Asian Power (September to October 2015)

ISSUE 71 | DISPLAY TO 31 OCTOBER 2015 | www.asian-power.com | A Charlton Media Group publication

Asia’s Nuclear future

US$360P.A.

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Mr. Antonius RT Artono, acting president Director PT. Indonesia Power

The tug-of-WAR over nuclear energy has become a painfully difficult issue

MICA(P) 248/07/2011

country report Malaysia’s RE plans placed under scrutiny

sector Report Opportunities and challenges in nuclear power in Asia

first China trails peers in offshore wind market

ANALYSIS India’s power sector is still stuck in the doldrums

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PAGe 28

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FROM THE EDITOR Nuclear power generation in Asia is seen to increase significantly in the next few decades despite opposition from various entities. While the nuclear meltdown which shook Japan over four years ago slowed down the pace of growth of nuclear installations, the interest has not waned in the region.

Publisher & EDITOR-IN-CHIEF Tim Charlton production editor Roxanne Primo Uy

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In this issue, Asian Power looks into the hefty projects in the pipeline over the next decade amongst key players in the region – China, Japan, and South Korea. Our channel checks show that at least 40 nuclear power plants are expected to come online across Asia. Considering that this volume can easily turn Asia into the world’s nuclear powerhouse with nearly half of new capacity expected to come from the continent, we sought the experts’ view on current coordination efforts among nuclear operators with regard to nuclear safety issues.

We also have comprehensive reports on the latest trends and challenges in Malaysia, Japan, and Indonesia’s power sectors. We found out that the key challenge for the pro-nuclear Japan government is how to demonstrate to the public that they have taken the right actions to improve the preparedness of their nuclear plant and that the plants are under effective scrutiny through the new regulatory regime.

Also featured in this issue is Mr. Antonius RT Artono, acting president director & director of business development & commerce at PT. Indonesia Power. Find out what he has to say about Indonesia’s ambitious target to meet 10 GW additional power capacities in the next 10 years.

Enjoy!

Tim Charlton

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ASIAN POWER 1

EDITORIAL CONTENTS

12

ceo interview PT. Indonesia Power reveals plans to meet 10 GW additional power capacities by 2025

FIRST

26

Country Report 3: Indonesia PPPs fail to translate to more power projects in Indonesia

20

sector report: Nuclear power in asia Asia expected to account for almost 43% of nuclear power by 2030

ANALYSIS

06 China trails peers in offshore wind market 06 Coal-fired electricity under threat

28 Why India’s power sector is still stuck in the doldrums despite government’s efforts

07 Asia’s construction constrictions 08 Four policies to reduce Asia’s power demand

14 Malaysia’s RE plans placed under scrutiny

OPINION 32 JOHN GOSS: Maximising the utilisation of green

COUNTRY REPORT

energy in China

18 Electricity sector deregulation one of the keys to Japan’s plan of resurrecting nuclear power

PETER HOPPER: The future of Hong Kong’s electricity sector

Published Bi-monthly on the Second week of the Month by Charlton Media Group 101 Cecil St. #17-09 Tong Eng Building Singapore 069533

2 ASIAN POWER

For the latest news on Asian power and energy, visit the website

www.asian-power.com

News from asian-power.com Daily news from Asia most read

IPP

650MW Malaya thermal power plant up for bids The Power Sector Assets and Liabilities Management Corp.

(PSALM) will auction off the one-year operation and maintenance service contract for the 650MW Malaya thermal power plant in July.

According to Maybank ATR Kim Eng, PSALM has allotted a PHP457.28m budget for the contract.

IPP

Asia’s renewables capacity set to double by 2024 It has been noted that Asia’s non-hydro renewables capacity is set to more than double over our 10-year forecast period to 2024, accounting for roughly 47% of total global renewables capacity (up from the current level of just under 40%).

4 ASIAN POWER

IPP

More power plants schedule maintenance shutdowns In June, the total capacity on outage is 1,125MW and there are power plants that are scheduled to go on shutdown or are still on shutdown from 30 May - 28 Jun. These are 375MW Pagbilao, 250MW San Lorenzo Module 50, the 250MW San Lorenzo Module 60 and the 250MW Sta Rita Module 40 natural gas plant.

IPP

Meralco application for lower interim rate gets approval The Energy Regulatory Commission (ERC) of the Philippines recently granted Manila Electric Company’s (Meralco) application for provisional authority to implement lower distribution, supply and metering charges. PHP1.5562/kWh.

IPP

SC gives oil pipeline conditional clearance after DOE-supervised tests First Philippine Industrial Corp (FPIC), a unit of First Philippine Holdings Corp., has been given by the Supreme Court a conditional clearance to reopen the 117km white oil pipeline that runs from Batangas to the Pandacan oil depot. In 2010, it was closed down because of a gas leak which affected an entire barangay in Makati.

IPP

Asian renewable markets becoming attractive for investments Beyond China, BMI Research reports that other renewables markets in the region are becoming increasingly attractive for investment, as a number of underlying positive fundamentals drive growth.These factors include Improving regulatory environments.

FIRST Industries Association. As the stability and predictability of the wind power sector attract greater investment, it is widely believed that wind power will be able to compete with coal generation by as early as this year.“That will be the turning point in China, which by then will be the world’s largest energy consumer,” says Li. While coal-fire power still remains the biggest contributor to China’s energy mix, the country posted a 9% decline in coal-power capacity in 2006, with domestic wind turbine technology catching up quickly.

The country was able to manufacture turbines of only up to 600 kilowatts, but policy incentives have helped in accelerating technological upgrades.

Coal-fired electricity under threat

Asia relies heavily on coal-fired power generation to meet its electricity needs, with over 60% of the power mix derived from coal. BMI Research believes that this trend will continue over 10 -year forecast period to 2024.

It expects coal to account for 59% of Asia’s total generation in 20 24, equal to 9,108 terawatt hours (TWh), forming an integral part of the power mix.

“Asia’s status as the global powerhouse for coal-fired electricity generation is supported by our key projects database, which collates major power projects in various stages of development across the world.

The power project pipeline for Asia indicates that nearly 45% of the total power capacity under development in the region consists of coal-fired power capacity,” says BMI Research.

Coal will remain the dominant fuel in Asia’s power mix over the coming decade as countries continue to ramp-up their domestic coal-fired power capacity, but financial restrictions and public opposition are major hurdles.

The major hurdles The research firm however notes that there are a number of counter trends that could materialise and prevent the realisation of the coal capacity in the pipeline. In particular, is the growing public opposition to coal projects in the region, financing restrictions on coal projects and increasing international pressure on the Asia region to reduce carbon emissions. Some of these risks have already materialised, evidenced in the number of ‘delayed’ or ‘suspended’ projects in the pipeline.

According BMI Research, over 50 GW (roughly 14%) of coal capacity is either delayed or suspended - with reasons including environmental opposition and difficulties in securing financing.

Furthermore, BMI notes that China’s coal capacity pipeline has been reigned in over the last year as the government has taken steps to diversify the power mix away from coal.

6 ASIAN POWER

China increases wind power capacity

China trails peers in offshore wind market

C

hina is witnessing the start of a golden age of wind power development. With wind installations likely to reach 100 gigawatts by 2020, the Asian giant’s policymakers have been caught off guard with the industry’s tremendous growth since 2005.

“Wind power in China is a key component of the government’s efforts to rebalance the power generation mix away from thermal power. This is reflected in a rapid increase in wind power installed capacity since 2010, with the share of wind power in total installed capacity in China having increased from 1.8% in 2009 to 7% in 2014. Capacity additions were highest in 2014 with a net addition of 20 gigawatts,” notes Ephrem Ravi of Barclays.

The role of climate change In addition to policies and regulations related directly to renewable energy and wind power, climate change considerations have played a major role in encouraging China’s wind sector.

As the only country in the world that has set up a national leading group for responding to climate change, headed by Premier Wen Jiabao, China is stressing measures to tackle the challenge through all levels of government, says Junfeng Li, secretary general of China’s Renewable Energy

Junfeng Li

Ephrem Ravi

Challenges A report from BMI Research shows that China’s offshore wind sector is gathering speed, but it could use much more momentum. The sector is picking up with stronger project pipelines and increased investor interest in the market, but challenges come in the form of high costs of development, relatively low feed-in tariff for offshore wind, and regulatory and infrastructure-related hurdles.

“China has been a notable underperformer in the global offshore wind market, with offshore installations - mainly consisting of demonstration projects - in Chinese waters dwarfed by those in Europe (home to over 90% of the global offshore capacity). We attribute this slow progress primarily to the low returns on offer to potential developers and the lack of clarity in regulatory environment for offshore wind,” BMI Research notes. The offshore wind sector is still plagued by regulatory and licensing issues, creating conflicts between different government agencies and project developers.

“Although we have witnessed progress in this regard, we expect further delays in the approval process for new projects,” BMI research adds.

China - renewables capacity by type, 2014-2024

Source: EIA,BMI

FIRST Public opposition to nuclear power has hindered construction and reduced funding in Japan, Taiwan, South Korea, India and Malaysia.

Wolsong Nuclear Power Plant

Asia’s construction constrictions

P

ower plant construction is zipping along in Asia but issues in financing and feedstock availability are proving to be pesky road bumps. Limited financing availability is particularly troublesome especially for politically and socially sensitive projects like nuclear, coal and large hydro plants, says BMI Research.

Public opposition to nuclear power has hindered construction and reduced funding in Japan, Taiwan, South Korea, India and Malaysia. “With this in mind, the ability of emerging Asian countries to move forward with their nuclear agendas will depend largely on both

Russia’s and China’s capacity to provide funding,” says BMI Research.

Financing support China has committed funding to Pakistan for nuclear development while Russia has played an active role in Bangladesh’s and Vietnam’s nuclear sectors. But financing support for nuclear power could skew increasingly towards China because of recent developments in Russia. “Given the macroeconomic headwinds facing Russia in the form of sanctions and lower oil prices, we believe that those countries with forged links and better access to Chinese investment

stand in a better position to see their nuclear ambitions come to fruition,” says BMI Research.

Feedstock availability is also rising as a concern among power plant developers who are finding it harder to secure feedstock. As a result, developers are beginning to second-guess previously economically viable power projects in India, Pakistan and Thailand.

In China, meanwhile, coal is losing some of its shine, in line with government efforts to implement tighter environmental policy. The country has imposed a ban on coal imports with high ash and high sulphur content, in addition to various pollution-abatement measures in coal plants and the closure of coal plants across the country.

But it should be noted that coal power plant construction will continue to make its case despite increasing public opposition and cleaner alternatives.

“We maintain our view that coal will be the dominant base-load fuel in China - and, in fact, the wider Asian region - over the next decade. It remains the cheapest and most efficient resource, coal plants are scalable and have shorter turnaround times - which are better for meeting surging power demand,” says BMI Research.

China - electricity generation by type

e/f= BMI estimate/forecast Source: EIA/BMI

the chartist: china’s nuclear capacity increases at the expense of thermal power Ever since the rapid expansion of wind power capacity in 2011, China’s windmills have consistently generated more electricity relative to their clean energy peer, nuclear power; but that is about to change, says Ephrem Ravi, analyst at Barclays. “Wind power generation of 15.1bn kWh in June was eclipsed by nuclear power’s 15.8bn kWh as nuclear installed capacity grew 25% y/y. More importantly, we believe the gap will widen for the remaining part of the year as wind speeds drop,” he explains.

According to Ravi, high utilisation and stable generation are the key benefits of nuclear power over wind, solar and hydropower in China, and nuclear power is the only scalable option that could materially compete with coal in the country’s power generation mix as hydropower resources are well developed.

