IPPs) include, but are not limited to: • POSCO Energy • GS EPS • GS Power • SK E&S • Pocheon Power • Pyeongtaek Energy Service As end-users, the GENCOs and the Independent Power Producers (IPPs) exert strong influence in choosing what NRE core parts to use.

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