Asian Power (January - March 2019)

ISSUE 91 | DISPLAY TO 31 March 2019 | www.asian-power.com | A Charlton Media Group publication

US$360P.A.

ACWA POWER

bUILDSWORLD’S

LARGEST CSP

hERE’S WhAT hAPPENED IN ACWA POWER CEO PADDy PADMANAThAN’S $5B BID TO BuIlD ThE lARGEST CONCENTRATED SOlAR PROJECT IN ThE WORlD

CAN INDIA HIT ITS 2022 ENERGY GOALS? HOW CAN ASIA KEEP WIND POWER bLOWING? WHAT’S bEHIND CHINA’S ENERGY TRANSITION? WILL ASIA DOMINATE ENERGY STORAGE?

working towards a more sustainable future

STELCO power generation

power distribution

For over 70 years, STELCO has been the leading power producer in the Maldives. Today, our power generation facilities and transmission networks provide power to a majority of the population, including the capital city Male’. We are a state-owned enterprise operating 35 independent power plants with a total combined generation capacity of over 129 MW. We also operate 4 desalination plants to supply drinking water to the public in 4 different island communities.

power retail

As the single largest producer of electricity in Maldives, we have been continuously working to integrate renewable energy into our power grid. This is in line with our commitment to striving for a greener and sustainable future. We will strive to work towards providing safe, reliable and affordable power solutions in a sustainable manner, utilizing commercially viable and modern technologies.

STATE ELECTRIC COMPANY LIMITED (STELCO)

A m e e n e e M a g u , M a l e ’ , Re p u b l i c o f M a l d i v e s

+960 332 0982

fax

+960 332 7036

admin@stelco.com.mv

stelcomaldives

www

www.stelco.com.mv

FROM THE EDITOR Asian Power’s first issue of 2019 tackles the breadth and depth of China’s energy transition, as shown by the conversion of 38% of its power sources into renewables. A newly opened retail market has spurred over 3,000 new companies and analysts think the monopoly is eroding fast, but new forms of consolidation are also possible. Find out more on page 14.

Publisher & EDITOR-IN-CHIEF Tim Charlton ASSOCIATE PUBLISHER Rochelle Romero production editor Danielle Mae V. Isaac Graphic Artist Elizabeth Indoy

ADVERTISING CONTACT Crizzle Naron crizzle@charltonmediamail.com

ADMINISTRATION Accounts Department accounts@charltonmediamail.com Advertising advertising@charltonmediamail.com Editorial ap@charltonmedia.com

The growth of India’s economy as well as its demand for energy over the years has leapt remarkably fast, so the government has to catch up by setting a 175GW renewables target that it has to reach by 2022. However, experts are scratching their heads on the direction the country is headed to as inconsistent reforms have impaired the momentum of solar auctions and equipment production. Read more on page 18.

We also sat down with ACWA Power CEO and president Paddy Padmanathan, awarded CEO of the Year 2018, who shared the behind-the-scenes of the world’s largest concentrated solar power plant. The company is also expanding to the Asia Pacific with its pending entry into the Indonesian electricity market. Read on what Padmanathan has to say on page 13.

Start flipping the pages and enjoy!

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ASIAN POWER 1

CONTENTs

20

22

INterview 12 CEO ACWA Power builds world’s largest single-site CSP

secTOR REPORT Key solar markets shed subsidies and shift to auctions

Analysis

FIRSTS 06 Doom and gloom for Australia’s gas plants

Sector report Hurdles slow down Asia’s race for wind power

26 How China turned into the last resort for coal plant developers

07 Indonesia’s unrelenting grip on coal

OPINION

08 IPPs target Vietnam deals 10 Energy storage systems take off in Asia

Country report 14 Stakes are higher in China’s energy transition 18 Rising costs screw India’s 175GW energy goals

28 Can PV systems provide resilient electricity to earthquake

prone areas in Indonesia?