Change in nuclear power installed capacity (y/y)

Source: WIND, Barclays Research

Change in cumulative wind power installed capacity (y/y)

Source: WIND, Barclays Research

ASIAN POWER 7

FIRST

Four policies to reduce Asia’s power demand

IPP WATCH

Datang Int’l Power Generation stays strong

W

hen Asia enters the next decade, its electricity consumption is expected to grow at the pace of 5.2% annually, faster than any other region, causing a spurt in carbon emissions that could convince Asian governments to enact policies to curb power demand.

Four policies stand out in reducing electricity demand in the coming years, says Georgina Hayden, analyst at BMI Research. “Policy initiatives such as the introduction of energy efficiency measures, the deployment of distributed energy solutions, improving grid efficiency and boosting smart meter coverage would all be effective mechanisms to curb surging power demand,” says Hayden.

Government funding With significant government funding – as seen in Singapore’s S$100 million investment in research for energy efficiency in buildings and data centres – energy efficiency can be a strong option. Key measures are refitting lighting systems and improving insulation.

A second policy approach would be for Asian countries to lean more on DES as an alternative to the traditional utility business model, which Hayden notes is based around centralised,

Singapore invested $100m for energy efficiency research

fossil-fuelled generation capacity.

Third, improving the quality of electricity supply through investments in grid infrastructure and power distribution reform would help Asian countries lower inefficiency and transmission and distribution losses, ultimately reducing overall power consumption.

Finally, the use of smart meters has been shown to be an effective and scalable way to lower power usage among households. “Smart meters facilitate two-way communication between consumers and generators in real-time, thus enabling utility companies to monitor energy use in every home in real time,” says Hayden.

“Meanwhile, customers are able to manage their own energy usage in accordance with the dynamics of supply, possibly reducing electricity costs by reducing electricity consumption or shifting consumption from peak period to off-peak periods, when electricity prices are cheaper.”

CPI’s total net generation down by 9% y/y

With significant government funding, energy efficiency can be a strong option.

Newcomers threaten Singapore’s long-time Power Trio It’s a great time to be a budding genco in the market-driven power sector of Singapore.

In fact, Singapore’s top three gencos, YTL PowerSeraya, Senoko Energy and Tuas Power Generation , which make up for almost 70% of the city-state’s power market share, are shaking from the idea of newcomers annexing their respective thrones atop the power hill. “Despite their market dominance, the profit after tax (PAT) margins of these bigger players are largely similar to those of their smaller peers such as Sembcorp and Keppel Merlimau,” says Serene Tan, analyst for RAM Ratings.

As Singapore’s power market is highly liberalised, the Energy Market Authority is encouraging new gencos in order to accommodate growing demand and usher in higher efficiency. “We envisage capacity growth to decelerate in the medium term while the reserve margin narrows following a 26% capacity expansion in 2013 and slower economic performance going forward,” says Tan. “Following the completion of the LNG terminal in 2Q 2013, Singapore’s generating capacity had expanded on the back of the rise in gas supply with the start of commercial operations for more than 2.6 GW of capacity,” adds Tan. 8 ASIAN POWER

Datang International’s power generation business was strong in 2Q15 with a 12% q/q recovery. In the absence of major project commissioning in 1H15, research firm Barclays believes that the recovery was led by a combination of strong hydro and better utilization hours for thermal power. Profit-Before-Tax in the power business increased 9% y/y and was ahead of our expectations.

China Power International Development’s (CPI) total net generation at 15.1bn kWh in 2Q15 declined 9% y/y. According to a research note from Barclays, within the blended generation, hydro power reported a 13% y/y decline in 2Q15, which is seasonally the peak season for hydro power. This compares with an increase of 47% y/y in 1Q15 in hydro power generation. Coal-fired power generation continued to be weak, declining 7% y/y.

Aboitiz Power’s unit to build a 380MW hydropower complex

Singapore’s budding genco industry

Going online soon Singapore welcomes new gencos

Aboitiz Power Corp.’s unit, SN Aboitiz Power-Ifugao (SNAPI), is set to build a 380MW hydropower complex. It will be in Lagawe, Ifugao to provide additional power supply to the Luzon grid.

The project is composed of three hydropower plants namely the Alimit Hydroelectric with 120MW target capacity, Olilicon Hydroelectric with 10MW target capacity, and Alimit Pumped-Storage Hydroelectric with 250MW.

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FIRST

Myanmar’s big push for power growth

J

ust a few decades ago, Myanmar was known as the “Pearl of Asia”; as one of the leading economies of southeast Asia at the time, its per capita income more than twice that of Thailand’s. However, the country’s growth rate has stagnated, leading to very slow growth in the past few years particularly in comparison to some of its neighbors – a daunting challenge now viewed as an opportunity by foreign investors who see the potential in its development.

“The key issues that Myanmar needs to address are that there is no track record of developing power projects in the country and the process for international developers is not sufficiently developed from an engineering, environmental or commercial perspective,” says Tony Segadelli, managing director of the OWL Group.

Myanmar’s potentials Myanmar’s GDP and electricity consumption per capita is one of the lowest in Asia. But, Wartsila Singapore business development manager Abhay Shah believes that it also has the potential to become one of the continent’s leading economies should its vast natural reserves and promising manpower resources be effectively utilised. This prospective economic growth is heavily reliant on the development of a power infrastructure that will increase the country’s access to electricity, without which industrial development cannot be sustained. To date, over two-thirds of Myanmar’s population does not have access to electricity.

Natural resources that have the potential to

become major power sources for Myanmar include hydropower, natural gas, liquefied natural gas (LNG), and liquid fuels, to name a few. Of these options, hydropower is one of the most substantial options –it is expected to remain the main source of electricity in the next few years.

However, its proneness to seasonal variations and the long development cycle of large hydro plants are only two of the challenges to be faced in utilisation, making it difficult for Myanmar to be solely reliant on it as a power source.

Developing other power sources such as coal plants and LNG infrastructure would not only be very expensive, but would also take several years to come online.

The optimal solution The optimal solution for Myanmar in the shortterm is to use heavy fuel oil (HFO), which is substantially cheaper than diesel and is locally available thanks to private companies who have begun importing it into the country for power generation. This would be utilised provisionally until domestic natural gas becomes readily available in adequate amounts to sustain the country’s energy needs. Though natural gas is the ideal option for Myanmar, the required quantity is insufficient and would not be available until around 2021.

Myanmar must also consider the feasibility of the different types of power plants to be constructed to provide high performance and efficiency at low lifecycle costs, an evaluation that

KHNPC/KEPCO on the right path with new nuke reactor When Korea Hydro and Nuclear Power Co,, (KHNP), the wholly owned nuclear power generation subsidiary of KEPCO, recently revealed that commercial operations of the Shin-Wolseong 2 nuclear reactor have already begun, analysts were upbeat.

According to Moody’s Investors Service Hong Kong associate analyst for project and infrastructure finance, Sean Hwang, the commissioning for the reactor was deemed lucrative for KHNP and KEPCO as it bolsters the companies’ cash flows for operations and debt metrics by boosting KHNP’s electricity revenue and minimize KEPCO’s expensive dependence on liquefied natural gas and oil-fueled power plants.

As it stores 1,000 megawatts of energy, the new reactor will generate 7,000 gigawatt-hours per year, effectively boosting KHNP’s operation funds, laying the groundwork for the construction of more plants.

“With this already reflected in our base case, we expect KHNP’s FFO/debt to be 23%-28% over the next 12-18 months, down slightly from 31% in 2014,” says Hwang. The new plant would also relieve KEPCO of a chunk of its generation costs, including the costs of electricity from independent power producers which generate their energy from costly LNG. “We expect such incremental savings to boost the utility’s FFO by KRW500-KRW600 billion annually, which, together with a significant decline in fuel costs, will strengthen its credit metrics. We expect KEPCO’s FFO/ debt to improve to 20%-23% over the same period from 18% in 2014,” explains Hwang.

10 ASIAN POWER

KEPCO Sakaiko Power Plant

Kori Nuclear Power Plant

What would be Myanmar’s optimal solution?

must be conducted per project in order to select the most appropriate technology at hand. One of the options to be considered include engine based dual fuel plants that could be a significant possibility for Myanmar’s potential interim plan of utilizing HFO until a more sustainable source becomes available.

There is much room for growth in a country like Myanmar, where there is so much untapped potential that investors are only beginning to take notice of.

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Antonius RT Artono,

Acting President Director PT. Indonesia Power

12 ASIAN POWER

CEO INTERVIEW

PT. Indonesia Power reveals plans to meet 10 GW additional power capacities by 2025 It has ambitious plans that will ride on the coattails of Indonesia’s power plant investment spree.

I

n the past decade Indonesia has reduced its electricity shortage and lowered the electricity subsidy through tremendous power plant investments. Encouraged by the strategy’s success, it is further ramping up its investments through the 35 GW New Power Plant Programs which will be implemented within the next 5 years.

Asian Power sat down with Mr. Antonius RT Artono, acting president director & director of business development & commerce at PT. Indonesia Power, to talk about Indonesia’s ambitious target and the role his company will play in this potentially game-changing program.

PT. Indonesia Power is a subsidiary of government-owned electricity distribution company, Perusahaan Listrik Negara (PLN). Established in year 1993, the company is aimed at creating power generation business competition together with Independent Power Producers that started to grow at that time in accordance with the electricity regulation in the country.

What are the targets of PT. IP in relation with the 35 GW New Power Plant Program?

The 35 GW Program is not only a big challenge for the company but also a big opportunity to grow and expand the company’s business. The company has targeted 10 GW of new power plant business in the next 10 years, which is more than double that of the existing capacity. Out of this new 10 GW power plants, 6.6 GW capacity is under development at various stages: 200 MW has just completed commisioning, 212 MW is under construction or exploration, 1,850 MW is under procurement stage and the rest of 4,390 MW is under the feasibility stage.

Among this 6.5 GW new capacity, the company has secured power plant locations for 4,890 MW. To realize the targeted 10 GW capacity, the company still needs to pursue the rest of 3.4 GW capacity through partnerships or equity investments.

To support the 35 GW power plants, Indonesia has various energy resources either renewable or non-renewable energy.

What are the most pertinent energy challenges Indonesia are facing today and how is your company helping to address these issues?

For such a big 35 GW electricity program, this country cannot just rely on a single energy souce. The country has an abundance of coal, gas, hydro as well as geothermal. This country, like other countries, must avoid utilizing oil as an energy source to generate electricity, as this is the most expensive way to produce electricity.

Utilizing a combination of many energy sources also provides less risk in terms of reliability in energy supply.

PT. Indonesia Power will focus on three major energy sources in developing new power plants, namely coal, gas and hydropower plants. We will still consider geothermal power plants as long as the risks are manageable.

We know that Indonesia Power looks after the operation of power plants in Indonesia. Can you tell us more about your operations in this country? What are the latest updates as well as challenges you are facing?

The company is providing O&M services for about 5.3 GW power plants belonging to PLN across the country. Our strategy in providing O&M services is mainly to deliver good power plant performance through duplicating our long-term

best practices in operating our own power plants, as well as build asset management systems to ensure the right power plant O&M strategies in the long run.

The most challenging parts in entering this O&M business is building competencies in O&M. To provide competent operators and technicians requires about 2 years of on the job and in-class training (different types of power plants will need different periods of training, in this example, we use coal power). To address this challenge, the company is investing in recruiting and training human resources 2 years prior to the expected power plant operation. We train staff in our existing power plants and place them under mentorship of experienced operators and technicians.

In addition, as each power plant will always have unique characteristics, then we will deliver our well-trained operators and technicians during the construction and commissioning stages to make sure they become accustomed to the specific power plant. This year the company is recruiting about 500 operators and technicians and will continue for the next 3 years to provide O&M services not just for PLN’s new power plants but also IPP power plants.

What do you consider as Indonesia Power’s biggest achievement to date?

There are many achievements awarded to PT. IP during its company history, but the biggest one is power plant reliability that can reach up to the top 10% of statistical data compared to the North American Electricity Regional Councel (NERC).