30 Chinese wind turbine manufacturers poised

to overtake their European counterparts

32 Taiwan’s referendum on nuclear and feed-in tariff

reductions – implications for investors

24 Malampaya is running out of gas, what’s next?

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

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

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

PROJECT

Enterprize Energy eyes 3,400MW offshore wind park in Vietnam UK-based Enterprize Energy has revealed plans to develop a 3,400MW offshore wind park in Ke Ga, off the south central province of Binh Thuan in Vietnam. This huge project will require total investments of at least $12b and will be carried out in several 600 MW phases.

REGULATION

Offshore wind developers reject Taiwan’s planned feed-in tariff cut The Ministry of Economic Affairs mulls cutting the feed-in tariff rate for offshore wind power projects by 12.71% and proposed to slash the FIT rate from 18.9 cents per kWh to 17 cents per kWh. In response, a joint statement by four wind developers called this “unacceptable.”

4 ASIAN POWER

PROJECT

South Korean financiers urged to drop investment in Indonesian coal plants Environmental groups in Indonesia have called on South Korean financiers Export-Import Bank of Korea, the Korea Development Bank, and the Korea Trade Insurance Corporation to drop funding for two coal-fired plants that will be added to the Suralaya power complex in Jakarta, Indonesia.

REGULATION

Vietnam to raise electricity prices in 2019 The Ministry of Industry and Trade and EVN said that some factors that could raise the prices of power are growing.

The government is developing a power supply plan for 2019, which includes four different scenarios based on the predicted growth rates of electrical load and the predicted amount of water to be received by power plants.

REGULATION

Indonesia unveils net metering scheme for PV installations Indonesia’s new net metering scheme will make sure residential, commercial and industrial PV installations are entitled to sell excess power to the grid. A ministerial decree said provisions will boost the installation of 1GW of PV systems and the savings of PV systems owners’ bills by 30%.

POWER UTILITY

Vietnam unveils draft for solar projects’ new feed-in tariffs The Ministry of Industry and Trade of Vietnam proposed new mechanisms for feed-in tariffs (FIT) to be used for two additional years (1 July 2019 to 30 June 2021) for grid-connected solar power projects as well as new tariff guidelines for the development of rooftop solar.

CO-PUBLISHED CORPORATE PROFILE

First unit of PT Tanjung Power Indonesia’s 200MW power plant in Kalimantan set for early operations in 2019 It was constructed six months before financial close, marking an achievement other firms are not willing to try.

T

he first unit of PT Tanjung Power Indonesia’s (TPI) 200-megawatt (MW) coal-fired power plant, called KALSEL-1, in the Tabalong district in South Kalimantan, Indonesia is set for official commercial operations in early 2019, according to officials from TPI—which is relatively earlier than previously projected.

But what is the reason? Construction of the company’s project, which consists of two units of 100 MW capacity each, was started in June 2016—almost six months before reaching financial close, something that other firms will not do given the risk.

TPI, a consortium of PT Adaro Power (65% share) and PT East-West Power Indonesia (35% share), largely utilised shareholder funds before Financial Close to finance the construction, demonstrating Adaro Power’s and PT East-West Power Indonesia commitment and belief in supporting the Government of Indonesia’s 35,000 MW programme to power the country’s growth and development.

Powering Indonesia “I think what makes it stand out is—first of all—this is part of the 35 GW programme of the Government of Indonesia. Secondly, we fast-tracked the project ourselves,” said Dharma Hutama Djojonegoro, president director of PT Tanjung Power Indonesia “We started construction even before the financial close because of our commitment to the government.”

In a separate report, Adaro Energy President Garibaldi Thohir noted that the project is another significant milestone for the company’s efforts and commitment to be a key player to the Government of Indonesia’s goal of bringing electricity to all people in the country.

“The successful financial close [of the project] underscores our strong commitment to be a major contributor in ensuring the success of the 35,000MW programme,” he said, adding that the project is a testament to the company’s objective of developing a power business fit for the future and creating synergies with their existing coal business. “We are now focused on executing the plans of TPI to increase access to electricity in supporting Indonesia’s growth,” he elaborated.

The project’s total cost is estimated to be $545m. The financing is done on a non-recourse project financing basis.

Equipment innovation The project will sell electricity to Perusahaan Listrik Negara (PLN) under a power purchasing agreement (PPA) for a period of 25 years from the commercial operating date. The Government of Indonesia, through the Ministry of Finance, has provided a government guarantee to this project in the form of a Business Viability Guarantee Letter, where the government guarantees PLN’s ability to fulfil its payment obligations as stipulated in the PPA. This is in support and complementarity of the Government of Indonesia’s massive electrification push in the whole country.

TPI is applying advanced Circulating Fluidized Bed (CFB) Boiler Technology compared to other IPP companies in Indonesia. The latest technology applied is the Integrated Heat Exchanger (INTREX).

INTREX technology causes heat exchange and keeps appropriate furnace temperature and stable emission, in order to stabilise plant operation. In

terms of air emission, application of CFB Boiler allows limestone injection which will remove sulphur dioxide from flue gas and reduce nitrous oxide emissions due to its low combustion temperature. TPI will also use bag filters to eliminate ash emissions.

Safety is always a top priority for TPI, which has managed to successfully achieve 15 million manhours without lost time incident (LTI). According to Dharma, “TPI’s focus in 2019 is to achieve Plant COD in H1 2019 as planned, achieve operational excellence and be a reliable power producer to enable PLN to serve the greater Kalimantan area.”

PT Adaro Power (Adaro Power) as TPI shareholder, currently has three assets in their portfolio, as proof of their expertise and experience in the area.

“We have an operational asset, a 2 x 30 MW plant. We are building this one, which should have a COD in H1 2019. We also own a stake in a 2x1,000 MW project in Central Java. The focus within Indonesia is to finish the construction of these plants on time and on budget, of course,” Dharma said. He also elaborated that Adaro Power is also looking at regional opportunities, particularly in looking for growth pockets as the Asia and the Pacific region is projected to continue growing over the next few years. This is the next growth phase for Adaro Power as demand in the region for energy grows.

As for the international connections and international standards that TPI holds, the president director noted TPI’s nature as a joint venture between Adaro Power and PT East-West Power Indonesia, a subsidiary of Korea East-West Power Co. Ltd. “We’re quite happy to get international recognition for the quality of our project. We’re hoping that we could get many more awards for either this project or other projects in the future,” Dharma concluded.

“We started construction even before the financial close because of our commitment to the government.”

Dharma HUtama Djojonegoro, president director of PT Tanjung Power Indonesia

TPI’s 200 MW power plant in Kalimantan ASIAN POWER 5

FIRST x CLEANER COAL PLANTs SOUTHEAST ASIA Indonesia

Takashi president director, Bhimasena Power Dr BikalErie, Kumar Pokharel, WoodPT Mackenzie

Asian Power sat down with PT Bhimasena Power Indonesia president director Takashi Irie as he discussed the joint venture between PT Adaro and Japanese companies J-POWER and Itochu to build a $4b 2GW coal-fired power plant in Batang Regency, Central Java.

Can you give us an update on the project?

PT Bhimasena Power Indonesia is developing a 2GW coal-fired plant in Central Java, Batang Regency. We are around 55% complete, past halfway, it’s all going very well.

What are your observations on Indonesia’s power industry?

There are some trends and projects that are focused on renewables, but coal is still one of the main energy sources powering Indonesia. We want to contribute to Indonesian electric power, but with our clean coal technologies.

Any observations on Japan’s power sector?

Why did an Indonesian and Japanese company decide on a joint venture?

Japan’s technology for not only coal but also for gas and renewables will contribute to Indonesia’s power development. I come from Japan, and we are very eager to contribute to the Indonesian power industry through our technology, especially clean coal technology.

What benefits has the joint venture reaped so far?

My company is the joint venture of three companies — PT Adaro Power which is the largest coal company in Indonesia; J-POWER, an electric power company in Japan; and Itochu, another company in Japan. Adaro has a lot of experience and knowledge about the local matters as well as good knowledge about coal.