Every year we measure and compare our operational power plant performance against the stastical data from NERC. We have the Suralaya Coal Power Plant Unit 5,6 & 7 (600 MW size each) that reached the Equivalent Availibility Factor of 95%, 94% and 92% respectively.

Each of them is above the top 10% of NERC at 90.35 %.

Availibility is one of important measures of success for a power generation company delivering O&M services. We are very proud of it, and willing continously maintain this high level availibility in the future.

What are Indonesia Power’s plans for the next 5 years?

The company in the future will focusing on five major aspects, but at this time I just want to focus on 3 of them: Growth, operational excellence, and business development excellence.

We expect that within the next 5 years, we can grow up to 5 GW capacity of new power plants. We just completed commissioning 200 MW additional capacity and expect more in the 4th and 5th year. This growth will ensure that the size of the company will increase in terms of assets and capacity as well as revenue and profit. This is very important to the company to maintain company sustainability through the renewal and replacement of old and less efficient assets.

Operational excellence is also a key focus to our company, as this is the way the company will get continuous profit for new investments. This critical factor will also build trust and confidence among our shareholders as well as potential partners.

Last but not least is business development excellence, starting from selecting good and profitable projects, conducting studies, all the way through to engineering & design, procurement, construction, quality control, project management, and commercial operation.

ASIAN POWER 13

Country report 1: Malaysia

Bakun Dam in Sarawak, Malaysia

Malaysia’s RE plans placed under scrutiny

Not everyone is convinced with the government’s target of 1,000MW renewable grid-connected capacity by 2020.

W

hen the 10th Malaysia Plan was first implemented in 2011, it aimed to allocate the national budget to all of the major economic sectors of the country until 2015. As a result of effective planning, Malaysia has shown marked improvement in practically all sectors, particularly in the effective sourcing and delivery of energy – for instance, electricity generation has increased by over 5,000 MW and electricity coverage in the rural areas has grown to roughly 98%, from 93% in 2010.

The focus on energy development was mainly placed on diversifying energy sources and investment in new technology and infrastructure in order

The efficiency of electricity supply services has increased significantly and the number of power interruption occurrences are also lower.

Malaysian power mix evolution (1971-2013)

Source: Global Energy and CO2 Data 14 ASIAN POWER

to meet Malaysia’s growing demand in a sustainable manner. At the same time, the country undertook to ensure efficient utilisation of their resources, which included taking measures to improve productivity in the process.

Efficiency of electricity supply The increase in generation capacity was brought about by commissioning ten power plants, with various energy sources including hydropower and gas. In remote rural areas, alternative smaller systems such as solar hybrid and biomass were also utilized apart from connection to the country’s main grid. The efficiency of electricity supply services has increased significantly and the number of power interruption occurrences are also lower.

However, with Malaysia targeting more sustainable energy use in the long term, they must reduce their dependence on fossil fuels as a main source of power by exploring alternative environmentallyfriendly power sources.

“The mainstay of the generation fuel mix will continue to be conventional fossil fuels, e.g. coal and gas. Gas is now even being imported as LNG for use in power plants. Clean energy sources will, for a long time, only be seen to complement fossil fuels and hydro, and not become a significant component of the fuel mix,” says Ir. Andrew Amaladoss, general manager of Tawau Green Energy of the

struggle to increase energy productivity with clean energy sources. “Challenges include the mismatch between the location of the grid and green energy resources such as biomass, biogas and hydro.”

In the total generation fuel mix, coal is expected to increase in terms of its current ratio to natural gas, leading to a significant increase in coal consumption for Malaysia in the near future. Unfortunately, in the near term, the country looks set for even more coal, in an effort to maintain electricity prices as the gas fuel subsidy is gradually reduced,” says Dato Ir. Dr Ali Askar Sher Mohamad, chief operating officer of Sustainable Energy Development Authority (SEDA) Malaysia.

A secure energy supply is one of the primary underpinnings of economic growth – in Malaysia, it would enable the country not only to move forward as an economy, but to raise their citizens’ standards of living. For this reason, the energy sector is one of the main components for development in the Eleventh Malaysia Plan to be implemented this 2016-2020, which includes comprehensive governance and a communication plan to improve good governance and public awareness on energy developments.

Part of this plan also entails a continuation of the earlier developments

Country report 1: Malaysia

Piarapakaran S.

Andrew Amaladoss

KL Sentral at night

on improvement of productivity by ensuring that there is a secure and reliable supply of natural gas, as well as further research on its safe and efficient distribution, particularly in the rural areas. In order to reduce distortion of market energy prices, sustained efforts will be carried out to decrease and gradually remove energy subsidies.

By removing these subsidies, growth in the oil and gas subsector is also imminent – a means of ensuring fair competition in the gas supply market will be implemented to encourage new entrants to contend with Petronas, which is currently Malaysia’s sole gas supplier. This is in conjunction with plans to develop technology that will greatly increase the country’s oil refining capacity, to which third party gas suppliers will have access, with the enforcement of the amended Gas Supply Act 1993 (Act 501) in 2016.

Renewable energy One of the most heavily-debated strategies in place for the future is the assessment and application of the clean and green alternative to Malaysia’s fossil fuel concerns; renewable energy (RE).

This was first introduced in the form of the Renewable Energy Act in 2011, and with it, the Feed-in Tariff (FiT), as part of the country’s movement to explore new sources of clean energy. Under the FiT, SEDA expects to achieve at least 1000 MW of installed renewable gridconnected capacity by 2020 as part of several initiatives to be applied by the government that are currently under development, one of which is net energy metering.

Not everyone is convinced by the argument for RE, however – there are challenges to be faced in introducing new sources of energy to the country, as it poses several difficulties in terms

of environmental sustainability. It also involves enormous investment, not only in terms of finances and infrastructure, but also the extensive amount of time involved in researching and developing the required technology.

“The government needs to identify the correct renewable energy resource that suits Malaysia and encourage the industry players to develop the necessary technologies locally where possible,” says Piarapakaran S., president of the Association of Water and Energy Research Malaysia (AWER). “Currently, Malaysia is not the technology owner for many RE technologies. We mainly ‘buy and use’ these technologies which will increase the cost of developing RE in Malaysia. Eventually, the consumers have to bear this additional cost via the electricity tariff. Besides this, the Malaysian government needs also to protect our rainforests to ensure the long term sustainability of our mini hydro and large scale hydroelectric projects.”

A sizeable number of residents and authorities alike are also wary of the introduction of nuclear energy as one of the renewable energy options being explored, despite the strong enthusiasm for its implementation in 2011. An independent atomic energy regulatory commission will be established in preparation for the project.

Challenges One of the foremost challenges includes educating public sentiment: the majority of Malaysian citizens are not confident in the idea of building a local nuclear power plant, and especially not if it is within their residential zone, based on the National Energy Security Survey (NESS) conducted by AWER. While plans to explore nuclear power as a potential energy source are still in place,

Pi Dato’ Ir. Dr. Ali Askar Sher Mohamad ara

Malaysia still has several more years to go before their research is completed, not to mention applied – perhaps by then the results will be more reassuring.

“I personally believe that nuclear is the way forward for Malaysia to cut its dependency on imported fuels… more effort needs to be put into public awareness and the conceptualising of nuclear in the generation mix,” says Amaladoss, emphasising that while confidence in the project is currently very low, the current public mind-set may be changed if it is properly informed and provided with adequate data on its development.

The exploration into renewable energy sources will allow Malaysia to strike the optimum balance in fuel mix, which aims to gradually decrease the ratio of fossil fuels and to substantially increase clean energy sources. To reduce their country’s carbon footprint, top-of-the-line emission control technologies will also be used to ensure that future power plants are not negatively affecting the environment.

This is particularly relevant in light of the fact that coal constitutes a considerable percentage of their current fuel mix, and will only increase further in the shortterm future.

Incentive based regulation Continuing the Incentive Based Regulation (IBR) is also part of Malaysia’s plans for the next few years, this time by restructuring the current model to further incentivise efficiency gains by the utility. Greater transparency yields greater efficiency in the new model, as well as being more financially stable, in turn benefiting Malaysian consumers and enabling overall economic growth.

In the past few years, the Tenth Malaysia Plan focussed on expanding their infrastructure network in all economic sectors to improve accessibility and overall quality of life. In the Eleventh Malaysia Plan, further investment in the developing infrastructure will be made to increase productivity and efficiency.

Components of electricity tariff revision, January 2014

Source: Tenaga Nasional Berhad

ASIAN POWER 15

co-published Corporate profile

Improving performance in power plant operation

The new release of SPPA-T3000: Success starts in the control room

The new functions of SPPA-T3000 Cue help plant operators to perform day-to-day work more efficiently and more effectively, and to react reliably and more quickly in critical situations.

S

iemens’ control system SPPA-T3000 Cue – a new release of the world’s leading control system for power generation – puts a focus on an improved Human Machine Interface [HMI] to enhance the economic performance of power stations.

Utilities and power plant managers are facing tough competition, and this puts more and more importance on performance in power plant operation – performance which is substantially influenced by the people operating the power plant.

This is why SPPA-T3000 Cue, the latest release of Siemens’ Distributed Control System [DCS] for power plants, has been designed following an operator-centric approach.

Comprehensive expertise for best-in-class automation Siemens has handled power plant engineering, design, and construction in-house for decades. So the company is intimately familiar with all the tasks related to 16 ASIAN POWER

power plant automation. Having automated more than 2,700 units worldwide over the past 50 years with great success, Siemens is now focusing on making the operator’s job even more effective and more efficient.

This is achieved by providing an intuitive design, enabling faster response to disturbances, smooth handling, and reducing the risk of unplanned disruptions in operation. Siemens is convinced that this will make an impact on the performance of the plant as a whole.

Operator needs for more effective and more efficient plant operation A power plant has thousands of sensors and signals, for the main components, for motors

“Siemens is now focusing on making the operator’s job even more effective and more efficient.”

and pumps, for drives and fans. The daily responsibility of the operator is to monitor all these components and to re-adjust and to correct any deviations.

Smooth periods of working through the various required tasks can suddenly be interrupted by periods of hectic activity to counter disturbances in the plant’s operation or failures of the plant equipment. In these situations, operators do not need raw, unfiltered information – they rather need to focus on what really matters. Their ability to function in an appropriate manner is supported by SPPA-T3000 Cue which delivers the right information, in the right manner, at the right time.

Optimized workflows thanks to a clever HMI SPPA-T3000 Cue is a control system that is intuitive to operate and provides the operator with complete control of his plant. With its ergonomic design, the system achieves maximum ease of operation, featuring

co-published Corporate profile information at the touch of a button, intuitive and icon-based navigation, one-click-access to important functions and to Siemens’ own and further applications.

In addition, the new release provides customizable user interfaces geared to an operator’s specific needs and comprehensive help in the event of faults, such as automatic first-value searching and suppression of subsequent messages. All of this combined leads to reduced stress levels in day-to-day business.

SPPA-T3000 Cue offers well thought-out support for various areas of the daily routine.

Highly advanced diagnostic tools visualize detailed facts about the plant systems or specific equipment at a glance. Built-in operations management and shift logs make handovers and scheduling more manageable than ever.

And additionally, the user can easily tap into non-local applications, such as maintenance management, equipment diagnostic systems or task lists – all directly accessible from the HMI workplace. All relevant plant data can always be in sight.

Support in the event of an alarm The new release also features improved alarm management. It classifies alarms, directs critical information to the operators in the control room, and re-directs unimportant messages to be either archived, or dealt with at a later time.

Alarm counts provide transparency about the plant’s situation and allow for quick and targeted reaction. Each alarm class is shown with the numbers of raising, unacknowledged and pending alarms; double-clicking opens the alarm-class-specific Alarm Sequence Display [ASD].

Group Alarm Indicators then reduce reaction time in critical situations: The respective alarm buttons allow direct navigation to the plant display which contains the corresponding component, avoiding a time-consuming search.

SPPA-T3000 Cue provides guidance by giving targeted cues to the control room personnel so that they can make better decisions – faster – in critical situations.

The HMI of SPPA-T3000 Cue manages torrents of messages and automatically guides the user through root-cause analysis in the event of a fault. Alarms and warnings are accompanied by detailed information and guidance for rapid resolution. Special alarm classes, specifically designed to avoid a plant trip or forced outage, include an alarm control window with clear instructions – enabling fast and precise action to keep a plant running.

Key Performance Indicators [KPIs] are always visible for the operator in order to provide transparency on the performance status of the power station. These KPIs may include output data, efficiency data,

emissions figures, trend reports on pressures and temperatures, or other values.

A new alarm class “Diagnostic Recommended” [DR] has been introduced – it is used to detect availability-relevant components that have reached a status for which a deeper assessment is recommended.

To do this, Siemens has integrated modelbased condition monitoring into SPPA-T3000 Cue. The system reports subtle changes from the expected status even before the DCS limit values are reached. With one click, the “DR” simplifies root-cause analysis by showing plain text messages and opening all relevant displays. An in-depth analysis can then be carried out using Advanced Diagnostics. As a result, the integrated condition monitoring makes a substantial contribution to increased availability.

Integrated support for shift handover Daily shift handover can be performed very efficiently if it is managed electronically and intelligently. SPPA-T3000 Cue features an integrated support function for this workflow.

It allows going through the five basic displays: plant overview, alarm sequence display with open alarms, shift schedule with resources, pending repairs, and open tasks. Operators can then load the tasks onto the task list for the following shift at the click of a mouse.

This gapless flow of information saves time and promotes safety and reliability.

Flexible connectivity is a key characteristic of SPPA-T3000 Cue, supporting common standards in industrial communication as well as future-oriented IEC standards.

Traditional control systems based on proprietary protocols can be connected to the HMI, and individual HTML or RDP applications can be accessed within the operator’s work environment.

Constantly up to date – over the entire lifetime of the power station Power producers can benefit from control system migrations and future upgrades.

SPPA-T3000 Cue comes as a Long-term Service Release and will be part of all of Siemens’ new power generation control solutions.

It can also be integrated or retrofitted to existing control systems. By supporting operators with the right tools, targeted cues, and guided procedures for sound operation, SPPA-T3000 Cue provides the platform for improved power plant performance.

Dr. Dirk Lumma Head of Product Management for Control Systems Siemens Power and Gas Division

“SPPA-T3000 Cue provides guidance by giving targeted cues to the control room personnel so that they can make better decisions – faster – in critical situations. The HMI of SPPA-T3000 Cue manages torrents of messages and automatically guides the user through root-cause analysis in the event of a fault. Alarms and warnings are accompanied by detailed information and guidance for rapid resolution.”

SPPA-T3000 Cue features additional functions such as optimized alarm handling, trip-stop buttons or integrated plant diagnostics.

ASIAN POWER 17

Country report 2: Japan

Ikata Nuclear Power Plant

Electricity sector deregulation one of the keys to Japan’s plan of resurrecting nuclear power

It has already begun with the limitedcompetition for bigger customers cutting across regional Japanese power firms.

M

ore than four years after a massive tsunami struck the island country, the tragedy of Fukushima still haunts Japan, a powerhouse economy dependent on nuclear energy.

The accident, brought forth by a massive magnitude-9 earthquake, has sent ripples from Japan to other countries, questioning current safety frameworks of nuclear power plants and emergency response mechanisms in times of catastrophic disasters.

The March 2011 disaster at the Fukushima I Nuclear Power Plant has cast a shadow of doubt on the future of nuclear energy in the country, despite the Japanese government’s plan to restart some nuclear plants this year. “Nuclear power has been a cornerstone of Japanese energy policy since the mid-1970s and before Fukushima, accounted for approximately 30 percent of electricity production,” says Steve Kidd, independent nuclear consultant and economist with East Cliff Consulting.

At that time, Japan ranked as the third-largest nuclear power generator in the world behind the United States and France. Natural gas and coal were the primary fossil fuels used in Japan, making up about 30% and 24% of Japan’s electricity mix, respectively, in 2010. Oil, one of

18 ASIAN POWER

Jonathan Cobb

Akira Tokuhiro

Tony Segadelli

the most expensive and least-clean fuels to burn, accounted for just 7% of power generation in 2010. Renewable energy made up about 11%, mostly from hydroelectric generators, says Candace Dunn of the United States Energy Information Administration who notes that after the meltdown at Fukushima Daiichi, the country proceeded to shut down almost all of its nuclear fleet.

Dunn says that in 2013, two years after the accident, more than 86% of Japan’s generation mix was composed of fossil fuels. In 2014, Japan’s nuclear generation was zero.

Pre-Fukushima accident Prior to the Fukushima accident and the gradual displacement of all of Japan’s nuclear generation, nuclear generation represented 27 % of Japan’s net power generation in 2010. “Following the Fukushima accident, nuclear’s share of electricity generation declined, and energy conservation measures were enforced for larger businesses and highly encouraged for smaller consumers. Japan’s utilities initially substituted the lost nuclear generation with natural gas, heavy fuel oil, crude oil, and coal, but oil-fired generation began declining in 2013, as Japan relied more on natural gas and coal. Meanwhile,

almost 4 gigawatts of additional coal capacity came online in 2013, increasing the share of coal-fired generation. Japanese utilities have proposed building several additional natural gas- and coal-fired power plants to replace aging generators and to serve the country’s high electricity demand,” says Dunn.

Despite the biggest nuclear disaster since Chernobyl, the Japanese government is still keen on the use of nuclear energy to reduce the current energy supply strains and alleviate high electricity prices.

“To achieve this, more than half of the operable reactors need to return to service and it would be necessary to commission new units as time passes. At the moment, only Ohma 1 is under construction,” Kidd says. He adds that another important issue in resurrecting the nuclear power industry in Japan is the proposed deregulation of the country’s electricity sector.

It has already begun with the limited competition for bigger customers cutting across regional Japanese power companies, but the electricity market is due to be deregulated in April 2016. “How this will affect nuclear power plants remains to be seen,” Kidd says.

The country’s new energy policy, issued in 2014, emphasizes energy security, economic efficiency and greenhouse gas

country report 2: Japan emissions reduction, although the plan has yet to provide details on the country’s future power generation fuel mix, Dunn says.

Satoshi Togawa of the Tokyo Electric Power Company’s (TEPCO) Corporate Communications Office believes that moving forward, it is important to have equal weighting for stable energy supply, economic performance and environmental protection, ensuring safety as the first priority, as the government implements its future energy policy. “TEPCO strongly wishes to be a nuclear power plant operator which has the world’s highest level of safety awareness, engineering capabilities and risk communication ability with society,” Togawa adds.

Kidd says that, along with laying down measures to ensure nuclear safety in the future, the Japanese government also has to grapple with the negative publicity that has been unleashed since the Fukushima nuclear disaster. “The foundations are in place for Japan to continue to have a substantial nuclear sector but the industry has to greatly improve its public relations and paint a positive picture,” he says.

Tony Segadelli, chief engineer and managing director of Owl Energy says

Unless reporters persistently cover news on recovery, remediation and restoration (R3) in Fukushima, news on R3 will gradually disappear.

Japan’s net electricity generation by fuel, 2000-2013 terawatthours (Twh)

Source: U.S. Energy Information Administration, International Energy Agency, METI

Fugen Nuclear Power Plant

even if Prime Minister, Shinzo Abe is able to pass further legislation and policy plans that promote nuclear energy, strong public resistance to nuclear power coupled with a permit process that requires local support, means that very few nuclear units will be restarted.

Public oppossition Jonathan Cobb, senior communication manager at the World Nuclear Association, says the nuclear power sector has to demonstrate to the public in Japan that they have taken the right actions to improve the preparedness of their nuclear plant and that the plants are under effective scrutiny through the new regulatory regime. “Although overall opinion toward nuclear energy has become more negative, there remains a range of views. The first restarts will likely take place where local opinion is more positive,” he says.

Cobb adds that experience has shown that in countries where there have been accidents, public support can be regained.

For example, public support in the United States has steadily improved since the accident at Three Mile Island in 1979. Cobb says the shutdown of nuclear reactors since 2011 has shown the negative consequences of not using nuclear energy. The country’s greenhouse gas emissions have risen and import costs have increased as it has relied on fossil fuels to make up for lost nuclear generation.

The return to nuclear will not be that be easy. “I believe this is ambitious and thus not likely to occur,” says Akira Tokuhiro, professor of mechanical and nuclear engineering at the University of Idaho, in response to the Japanese government’s plan of meeting as much as 22% of the nation’s energy needs through nuclear energy.

“Japan had 54 operating nuclear reactors before the Fukushima Daiichi

accident. This provided approximately 33% of the electricity generating capacity.

There were plans to expand this beyond 40% reliance. In the post-Fukushima Daiichi period, they shut down all reactors. Four years later, they are struggling to restart their first reactor since ‘3.11’, the Sendai NPS. I believe even under the best scenario, Japan will only realise restart of 20 or so plants over the next 10-15 years,” says Tokuhiro.

Tokuhiro adds that 15 years from now, many nuclear power plants will have to be decommissioned because they will have reached their 40-year license limit. “The argument that is not being made to the Japanese public is the economic decline of Japan relative to the rise of China in Asia.

I believe even Prime Minister Abe has not linked nuclear energy in Japan for peaceful purposes to the geopolitics,” he adds.

Asia’s trend The Japanese government’s plan to return to nuclear energy also comes at a time when other countries in the region are giving nuclear power some serious investigation. “China is already pushing nuclear programmes and has declared plans to grow nuclear capacity for the next 20 years. Via this ambition and relative stagnation in growth of nuclear power in Korea and Japan, China will increasingly become the leader in nuclear power in Asia and globally,” Tokuhiro says.

Political continuity also stands out as a major factor in bringing back nuclear energy to contribute a substantial portion to the country’s energy mix. “For Japan to steadily restart its idle nuclear plants will take more than the next five years.

This means that a personality as strong as Prime Minister Abe’s will have to emerge from his Labor Democratic Party(LDP).

Is there such a person today? In addition, for Prime Minister Abe, securing changes to Japan’s security positioning is a higher priority than restarting its reactors,” he says.

Tokuhiro says that in Japan, the ever present challenge is for the LDP to remain in power, to hold the majority in both houses of the Japanese Parliament.

“This means successful elections and referendums to forward their agendas. At the moment, there is strong and persistent opposition. However, if you observe news reports, the Fukushima stories are slowly declining in coverage. The plight of the victims is slowly being forgotten globally and nationally. By this, I believe that Japan is very Tokyo-centric; most of Japan-worthy news is centred about Tokyo. Since Fukushima is distant from Tokyo, unless reporters persistently cover news on recovery, remediation and restoration (R3) in Fukushima, news on R3 will gradually disappear,” he says.

ASIAN POWER 19

sector report: Nuclear power in asia

Monju Nuclear Power Plant in Japan

Asia expected to account for almost 43% of the world’s share of nuclear power by 2030 Four years post Fukushima tragedy, nuclear energy is still being touted as a reliable and viable power source .

W

hen a powerful earthquake shook Japan in 2011 and heavily damaged the nuclear reactors at Fukushima— resulting in a nuclear meltdown that cost billions of dollars, both in human life and in property—the aftermath for the nuclear industry was bleak. The Fukushima Daiichi nuclear accident cast a troubling shadow over many nuclear programmes in the region, in one way or another. Growth, while still consistent, has now slackened.

“In general, there is still a lot of interest in nuclear power in Asia despite the negative impacts from Fukushima. However, we have seen a marked reduction in the pace of growth after Fukushima,” notes Jonathan Hinze, executive vice president at The Ux Consulting Company, LLC (UxC).