Adaro contributes to the local development as well as coal supply. J-POWER has the high expertise of the ultrasupercritical (USC) clean coal technologies. We are in charge of the technical, whilst Itochu has more expertise on the commercial side. We got together for this big project, and we are working very closely to contribute to each other.

What is your outlook towards the power industry in Indonesia?

Renewables are important for Indonesia. There is no one solution I think [for figuring] the mixture of coal, gas, renewables and in the past, the [building of] transmission lines. As for business, Indonesia is very good for a private company to invest in. I think many foreign companies are eager to invest in Indonesia’s power sector.

6 ASIAN POWER

Gas plants are likely to be uneconomic soon.

Doom and gloom for Australia’s gas plants

heights and resulted in investments growing to $14.52b (A$20b) in 2018.

Energy market agencies and private energy experts have also implied that wholesale power prices should continue to moderate as more wind and solar supply floods the market because these are the cheapest forms of new supply and cheaper than existing coal and gas supply in some cases.

However, gas is needed to ensure stability of supply, and plant owners have shown they are not worried.

“The use of gas for power generation is changing to when demand is at its greatest, most often at the start and end of the day,” Simon Rodgers, general manager, trading and operations, Origin Energy, told publications in an interview. “As a result, the total volume of gas required for power generation is lower than in the past. However, the role of gas is more important than ever with its flexibility supporting system reliability given the increase of intermittent renewables,” he added.

Retirement without compensation?

The future of gas plants is hindered by the dominance of two- and four-hour batteries, which will reduce volatility.

This is their bread and butter, said Mark AUSTRALIA Hutchinson, vice president, head of ustralia’s gas peaking plants The average APAC Power & Renewables Consulting are likely to be uneconomic expected at Wood Mackenzie. starting in the 2020s, as the capacity for “We fear that without adequate average expected capacity for peaking peaking plants in plants in 2030 is expected to be around 2030 is expected compensation, a lot of those plants will 5% in a year, according to Zi Sheng to be around 5% start to retire,” Hutchinson warns. To contain some of the increasing risks Neo, managing consultant for Power & in a year. towards gas plants, developers may be Renewables Consulting Asia Pacific at turning to other forms of support.

Wood Mackenzie.

Former energy minister Angus “Based on business as usual without Taylor said that amongst the 70% of the introduction of reliability features in prospective power plant operators the existing power market, these plants seeking taxpayer backing for new which depend on the volatility of the generation projects, the strongest market will actually have to shut down,” interest was in gas power. he said.

“Without any form of capacity payment or reliablity payment, or any Gas loses to renewables form of life support, all these plants will The fear of gas plants’ retirement have to close down and will be unable is exacerbated by the fact that gas to recover any of their operating costs,” generation is continuing to lose against Zheng warned. renewables when it fell 44.08% to just 3,183GWh in the December quarter from 5,692GWh in the December 2017 Australia Q2 2018 generation mix quarter, according to data compiled by Dylan McConnell, a researcher at the University of Melbourne’s College of Climate and Energy.

EnergyQuest also revealed that the use of gas on the Australian east coast for electricity generation was 42% lower in December than a year earlier whilst the use of generation sources such as solar, hydro and wind all jumped.

Even without the National Energy Guarantee (NEG), the installation of Source: Wood Mackenzie renewables has reached unstoppable

A

FIRST Indonesia’s coal consumption could double from 83 Mt in 2018 to 157 Mt by 2027.

By 2027, 58 greenfield coal projects will come online.

Indonesia’s unrelenting grip on coal

D

Indonesia

espite a good run for Indonesian renewables in 2017, the country is undaunted in its voracious appetite for coal. Wood Mackenzie data showed that about 58 greenfield coal-fired power plants like the ongoing Sulawesi Mining power station (which has started its third phase) are due to come online in the period to 2027 and boost capacity from 24,418MW in 2018 to 51,800MW in 2027.

“This will be the largest factor driving the increase in domestic coal consumption, causing coal consumption for power generation to grow at an 8.3% CAGR between now and 2027,” said analyst Vicky Adijanto. Consumption could double from 83 Mt in 2018 to 157 Mt by 2027.