Japan’s long-term nuclear growth, for instance, is now being closely watched. “While Japan was unlikely to expand nuclear power all that much before Fukushima happened, it is now likely to only have around 25 GWe (gigawatts-electric) in capacity until 2030 compared with nearly 50 GWe before the accident,” Hinze says. In China, there have only been a total of nine nuclear construction starts since Fukushima (four in 2012, two in 2013, and two so far in 2015) versus the trend of starting eight to ten new reactors annually, pre-Fukushima.

“For example, people were thinking that China could reach close to 80 GWe in nuclear capacity by 2020 before Fukushima happened, but we now expect only about 50 GWe to be online by the end of 2020,” Hinze notes. In Taiwan, the likelihood of a total nuclear ban by 2025 looms, while initial plans to jumpstart nuclear power programmes in the Philippines and Singapore have been all but shelved.

Asia: a sweet spot for nuclear energy Nevertheless, some experts are a bit more optimistic on nuclear power in a post-Fukushima Asia. Jonathan Cobb, senior com20 ASIAN POWER

Asia is and will continue to be the fastest growing nuclear market globally. This trend will likely accelerate.

munication manager at the WNA, boldly declares, “There is strong support for the use of nuclear energy in Asia.”

In addition, Hinze goes on to note that Asia still trumps the West in terms of nuclear expansion.

“Asia remains the shining star of the global nuclear market. As nuclear power plants are either closed or plans for new plants are delayed in other major regions, such as North America and Western Europe, the continued expansion of nuclear power in Asia means that all the leading companies in this industry are now heavily focussed on this key regional market,” he says. According to proprietary UxC forecasts, Asia is expected to account for approximately 43% of the world’s share of nuclear power by 2030, a sharp rise from a mere 25% share this year.

“Naturally, this kind of rapid expansion is getting a lot of attention around the world,” Hinze confirms.

As with any industry, policy constitutes the backbone of Asia’s nuclear sector, and clearly,Asian governments were unfazed by the Fukushima incident. “Across the world, only a handful of countries changed their energy policy negatively on nuclear energy after the Fukushima accident,” Cobb observes. After all, while mistakes were made, lessons were also learned.

“Governments, regulators and the nuclear industry have examined what caused the accident at Fukushima and are implementing changes in response to what has been learnt,” Cobb says.

Hefty projects in the pipeline Over the next decade, a pipeline of at least 40 nuclear power plants are expected to come online across east and southeast Asia, easily turning the region into the world’s nuclear powerhouse with nearly half of new capacity expected to come from the continent .

“Asia is and will continue to be the fastest growing nuclear market globally. This trend will likely accelerate. Asia itself will

sector report: Nuclear power in asia Nuclear power in Asia, and involvement with the nuclear fuel cycle

Source: WNA Reactor table, WNA country papers, OECD/IEA World Energy Outlook

Source: International Atomic Energy Agency, 2013

become the hub of the nuclear supply chain and state-of-the-art technology,” says William S. Linton, principal and chief executive officer at Linton Consulting.

“Through to 2010, projected new generating capacity in this region involved the addition of some 38 GWe per year, and from 2014 to 2025 it is expected to be 1,400 GWe - over 120 GWe per year - very little of this being to replace retired plants. This is about 46% of the world’s new capacity in that period – under construction and planned (current world capacity is about 6,200 GWe, of which 380 GWe is nuclear),” the World Nuclear Association (WNA) said on its website, citing its own reactor table and country papers, as well as the Organisation for Economic Co-operation and Development/International Energy Agency World Energy Outlook.

The WNA describes the growth to be derived from nuclear power plant expansions in China, Japan, India, and Korea. “The nuclear share of this to 2020 is expected to be considerable in three of those countries, especially if environmental constraints limit fossil fuel expansion,” WNA states. Meanwhile, in addition to these nations, Hinze cites Pakistan and Vietnam, and “...possibly Indonesia and Malaysia...” as sources of active growth for nuclear power in the region.

According to the WNA, Japan tops the list of Asian countries in terms of built nuclear power plants, with 43 operable units in its arsenal, although a number of these have been temporarily shut down. Three are currently under construction.

Japan, China, South Korea “Japan was generating up to 30% of its electricity from nuclear power up to 2011. By the nuclear contribution was expected to increase to 41%, and longer-term plans were to double nuclear capacity (to 90 GWe) and nuclear share by 2050. However, following the Fukushima accident in March 2011, these plans have been scaled back, to nuclear providing 20-22% of electricity,” WNA explains.

After Japan, China places second on the WNA’s list with 26 operating nuclear power plants, and 44 in the pipeline.

“China is moving ahead rapidly in building new nuclear power plants, many of them conspicuously on time and on budget. Some under construction are leading new-generation western designs,” WNA notes.

Meanwhile, with 24 nuclear power plants in its portfolio, South Korea ranks third among Asian countries harnessing nuclear energy, with approximately a third of its electricity being sourced from nuclear power at present.

According to the WNA, “...the national plan is to expand to 36 nuclear power reactors by 2030, including advanced reactor designs, and achieve about 40% nuclear supply. Demand for electricity in South Korea is increasing by about 2.5% per year.”

Aside from constructing nuclear power plants from the ground up, South Korea is also making investments in the devel-

Atomic power plants in Asia

William Linton

Jonathan Hinze

Jonathan Cobb

opment of nuclear technology that may be exported abroad.

“In collaboration with US companies, South Korea developed the 1,000 MWe OPR-1000 nuclear reactor which is 95% locally-made, and may be exported to Indonesia and Vietnam.

The newer AP1400 model is based on it, and four are being built in United Arab Emirates in a $20 billion deal, having been sold against strong competition,” the WNA notes, in addition to the country’s $1 billion research and development undertaking and demonstration “aiming to produce commercial hydrogen using nuclear heat by about 2020.”

India, one of the most populous countries in the region, also boasts of a formidable nuclear portfolio with 21 nuclear power plants with six currently under construction.

As one of the most populous countries in the region, demand for power perennially outstrips supply, paving the way for growth opportunities for the nuclear industry. According to the WNA, India has attained independence in its nuclear fuel cycle, but nuclear power supplies less than 4% of the country’s electricity needs.

“There are six units under construction, including a second large Russian reactor, and four PHWRs. A further 22 reactors are planned beyond that, including four more Russian units and two modern French ones. Plans are for 15 GWe by 2020,” the WNA notes.

Like South Korea, India is also keen on developing nuclear technology for its plants. “India is a pioneer in developing the thorium fuel cycle, and has several advanced facilities related to this. A 500 MWe fast reactor is due to start up in 2015,” the WNA adds.

As countries ramp up the development of their respective nuclear programmes, analysts cite the region’s rapid economic expansion, led by China’s economic juggernaut, as a key driver behind the growth of nuclear power in the region.

“Asian populations and economies are globally the fastest growing. This growth has required and will continue to require more electricity generation. Of course, there are only so many ways to generate significant amounts of electric power,” says Linton, noting that the so-called “Big 3” of energy sources—coal, natural gas, and nuclear —depend on a host of factors for their successful development.

“Some countries with favourable climatic and topographical circumstances generate significant amounts of electricity through hydropower, [while] the growing popularity of wind and solar is being driven mostly by the desire to minimise environmental impacts. These sources will not by themselves produce sufficient and stable amounts of power to meet the needs of dynamically growing economies,” Linton warns.

Environmental factors Cobb agrees, adding however that the environment is also taking centre stage as more countries consider nuclear power. “As econASIAN POWER 21

sector report: Nuclear power in asia omies in the region continue to expand, demand for electricity is growing. Where this demand is being met with fossil fuels there are now serious concerns over the effects of air pollution today and climate change in the future,” Cobb says.

Compared to other forms of energy, nuclear power appears to offer a more environmentally friendly option. “Nuclear power has zero emissions and supports climate change goals. Additionally, there are many nations in Asia that lack sufficient resources of oil, gas, and coal, and nuclear power allows them to diversify away from expensive imports,” Hinze says.

For Asian countries, adopting nuclear power along with other forms of energy offsets any capacity deficiency in the grid. For nuclear power to succeed, this type of power must be developed alongside other energy sources.

A balance of sources “While renewables like wind and solar will also expand (probably faster than nuclear power in many places), these renewable energy sources are intermittent and cannot be relied on to completely support advanced economies. There are only a limited number of real options in this world to supply stable electricity, and this is why nuclear power remains a key source for so many current and potential future countries,” Hinze further explains.

Coal and natural gas, for instance, are two of the main forms of energy powering Asia’s economies today. However, a number of negative factors actually make them unwieldy choices in the long run.

“Many countries are discouraging coal generation through increasingly stringent regulations due to environmental concerns about CO2 (carbon dioxide) and other emissions. Natural gas is a limited resource that is expensive to transport in many regions.

It also has alternative uses such as chemical production. This means nuclear power has to be in the mix for the future of Asia and the appetite for Asian countries for nuclear power will be high,” Linton argues.

Safety concerns?

Despite the advantages of nuclear power in providing stable and reliable power, there remains pockets of opposition to this form of energy. In the past few decades, the biggest concern hindering the progress of nuclear power lay in safety. Indeed, this concern was further magnified in the aftermath of the Fukushima accident.

“It is understandable that people still do have concerns about nuclear power. Better communication is needed with the public, China’s total nuclear capacity by year, GW

* Data from World Nuclear Association Website Source: Energy Collective

22 ASIAN POWER

China will remain the leading growth country with more than 50% of all new nuclear construction in Asia in the coming 15 years.

particularly local communities,” Cobb said on the issue of safety concerns. “There needs to be a better dialogue and more information provided to allow people to reach more informed judgments on the use of nuclear energy.”

Indeed, the nuclear industry has already begun moving toward this kind of dialogue by adopting state-of-the-art technology to buffer concerns about safety in the event of a nuclear meltdown.

“New nuclear builds in the region will utilise modern reactor designs that have been developed with robust safety systems,” Cobb says.

There is also now a closer coordination among nuclear operators in Asia in terms of collaboration on nuclear safety issues, together with bilateral agreements between nuclear regulators in key Asian countries. Key groups handling nuclear safety in Asia include a regional centre of the World Association of Nuclear Operators and the International Atomic Energy Agency, which “...is also very active in promoting safe operations and information sharing around the world, including Asia.”

“Clearly, the Fukushima accident caused all of the current and potential new nuclear power countries in Asia to review and enhance their safety rules and oversights. Moreover, every one of the utilities has been required to install additional equipment to handle potential earthquake and tsunami events,” Hinze says.

China: the next nuclear frontier In the next few years, the region’s nuclear activity is expected to centre on China, the world’s largest economy and very much a regional power to be reckoned with.“China will remain the leading growth country with more than 50% of all new nuclear construction in Asia in the coming 15 years,” Hinze says.

Thanks to a burgeoning economy that has resulted in a surge of coal-fired power plants in recent years, China is now facing an array of pollution problems as the world’s largest carbon emissions producer, the WNA notes. According to the WNA, “...rapid growth in demand has given rise to power shortages, and the reliance on fossil fuels has led to much air pollution. The economic loss due to pollution is estimated by the World Bank at almost 6% of GDP, and the new leadership from March 2013 has prioritised this.”

At present, mainland China accounts for 26 nuclear power reactors, with 25 currently being constructed. “Additional reactors are planned, including some of the world’s most advanced, to give more than a three-fold increase in nuclear capacity to at least 58 GWe by 2020-21, then some 150 GWe by 2030, and much more by 2050,” the WNA states.

Not to be left behind, other countries have resolved to play catch-up as well with China’s nuclear muscle.

“I believe that many countries in the region will continue to keep nuclear power as a serious option for the long term. Japan’s reliance on nuclear power will diminish, but it will not completely turn its back on nuclear either. Taiwan remains an open question, but it will be very difficult for an island with few resources to replace the steady, low cost energy supply that its six operating reactors provide,” Hinze says.

Countries such as South Korea, India, and Pakistan will further expand their nuclear technologies, while other countries such as Vietnam, Indonesia, and Malaysia are likely to do the same by 2030.

At the end of the day, the success of the region’s nuclear industry will hinge on how effectively a country is able to execute its nuclear strategy. In an era of conservation and limits, nuclear energy manages to outweigh other energy sources when it comes to supply predictability.

“The challenge is to meet future energy needs in Asia cleanly, reliably and affordably,” Cobb says. “No one energy solution will be able to meet those needs for the whole region alone, but nuclear energy has clear benefits in terms of constant and predictable supply.”

ANALYSIS: vietnam’s power reforms

Thuy Dien Hòa Bình, the largest hydroelectric dam in Vietnam

How recent reforms in Vietnam improved investments in the power sector The unbundling of the power monopoly brings high hopes but effective change remains limited.

T

he unbundling of the power monopoly is expected to improve the commercial viability of the power sector. However, positive financial and operational results may not be expected as reforms in Viet Nam have only been implemented very recently. From 2008 to 2011, the Electricity of Viet Nam (EVN)’s annual net operating margins were negative. Its debt grew dramatically (from D86 trillion in 2007 to D246 trillion in 2012), and about 50% of the debt is due in less than 5 years. From 2007 to 2011, the EVN’s equity increased by 1.75 times, but its long-term liabilities increased by 2.72 times and its short-term liabilities by more than three times.

In 2012, the EVN’s financial performance reversed quickly, recording a net operating margin of 13%. This was mainly due to good rainfall levels (over which EVN and other entities do not control) and to the increase in tariff rates. But with the tariff rates still not at a costrecovery level, sustaining the improved financial performance remains a major challenge and a major deterrent to attracting investors. On a positive note, the EVN has succeeded in reducing 24 ASIAN POWER

Partly because of the poor financial performance of generating companies, private investment in power generation has been minimal.

time needed to collect revenue—from 84 days in 2008 to 68 days in 2012.

The generating companies’ finances cannot be assessed because historical data are lacking for some power plants.

Nonetheless, net operating margins of most power plants with available data are lower than international standards, with coal-fired power plants performing worse than hydropower plants. Operating costs were high partly due to overstaffing (especially in thermal power plants), inefficient processes, and aged equipment. Partly because of the poor financial performance of generating companies, private investment in power generation has been minimal.

In terms operational performance of the generating companies’ hydropower plants performed well above the international standards.

Thermal power plants In contrast, thermal power plants had underperformed. Coal-fired power plants more than 15 years old had the highest number of outages.

Power companies and the National Power Transmission Corporation had the same financial difficulties. During 2008 to 2011, the power companies

barely earned enough revenues to cover their operating costs. Their working ratios are below acceptable levels, which can be attributed to inefficient use of resources and low revenue collection because tariff rates are set below cost recovery level.

Although the situation had improved in 2012, the power companies’ net operating margins remained below a commercially acceptable level, and current account ratios were below acceptable standards.

The National Power Transmission corporation had bigger losses, with net operating margins from 2009 to 2011 (ranging from –7% to –29%).

Its financial position only improved in 2012 with a net operating margin of 13%, thanks to higher tariff rates, increased transmitted electricity, appreciation of the dong and higher equity value due to revaluation of assets. Because the National Power Transmission Corporation’s financial position was unstable, it relied on debt for capital investments. In terms of operational performance, the frequency of faults in transmission lines was aligned with acceptable standards but the duration of faults had increased to 52.24 minutes from

ANALYSIS: vietnam’s power reforms 35.37 minutes between 2009 and 2012. Low labor cost has resulted in overstaffing and has been linked to a lack of automation of processes.

Overall, generation, distribution, and transmission companies are still struggling financially. Although 2012 data indicate better performance, it is difficult to assert that the improvement is sustainable. The only consistent improvement is in the management of accounts receivable.

Limitations of reform The reform process has commenced functional unbundling of the industry’s monopoly structure, along with some institutional, regulatory, and pricing reforms.

The EVN has theoretically been unbundled, existing as a holding company with operating divisions.

Corporatization (equitization) has resulted in the creation of several state-owned joint stock companies, but little private ownership.

Effective change in market structure is still limited. The initial steps toward creating a competitive electricity market have been taken, with 10% of total generated power sold under PPAs purchased in a power market by prior-day bidding.

Viet Nam is already developing a legal framework for a pilot wholesale competitive market that is expected to be operational in 2017.

Clearly, the reforms and restructuring must continue to achieve complete independence among system players, including and especially the regulator, and this independence is a crucial prerequisite for implementing a competitive market. The question remains as to what extent restructuring has so far furthered the initial goals of reform.

In terms of progress toward economic efficiency and viability, some tariff reform has been introduced.

As part of the reform process, the scheme for formulating tariffs has been revised to provide more efficient cost recovery, to establish cost-ofservice or market-based rates, and to promote investment and efficient use of power, consistent with the government policy. Average retail tariffs are to be reviewed and adjusted annually to recover the EVN’s costs, and should be uniform throughout the country.

Cost-based transmission charges and distribution tariffs are calculated on the basis of both allowed revenue and the quality of service. Criteria for performance-based transmission rates are not yet established.

So far, however, only residential

and industrial tariffs are in principle designed to be cost-based while tariffs for commercial customers are not. The tariffs customers pay are supposed to be adjusted annually and quarterly according to variations in input parameters.

They are unbundled for four subsectors: generation, transmission, system administration and market operation, and distribution.

However, in practice, tariff adjustments have been delayed, breaking the link between tariffs and costs of supply, and transparent information on costs and revenue allocations is lacking. Generation prices are the largest component of the retail tariff. At present, there is little possibility for reducing these through operational efficiency, as 90% of sales are covered by long-term financial PPA contracts, the prices of which are not transparent and have been negotiated between generators and the government (usually the MOIT).

The PPA contracts range from 10 to 20 years for local IPPs and up to 25 years for a BOT. Special tariffs apply to renewable generation and small hydro plants, providing preferential pricing for renewable power.

A new PPA pricing scheme for future thermal generators will include a bracket of permissible costs based on the benchmark of a new power plant. However, prices will still be negotiated on a case-by-case basis and include fuel transport costs. The government has invested heavily in power sector improvements, but there are limits to public financing.

Investment funds As noted above, prior to reform, revenue was inadequate for operation, maintenance, and rehabilitation of existing plants, much less to accumulate investment funds for new capacity. Hence, in 2000, the government was forced to look beyond the EVN to provide continued and adequate electricity services. Entry of other generation started in 2000 with 452 MW or approximately 7.3% of total generating capacity.

This doubled to 14.8% of the total in 2004 (1,575 MW). A shortage of funds for expansion has also been evident in the years since reform, as revenues continue to be inadequate for investment. Investment in generation has fallen short of the Power Development Plan VI. Only 69.1% of the planned investment had been realized by 2010—10,081 MW of the planned 14,581 MW .

Similarly, actual investment in the

The initial steps toward creating a competitive electricity market have been taken, with 10% of total generated power sold under PPAs purchased in a power market by prior-day bidding.

grid amounted only to 40%–60% of what was planned for 2006–2010. The EVN is still responsible for assuring power supply and for investment in power generation, power imports and exports, and grid expansion to assure universal service. But mobilizing the capital projected as necessary for the requirements of the Power Master Plan VII may be difficult. The many varied claims for public funds limit the government’s potential for financing the power sector. Retail tariffs in principle will now include limited provisions for capital accumulation (investment in maintenance and system expansion) within a range of recoverable generation costs for new generation.

In practice, such returns are not likely to be achieved and the current pricing structure may not create incentives adequate to attract significant foreign investment to the sector.

In terms of governance and regulatory reform, more aggressive changes will be needed. The EVN generation company offices, information systems and other resources need to be further separated and a regulatory framework is needed for ring fencing the separate entities, with established codes of conduct and confidentiality requirements.

The generation companies should be audited periodically to ascertain whether they are operating independently. Rather than remaining part of a holding company structure, generating entities should become fully independent state-owned enterprises or joint stock companies as soon as possible, with private participation through equitization where feasible. In addition, the independence of the system operator must be confirmed as planned in 2015, as this is an essential prerequisite for attracting private sector capital.

By Economic Research and Regional Cooperation Department, Asian Development Bank

Viet Nam - Investment in Grid, 2006-2010

Source: Government of Viet Nam (n.d.), Power Development Plan VII, Chapter 2: Assessment of Power Investment.

ASIAN POWER 25

Country Report 3: Indonesia implementation can increase investors’ required returns for these projects.

Unfortunately, the lack of visibility as to the certainty of returns often makes it difficult to justify the level of risk.

According to global consulting firm, McKinsey, addressing Indonesia’s large infrastructure deficit is crucial in sustaining its rapid GDP growth in the short-to-medium term. In the longer term, failure to do so may result in compromising the longterm prospects of its economy.

The firm has noted that Indonesia’s infrastructure spending has been about 3-4% of the country’s GDP, but that is only half of what is required.

The World Bank estimates show that Indonesia has lost one percentage point (1%) annually as a result of the infrastructure deficit. This unfilled need presents a huge opportunity for businesses, with McKinsey estimating that even just 30% of Indonesia’s full Infrastructure needs would represent a $180B investment opportunity.

Borobudur nothwest view

PPPs fail to translate to more power projects in Indonesia

The lack of visibility as to the certainty of returns often makes it difficult for power investors to justify the level of risk.

T

he rapid growth of Indonesia’s economy has created a swelling demand for power, with the country’s National Nergy Council (the Dewan Energi Nasional or DEN) estimating a threefold increase by the year 2030. If this demand is unmet by new generation capacity, however, it would simply translate into power shortages rather than demand-led economic growth.

The generation capacity of Indonesia is about 206.5TWh (kilowatt hours) while demand stands at about 207Twh. At least 35GW of additional generation capacity was recently committed to by the Indonesian Government, to be built under their newly unveiled Public-Private-Partnership (PPP) projects in order to augment the existing 53GW of capacity.

The Public-Private-Partnership system The large amount of capital expenditure involved in infrastructure development means that the government cannot finance the project in its entirety. PublicPrivate-Partnership projects allow the government to effectively farm out the entire project (and necessary investment) from construction, operation and 26 ASIAN POWER

The large amount of capital expenditure involved in infrastructure development means that the government cannot finance the project in its entirety.

decommissioning and regulate the terms. Indonesia’s Ministry of National Development Planning (BAPPENAS) has pegged the total investment required between 2014 and 2019 to be about IDR5.45 trillion (approximately USD450B). Only about 22% of this can be financed by the government, with the rest being covered by private entities.

The government has also made other strategic moves intended to spur the development of energy generation in the country, such as the ban on the export of raw nickel for example. Policies like these are meant to encourage the private sector to invest in local manufacturing and the related infrastructure supporting its operation such as roads and power generation capacity.

The Public-Private-Partnership system has been already been in place for close to ten years, but has translated to the awarding of very few projects, according to law firm, Baker & McKenzie. The old legislation included a number of restrictions that prevented numerous projects from being awarded, or decreased investor appetite for undertakings of that nature Uncertainty and problems pertaining to the qualification, awarding and

PPP’s Implementation Gap While PPP’s are a sound concept on paper, they have proven to be less so in practice when it comes time for actual execution. The system allows governments to systematically plan projects, budget them, then orderly tender them out for bidding from the private sector. It has not worked as such in practice, especially in Indonesia.

Despite the system being designed to facilitate the orderly tendering of projects, there are still risks for private sector bidders looking to qualify for a project, according to McKinsey.

The first is the transparency of qualification criteria for selection and prioritisation of projects. For example, the Pondok Gede Water Supply project was already classified as “ready for offer” in 2011, but was suddenly downgraded to “priority” in 2012 without explanation.

The second is that the choice to execute a project through the PPP system is viewed by administrations as a financing choice rather than a different category of projects altogether, and that they are perceived to be complex to implement.