However, recent electricity demand growth has been below expectations.

PLN’s sales growth only hit 3.1% and failed to meet its target of 8.3%, forcing the government to cut its capacity forecast over the next 10 years by 22GW. Major plans have also been cancelled, as shown by PLN’s withdrawal of 5,000MW of coal projects in March 2018. “However, coal’s cost competitiveness means that most of the delayed projects are gas-powered plants.

The latest RUPTL shows that potential coal capacity has been reduced by 5GW, whereas gas and renewables capacity have been reduced by 10GW and 6.7GW respectively,” Adijanto noted.

Indonesia’s new policies could also serve as roadblocks to the development

of renewables projects. One of them, Ministerial Decree No 1953 K/06/ MEM/2018, requires 50% of the hired engineers in this relatively new industry to be locals. “This policy is setting a higher barrier to entry for renewable energy to gain traction in the market,” Adijanto commented.

Clunky renewables policy Indonesia also provides limited incentives, such as tax allowances and holidays, for renewable generation. The cost of generation provision – a price cap for any kind of electricity tariffs to be paid by the government in different regional grids, colloquially known as BPP – also restricts investment in renewables, the analyst added.

Still, experts urge Indonesia to include more renewables into its energy mix.

“Renewable energy provides positive economic impact to rural areas, which are very difficult to reach by fossil fuel due to limited infrastructure. To reduce risk and increase affordability, the government may collaborate with international partnerships through fiscal and non-fiscal incentives,” said Dr. Surya Darma, chairman of Indonesia Renewable Energy Society (METI).

“Indonesia will become a net importer of gas by 2027 and a net importer of coal by 2056. We need a significant effort to delay these. On the other hand, RE development takes about 8-10 years for a geothermal plant, and 7-8 years for hydropower,” he added.

“Coal’s run in the domestic power generation mix will not go unchallenged.

Gas and renewables are likely to slowly displace coal in the long run and we do not expect any investment in new coalfired capacity in Indonesia from 2027 onwards. Until then, coal will remain king in Indonesia,” Adjianto noted.

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China tops country rankings of climatex aligned bonds

Legend: green - green bond issuers; teal - fully aligned issuers; blue - strongly-aligned issuers / Source: Climate Source: BMI Research Bonds Initiative

ASIAN POWER 7

FIRST

IPPs target Vietnam deals

Vietnam’s wind and solar capacity, 2017-2027f

Singapore

E

VIETNAM

xpecting abundant returns, German power plant developer juwi marked its entry into the Vietnamese market with contracts for two solar projects in Ninh Thuan province with capacities of 50MW and 30MW. Private electricity producers are anticipating the launch of Vietnam’s wholesale electricity market, which will be fully operational in 2019 after a year-long pilot period.

“We have seen several Asian countries opening their wholesale market. Customers will be able to make their own choice about their electricity purchase, prices will very likely go down due to higher competition. With a growing electricity demand of 8-9% per year, the Vietnam electricity market has a great outlook for customers, developers and investors,” juwi said.

Defining market models During the pilot period, the Ministry of Industry and Trade tracked performance metrics in order to improve service. The remaining time of the pilot period will be devoted to improving information technology infrastructure and training companies on how the market works.

The launch of the wholesale electricity market marks the second phase of Vietnam’s multi-year Power plant WATCH

senoko energy enters singapore’s oem

Source: Fitch Solutions

Sector Reform Road Map. The first phase involved the launch of a competitive generation power market, whilst the third phase will result in the launch of a competitive retail power market whose pilot will start in 2021.

Nguyen Anh Tuan, director of the Electricity Regulatory Authority of Vietnam, explained that the agency will put energy generated by the Electricity of Vietnam’s hydroelectric plants into the market. Renewable energy providers can connect to the national grid soon after. This is welcome news for the renewable energy sector, which continues to enjoy hefty investments.

“The landscape of electricity market in Vietnam is up for a change with the introduction of wholesale electricity market for large industrial customers.

This will reduce the monopoly of EVN on the electricity market in Vietnam, as big industrial players can connect directly to substation of the electricity supplier,” noted Beroe Inc. analyst Gadde Ramachandra.

With a growing electricity demand of 8-9% per year, the Vietnam electricity market has a great outlook for customers, developers and investors.

Glow Energy eyes plant sale in Q1

Ørsted’s Taiwan wind 6GW wind farm in projects delayed Mongolia OK’ed

Thailand

Taiwan

China

Thailand utility and ENGIE subsidiary Glow Energy eyes a deal to sell the 124MW co-generation SPP 1 power plant in Rayong province in the first quarter of 2019. The plant is valued at around $188.47m.

The country’s Energy Regulatory Commission (ERC) imposed the sale of the power plant as a condition for allowing Global Power Synergy Plc (GPSC) to acquire Glow. The concession of Glow SPP 1 ends in 2021.

Meanwhile, a renewal is being considered by the National Energy Policy Council.

Denmark-based firm Ørsted paused its projects in Taiwan and said it will revisit activities, timelines, and commitments after it failed to get an establishment permit in time to sign a 2018 power purchase agreement with Taipower for the offshore wind projects, Changhua 1 and 2a. The projects have a total capacity of 2.4GW and around 1.8GW. The deadline for signing the 2018 PPA was extended to 2 January 2019. However, Taiwan’s Bureau of Energy had not issued an establishment permit by close of business local time.

China’s State Power Investment Corp (SPIC) got the go-ahead for a 6GW onshore wind project in Inner Mongolia worth $6.2b, a report by Recharge News revealed.

SPIC said the project will be the world’s largest.

The Ulanqab wind project will sell power with no subsidies. The report adds that it will compete with coal-fired power’s price benchmark in the region at $41.26/MWh. National Energy Administration (NEA) renewables director Liang Zhipeng said zero-subsidy wind is feasible in the country.

Stefano Boscaglia, Senoko Energy

Stefano Boscaglia, Senoko Energy’s senior vice president, SME and Consumer Sales, discusses how the generation company is responding to the complete rollout of Singapore’s open electricity market, or OEM. How are your price plans structured?

There are two main types of electricity plans being offered in the OEM for new residential consumers and SME businesses – Fixed Price Plans and Discount Off Tariff plans. In fixed price plans, consumers pay a fixed rate for electricity throughout their contract period. With electricity tariffs rising for the fourth time in Q4 to 25.82 cents/kWh, these plans enable customers to hedge against the changing energy pricing conditions and minimise the risk of volatility outside of their control.

DOT plans are structured to provide a guaranteed discount on prevailing tariffs every month. Senoko Energy’s DOT plans offer up to 17.25% discount on regulated tariffs. Consumers should look beyond the low rates or huge discounts as advertised. There may be hidden costs like security deposit, registration or admin charges that have not been declared upfront.

What opportunities are there in the OEM? Many consumers have noticed that electricity and gas tariffs are steadily on the rise and are looking for ways to counter this. Singapore opening up its retail electricity market provides an opportunity for consumers to take charge of their energy provider and electricity bills, whilst enabling power generation companies like us to engage with customers directly.

So far, we have seen very positive response from customers in the first phase of the nationwide rollout of the OEM, in line with what we expected after the Jurong pilot. Our new sign-ups in the first phase have surged past four digits, and we are optimistic that this figure will continue to rise as consumers become more accustomed to the concept and more aware of the benefits of switching.

What are your plans for the future?

We are focused on delivering a personalised, seamless customer experience and relevant products and services. As part of this goal, we launched a customer app this month to enable our customers to manage their electricity accounts on the go and take charge of their energy consumption. We are also digitising the back-end billing and customer operation processes to cut error rate and ensure a smooth customer experience.