Because of the risk involved in dealing with private sector firms and other stakeholders in the project, those tendering out projects often prefer to use public funds or international grants rather than execute a project via a PPP As a result, the choice to tender through a PPP tends to become a last resort, and often gets used for lower-priority projects. Lastly, the complex nature of PPP’s requires a deep understanding of corporate finance and economics on both sides, with many government

Country Report 3: Indonesia agencies lacking the skills to properly assess them. Project evaluation for a PPP involves extensive analysis of the risk-return parameters to the private contractor, along with the estimation of cash flows and their risk-adjustment.

They also require appropriate knowledge regarding structuring of the project terms to ensure a fair deal, meaning citizens are not charged overly-high tariffs, but the private contractor is able to earn its WACC plus an appropriate spread.

A new legislation Indonesia has passed new legislation recently in an attempt to improve the PPP process and boost investor interest, with the issuance of Presidential Regulation No. 38 of 2015 on Cooperation between Government and Business Entities in Procurement of Infrastructure (“PR 38/2015”).

The issuance changed a number of key rules which were often stumbling blocks for the awarding of projects in the past.

Agung Wiryawan, a director at PwC Indonesia noted that there were three key changes introduced by this new piece of legislation: the allowing of unsolicited bids for projects, introduction of availability payments, and opening of a facility for government support or guarantees.

Specific government agencies for the financing and guarantee of project finance have also been set up, which helps to alleviate the concerns on the creditworthiness of issuing agency, Perusahaan Listrik Negara (PLN). These new agencies are meant to serve as alternatives to PLN and are expected to be recapitalised or bolstered with government guarantees in order to alleviate concerns from providers of project finance.

On the return side, the new issuance has set up an alternative method, the Availability Payments facility, by which bidders can earn their returns. This is meant to help ensure the “bankability” of projects farmed out for PPP. The administration is

hoping that this will improve the access to project finance along with boosting investors’ appetites, given the improved risk profile in the process.

Power is priority Wirayawan says that power generation capacity remains a priority sector for Indonesian Infrastructure. The government has affirmed this through the launch of a recent series of projects representing 35GW of capacity.

Shobana Venkataraman, principal investment officer at International Finance Corporation (IFC) explains that over 50% of generation capacity over the next five years will be done through the PPP system in order for the government to meet the projected demand growth of 8% per annum.

Large blocks of capacity are already under tender, according to Venkataraman. On the revenue side, the new legislation also provides for a direct appointment mechanism for power projects and a tariff cap, in order to avoid complications as to returns.

He notes that the government has been pushing quite hard to get these projects done and feels that these recent initiatives are affirmation of that.

On a related note, the government has to improve the bankability of projects it tenders out as well, given that the quality of project finance will also depend on this. Ray Tay, senior analyst at Moody’s Investors Service, notes that one of the most important credit factors in the Moody’s project finance credit rating score is the cash flow stream that supports a project’s debt load.

Common practice in PPP’s is to finance a significant chunk of the project with debt, for two main reasons. The first is the lower the WACC or hurdle rate required on the project. Because of the relatively lower returns on invested capital (ROIC) caused by capped tariffs, leverage is often employed to raise the return on equity (ROE) to acceptable levels for the contractor. The second is

Number of public-private partnership (PPP) projects in Indonesia

Source: Business Monitor International, National Development and Planning Agency (Bappenas)

Ampera bridge at night, Palembang

While PPP’s are a sound concept on paper, they have proven to be less so in practice when it comes time for actual execution.

due to the recurring nature of the cash flows involved in large-scale industrial projects such as infrastructure.

From an asset-liability management standpoint, an operator can confidently lever up as the cash flow stream is stable.

Government guarantees from more reputable agencies than PLN, however, will still be instrumental in the freeing up of financing for these projects.

Challenges still exist for investors interested in PPP’s despite the more accommodative regulations. For example, land acquisition is still an issue, as it has always been. The ability to acquire the required land from the local owners to build the project is an issue that remains unresolved, despite the amendment of the Land Acquisition Law. IFC’s Venkataraman notes that there are instances in which there is delay due to uncertainty surrounding land acquisition and government support.

Even in instances where the site has not been identified, there could be some sources of uncertainty and delays as he says “further work on environmental and social aspects needs to be done up-front, including community consultations.”

Additionally, the availability and structure of project finance will be crucial for all PPP’s moving forward.

As was mentioned previously, the creditworthiness of PLN is still questionable; the new agencies established for the providing of financing must be enhanced. The entire PPP qualification process still takes an extremely long time, with the whole process requiring at least 710 days. Infrastructure opportunities still abound in Indonesia, and hopefully new regulation will encourage additional investment in these projects.

ASIAN POWER 27

analysis: india power

India One Solar Thermal Power Plant, India, Brahma Kumaris

Why India’s power sector is still stuck in the doldrums despite government’s efforts

Lower electricity offtake by state-owned distribution companies have increased the risks for generating companies.

O

n October 19, 2011, CRISIL had predicted that India’s generation sector will face fuel scarcity and pricing problems in the medium term, and underlined that close to a third of the capacity under implementation at that point in time will be affected. As things stand, nearly a third of the coal-based capacity additions done between April 1, 2009, and March 31, 2016, are facing viability risk. That’s not all: nearly 40% of the gasbased capacities have also become unviable.

Reason? Shortages in domestic coal supply, and dwindling gas supplies from the D6 block in the Krishna-Godavari basin. Further, aggressive bidding for projects and lower electricity offtake by state-owned distribution companies (discoms) have increased the risks for generating companies.

To be sure, the government has not been a mute spectator.

It has been quite proactive, trying to iron out the creases. For example, in 2012, it facilitated the implementation of a financial restructuring package (FRP) for discoms. Then there was a Presidential Directive on July 17, 2013, asking Coal India to sign fuel supply agreements (FSAs) for 78,000 mw of capacities to be commissioned by March 31, 2015. This was followed by the creation of a framework to auction coal mines de-allocated by the Supreme Court. A chunk of them were put on the block in 2015 to end disruption in feedstock supply. A mechanism was also devised to fire gas-based plants using subsidised and imported re-gassified liquefied natural gas (RLNG).

So yes, there have been admirable efforts made to address woes, but the crux of the matter is that India’s power sector remains in doldrums.

Private sector coal-based plants dominate new capacity additions since 2009 India’s electricity generation capacity has grown at a CAGR of 10% since April 2009. Of around 119,000 mw of capacity added, 28 ASIAN POWER

Except in fiscal 2014, the energy requirement of discoms has been driven by consumption growth. In fiscal 2014, discom demand grew only 0.4% even as actual consumption grew at 7%.

nearly 87,000 mw is coal-based.

Private sector contributed the most - nearly 60% - of the new coal-based capacities by investing around Rs 320,000 crore. Central power generation companies added 21%, and state-owned ones theleast. Consequently, the private sector’s share in India’s coal-based power generation capacity galloped to 35% as on March 31, 2015, from 7% as on March 31, 2009.

New capacities reduce power deficit, but lower energy demand of discoms hit PPAs Despite inadequate fuel supply, significant growth in generation capacity has led to energy availability increasing at a compound annual growth rate (CAGR) of 6% in the last three years, outpacing the energy requirement of discoms, which grew at CAGR of 4% . Arithmetically, this has reduced India’s base power deficit to 3.6% last fiscal from 8.5% in fiscal 2012.

Except in fiscal 2014, the energy requirement of discoms has been driven by consumption growth. In fiscal 2014, discom demand grew only 0.4% even as actual consumption grew at 7%. Had it synced with consumption growth, demand would have risen by another 10,000 mw. A portion of this could have translated into Power Purchase Agreements PPAs. The lower energy requirement of discoms has meant fewer PPA bids were announced – just 10,000 mw in the last three years, or equal to what was signed in fiscal 2011 alone.

Consequently, there has been an increase in private sector capacities without PPAs in the last three years. If PPA signing does not commence soon, by the end of fiscal 2016, nearly 15% of private sector capacities -- or 10,000 mw -- sans PPAs will be exposed to the vagaries of the short-term electricity market.

Going forward, signing of new PPAs will depend on the ability of discoms to enter into long-term commitments, which means generating companies will till then be exposed to volatile

analysis: india power prices in the short-term market. After falling to Rs 2.07 per unit in August 2013, they increased to Rs 4.33 in October 2014 only to tumble anew to Rs 2.56 per unit in June 2015. CRISIL believes that merchant power prices will remain subdued over the nearto-medium term on account of large untied capacities leading to increased competition in the merchant market.

Additionally, PPA bidding under the Case 2 route (where land availability, fuel, and clearances are taken care of by states) was impacted by issues pertaining to bidding documents. In the last few years, the government had invited bids for 4,000 mw ultramega power projects in two states -- Orissa and Tamil Nadu -under Case 2 bidding. The response from private developers was tepid due to lack of clarity in regulations pertaining to ownership of the plant. Case 2 bidding guidelines mandated project assets be handed over to state utilities after successful completion of the concession period, which left lenders wary. Going forward, successful bidding for these projects will depend on modification of standard bidding documents, which is currently being reviewed by a government-appointed panel.

But guess what, there is enough latent demand Rough calculations show India would have become a power surplus nation (where base deficit gets wiped out) if its installed thermal capacity of 165,000 mw operated at a PLF of 70%). However, the reality is that India’s latent demand is much more than the energy requirement estimates of discoms. Per capita power consumption is low because large swaths of population are yet to get access to electricity. And despite low power deficit, outages remain high.

After fiscal 2009, Coal India refrained from signing FSAs for upcoming power plants because domestic coal production was stagnant. For agreements already signed, it was meeting 90% of the annual coal requirement. However, after the Presidential Directive, Coal India signed FSAs with 78,000 mw of capacities that were to be commissioned by March 31, 2015. Under this, the largest miner was supposed to meet 65% of the annual coal requirement of the plants but eventually came up short.

The problem was that growth in domestic coal production was muted at a CAGR of less than 4% between fiscals 2009 and 2014 – not good enough to stay apace with demand and capacity additions. But in fiscal 2015, domestic coal supplies to power sector rose 10.7% as Coal India ramped up mining. Speedier environment clearances and land acquisition, coupled with concerted efforts by Coal India, led to the increase in production.

However, domestic availability is still below what is required to operate installed capacities at the normative PLF of 85% stipulated by the Central Electricity Regulatory Commission (CERC).

CRISIL’s calculations show that India’s coal-based power generaImproving production from Coal India and captive blocks

Source: CRISIL Ratings, Coal India Ltd., Central Electricity Authority

Domestic availability is still below what is required to operate installed capacities at the normative PLF of 85% stipulated by the Central Electricity Regulatory Commission (CERC).

tion plants require about 713 million tonne of coal in fiscal 2015 to operate at 85% PLF. But domestic supply stood at 451 million tonne and 90 million tonne was imported–totalling to 76% of what was required – because of which, the all-India thermal PLF declined to a decadal low of ~65% in 2015. We believe domestic coal production is likely to grow at a healthy CAGR of 9% in the next three years as Coal India -- and captive mines allocated in the recent round of coal block auctions and allotment – crank up production. Yet imports will be in the range of 100-105 million tonne because of the requirements of new capacities.

Between April 1, 2009, and March 31, 2015, nearly 87,000 mw of capacities were commissioned. Following an improvement in domestic coal production, PLFs at these plants improved to an average of 41% in fiscal 2015 compared with 37% in fiscal 2013 (We arrive at this number by assuming that the entire incremental coal production after 2009 was used to fire incremental capacities commissioned after 2009).

With Coal India producing and supplying more, and production from captive coal blocks on the rise, we see PLFs of thermal capacities that have come up after April 1, 2009, improving even further to an average of 45% in the current fiscal. But this remains a very sub-optimal level and exposes generating capacities to fuel availability risk, impacting viability. That’s why we believe fuel availability risk is particularly high for these projects.

Some domestic coal-based projects which enjoy Availability Based Tariff (ABT) – where fuel-cost passthrough is allowed -will be able to report plant availability factor (PAF) and recover their fixed charges. However, players that do not have ABT are subject to high fuel availability risk as they will not be able to blend expensive imported coal or e-auction coal.

To address this issue, the government has allowed passthrough of fuel costs in the standard bidding document, thereby facilitating blending of imported coal.

For projects based on imported coal, aggressive bidding and weaker rupee offset gains from lower international coal prices Competitively bid out imported coal-based projects, which can’t pass on fuel costs, are exposed to fuel price risk. These projects were bid out quite aggressively with no scalable fuel charge component at a time when the price of coal imported from Indonesia was low. But later, the Indonesian government changed the rules, which made imports costly. This significantly dented the cash flows of the projects. While the prices of imported coal have declined in the last four years, this has been offset by a significant depreciation in the rupee, leading to continued under-recoveries on variable cost. Further, aggressive bidding sans return on equity (RoE), cost overruns and rupee depreciation are also leading to under-recovery in fixed costs for these projects.

Our analysis reveals that the levelised tariffs approved under competitive bidding for these projects based on international coal are significantly lower than these levels. These projects had sought compensatory tariffs for the cost under-recovery. The CERC approved variable cost under-recovery in February 2014, but discoms appealed against the order in the Appellate Tribunal of Electricity (APTEL), which provided interim relief by allowing compensatory tariff until final proceedings are complete.

However, the Supreme Court stayed the interim order passed by APTEL after a petition by discoms. The final decision on compensatory tariff is pending. CRISIL believes, despite compensatory tariff, these projects will continue to have under-recovery on fixed charges which will impact their viability.

Winner’s curse: Private sector aggression continues After the de-allocation of coal blocks by the Supreme Court in September 2014, the government concluded the first phase of auctions in a timely manner. Reeling under chronic supply shortage, private sector companies bid very aggressively for nine coal blocks which had fuel to fire around 6,500 mw. This approach ASIAN POWER 29

analysis: india power showed strategic fuel security had become more important than profitability. The bidders, who had agreed to a zero fuel charge in their PPAs, thus foregoing mining costs, also agreed to pay a forward premium of Rs 100 to Rs 1,010 per tonne to the state government concerned. With mining cost and forward premiums not recoverable through the variable charge component in PPA, bidders were exposed to the risk of underrecovery. Some of these capacities are yet to sign PPAs, so they could have sought higher fixed charges to compensate for the under-recovery in variable costs. But as per the revised Case 1 bidding guidelines, where bids are invited from players having domestic captive coal mines, the buyer of electricity has to cap fixed charges per unit in consultation with the state electricity regulator. That means, depending on where the tariff is capped, there could be under-recovery.

Gas-based units hit by dwindling feedstock supply; RLNG auction provides only interim relief enabling interest servicing Domestic production of natural gas has been falling since fiscal 2012, mainly because of a precipitous decline in output from the D6 block -- from 55 million metric standard cubic metre per day (mmscmd) in fiscal 2011 to 14 mmscmd in 2014.

The shortfall has meant a sharp deterioration in both the credit quality of power projects based on domestic gas, and PLFs. Nearly 14,000 mw of gas-based capacities were completely stranded (zero PLF), while 10,000 mw capacities were receiving limited supply and operating at a sub-optimal PLF. To ameliorate the situation, the Ministry of Power came up with a scheme to e-auction imported RLNG, and conducted it on May 12 and 13, 2015.

The scheme provided for a per-unit tariff subsidy from the Power System Development Fund (PSDF). This will be disbursed -- based on a reverse auction mechanism -- to stranded gas-based power plants first and then to plants already receiving domestic gas. Between June and September 2015, PSDF support equivalent to Rs 844 crore is allotted for this mechanism.

Further, the delivered price of the e-bid RLNG is estimated to be around $3 per mmBtu lower than spot RLNG prices because of support from various stakeholders in the form of reduced marketing margins, re-gassification charges and transportation charges, apart from customs and sales tax waivers. This translated

Bathinda Power Plant, Punjab, India 30 ASIAN POWER

Private sector capacities without PPAs are increasing

Source: CRISIL Ratings, Coal India Ltd., Central Electricity Authority

into Rs 870 crore of support – over and above the subsidy support.

In the auction, plants with 7,000 mw of capacity successfully bid for subsidy under PSDF. The average subsidy is around Rs 1.43 per unit and the tariff to be charged to discom is Rs 4.7 per unit.

Thus, revenue of around Rs 6.13 per unit will be available to these power plants.CRISIL believes the scheme will enable this 7,000 mw stranded capacity (out of a total 14,000 mw) to operate at around 27% PLF – which is good enough to service their interest payment obligations. So the success of the scheme will depend on the availability of a principal moratorium period from lenders and the ability of power plants to find buyers for electricity at Rs 4.7 per unit. Further, out of the 10,000 mw of capacities that are already operating at sub-optimal PLF, nearly 3,500 mw has won RLNG supplies through the auction. CRISIL believes that the PLF of these capacities willimprove to 32% from last fiscal’s 24%. Since this is not very significant and most of these players already have a favourable availability-based tariff structure that facilitates costrecovery, the scheme is unlikely to materially benefit them.

Then there is the currency issue To add to all the woes, many power producers faced cost overruns due to a sharp depreciation in the rupee against the dollar. These developers had contracted foreign currency debt in a benign macro-environment between fiscals 2009 and 2011 and left the exposure unhedged. They are now facing the exchange rate heat.

These capacities also face the risk of under-recovery in fixed cost.

Net-net, 46,000 mw at risk CRISIL believes the viability of around 46,000 mw of capacities is at risk today. Of this, nearly 36,000mw are coal-based and nearly 10,000 mw gas-based. This includes 33,000 mw out of the 87,000 mwof coal capacities added between April 2009 - March 2015, and 3,000 mw of capacities expected to becommissioned by March 2016, for the following reasons: (1) For nearly 3,000 mw of capacities, there are no long-term buyers, so they are susceptible to the vagaries of the short-term electricity market; (2) For nearly 16,000 mw of capacities, the inability to pass on higher price of imported coal, and aggressive bidding done to win projects are leading to under-recoveries; (3) For nearly 13,000 mw of capacities, coal supply is inadequate leading to sub-optimal PLF. Some projects are also hit because their coal blocks got de-allocated; (4) For nearly 4,000 mw, aggressive bidding to win coal blocks and no recourse to a pass-through have meant under-recovery of fuel cost even as fixed cost is capped. (5) And nearly 10,000 mw of gas-based capacities are at risk, including those that have won subsidised RLNG (which will only help service interest payment obligations), and stranded ones with zero PLF. By CRISIL Ratings

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6

OPINION

JOHN GOSS

Maximising the utilisation of green energy in China

john.goss@aod.com.hk

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plan to maximise the use of green energy generation has recently been issued by China’s National Energy Administration (NEA). The plan gives emphasis to the future use of what it refers to ‘a micro-grid’ of new renewable energy resources.

This micro-grid would be an intelligent local network that would enable the maximum use of different types of green energy, such as solar and wind power and to be utilised effectively. This statement reflects the nation’s pledge to curb its greenhouse gas emissions. It is clear that that China needs to be more proactive in installing solar and wind power plus other forms of green and cleaner energy in the country.

Rapid implementation will serve to meet recent ‘clean energy’ commitments as other resources such as nuclear power and hydropower are held back by availability and safety issues. China is planning to add something like 18 GW of solar power capacity across the country in 2015. The nation’s greenhouse gas emissions have increased significantly

since 1997 when the last climate deal was signed.

This means that the country now accounts for more than a quarter of the global total of greenhouse gas emissions. China’s energy authorities have pledged to peak the country’s emissions around 2030. They are setting targets for obtaining 20 percent of all the country’s generated power capacity from nuclear power and renewable power by this date.

To reach this target figure, China would have to install and utilise around 30 times more solar power than the country had at the end of 2014, or nine times more wind power generation. These pledges come at a time when China’s energy authorities are slowing down or stopping any further expansions of coal-fired power plants. These coal burning power plants consume most of the nation’s fossil fuels.

The NEA has reported that China, as the world’s largest energy consumer, generated 11 percent of its primary energy from non-fossil fuel resources last year. This figure included power generating capacity from both nuclear power and renewable power.

peter hopper

The future of Hong Kong’s electricity sector

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istorically, two family-owned and publicly-listed power companies – Hong Kong Electric and CLP Power Hong Kong, have supplied electricity directly to Hong Kong’s homes and businesses. Both companies are vertically integrated such that they own and operate generation plants and transmission and distribution networks.

Their operations have been regulated by the Government through a Scheme of Control Agreements (SCA). It was negotiated and designed with incentives to ensure that the power companies would provide sufficient levels of investment in plant, equipment, and maintenance to meet current and future electricity demand.

At the same time power producers are entitled to earn a permitted rate of return on their average net fixed assets. The current SCA will expire in 2018. Although the government has an option to extend the existing agreement for another five years, it launched a three-month public consultation starting in March, which concluded with the

32 ASIAN POWER

collection of public feedback at the end of June, to help decide future energy policy.

In the public consultation paper on the development of the electricity market published in March, the Government proposed to reduce the permitted rate of return from the current 9.99% to 6-8%.

It also suggested a tightening of both the excess generating capacity mechanism and the tariff approval process in order to cover fuel cost estimates.

It will also commence preparation work to pave the way for introducing market competition after 2028. The two power companies are expected to make a formal response sometime after the end of the consultation period. The lowering of the permitted rate of return and deciding whether more competition should be allowed in order to offer customers more choices have been a source of contention and debate.

An inconvenient truth Everyone seeks affordable and reliable electric-

This figure is up from 9.8 percent in the previous year. The proportion of coal usage shrunk to 64.2 percent last year, down from 66 percent in 2013.

A five year push for renewable power in China In the recently issued 13th Five Year Plan (20162020) on energy planning and implementation, China is aiming to increase offshore oil and gas exploration and to raise its output targets for renewable energy. In this government-issued plan there will be a special focus upon increasing the installed capacity of both wind power and solar power.

Around ten years ago, the majority of the manufacturing, installation and utilisation of renewable energy capacity occurred in the US, Japan and Europe. The renewable energy markets, manufacturing and investments have now shifted to other global regions, says the Global Status Report from the Renewable Energy Policy Network for the 21st Century.

The report says that China has now become the world leader in renewable manufacturing and installed as the nation increased investment into the renewable power sector nearly every year for the past decade.

China’s Premier Li Keqiang has recently promised that China will cut carbon emissions per unit of GDP by 60 percent to 65 percent by 2030, compared with 2005 levels. The country has already stated that it is to have 200 GW of wind power and 100 GW of solar power by 2010.

One thing is certain - when the Chinese government says it will achieve and implement something in the country’s energy sector, it gets done. ity prices and supply through an efficient system.

However, environmental protection and air pollution reduction are also key objectives of Hong Kong’s energy policies. Electricity generation has been identified as a major source of air pollution in Hong Kong. Meeting these seemingly conflicting goals requires a careful examination of all the issues and arguments.

The Government has already implemented a number of stringent control measures on power sector emissions over the past years. They include the prohibition of the installation of new coal-fired power plants, introducing incentive schemes that encourage the power suppliers to meet emission standards and the tightening of emission caps for the power plants.

The Government addressed the public’s environmental concerns in 2014 by launching a threemonth public consultation on the future fuel mix for electricity generation which ended in June. The design of future fuel mixes for electricity generation is based on emission targets. They were established to cut Hong Kong’s carbon intensity by 50% to 60% by 2020 based on 2005 levels. However, achieving these targets could substantially affect the cost for end users and they are still subject to public acceptance of the tariff implications.

Meeting emission targets is mandated in Law and the transition to cleaner fuels inevitable. The question is, what are consumers prepared to pay and do they fully realise the implications of this move on tariffs and needed investment?

DOOSAN