OUR O&M BUSINESS

TOTAL CAPACITY 5,300 MW

PJB Services, Providing Total Solutions For Your Power Plant

PJB Services provides many kinds of services in power plants management. Our products ranging from Operation and Maintenance (O & M) of Coal Fired Steam Power Plant , Hydroelectric Power Plant, Combined Cycle Power Plant / HRSG, Gas Turbine , Gas Engine, and Diesel Engine, consist of : HSE Management, Setting up-mentoring-and implementing Asset Management. PJB Services provides another services like Repair & Rehabilitation, Relocation, Remaining Life Assessment (RLA) and Inspection (Overhoul) of any types of Power Plants also.

Supported by 17 years of experiences and 3,700 experts and professional in O&M of various types of Power Plants, PJB Services reputation has already been proven that we can give our customers a high reliabilty, availability and efficiency for power plant unit performance output.

WHAT WE ACHIEVE IN ASAHAN, SUMATERA UTARA

In relation to primary energy there are several other factors that influence the output, they are: the height of effective fall, water quality and water discharge that can be utilized. Effective fall height is affected by the elevation of water in the siruar dam with the water elevation in the Sigura - Gura dam.

This condition creates a synergy between the managers of Lake Toba, namely Jasa Tirta, the Manager of the Sigura Gura Dam, the Inalum Hydro Power Plant and the Owner of Asahan I Hydroelectric Power Plant, namely BDSN. Daily basis coordination is needed for this work.

Together.

Continuously encourage and educate the surrounding community not to throw garbage in the river path, activate the community waste management, and empowering residents to participate in taking care of river cleanness, like picking garbage in the river.

Besides that, sediment dredging, diving for garbage cleaning and periodic trash rack checks are also carried out. However, cleaning the trash rack must be routinely done every day. To meet one of the indicators of success, the efficiency of water use is in accordance with the design of water use planning.

Operation Indicator

Since 2014, Asahan I Hydroelectric Power Plant has been successfully operated and maintained by PJB Services. Asahan I is a run of river hydropower with 2 x 90 MW in capacity, with 1,175 GWh / year production target. The biggest challenge for Asahan I is reaching the production target according to the contract.

Net Production Average Water Debit Equivalent Available Factor (EAF)

Which is broadly influenced by several factors, including: availability of primary energy, electrical energy needs and wellness of generating equipment. As in general, the availability of primary energy is affected by rainfall. Although the rainfall or water debit that is used fluctuates annually, the production target remains the same.

Technical Innovation

PT PJB Services

Units

Award

Modification of the garbage lift system in trash rack intake gate Modification flange balancing pipe Modification conveyor system intake gate

www.pjbservices.com

FIRST

Energy storage systems take off in Asia asia pacific

Tim Buckley, IEEFA director

A

sian Power sat down with Tim Buckley, director of the Institute for Energy Economics and Financial Analysis (IEEFA) to discuss the leadership roles of China, India, Japan, Australia, and South Korea in energy storage market that could grow to $620b, according to BloombergNEF. What factors could enable India, Japan, Australia, and South Korea to lead the world market for energy storage?

India and Australia are two leading markets where the rate of variable renewable energy (VRE) deployments has accelerated cost declines to the point where new solar and wind capacity is clearly the low cost source of electricity supply, far cheaper than new fossil fuel generation. In both markets, low-cost VRE starts to challenge the viability of existing thermal power generation.

South Korea and Japan are still relatively high-cost renewable energy markets, where the policy framework is still emerging and lower quality solar & wind resources mean VRE is still relatively expensive versus imported fossil fuel generation. However, with ongoing doubledigit annual VRE cost deflation coupled with increased carbon/coal taxes and higher LNG and imported thermal coal costs, the move by renewables below grid parity rapidly approaches.

As such, all four markets are now readily evaluating battery storage as an increasingly

x coal financing in asia

viable and necessary complement to greater reliance on VRE. Australia has commissioned two of the largest utility scale battery facilities in the world over 2018. South Korea is set to deploy a number of similar sized battery operations in 2019, whilst Australia has 3-4 more battery facilities already under construction.

What is your outlook on the demand for EVs and battery storage in Asia?

It is worth recognising that China is now clearly the world leader in designing, manufacturing and deploying lithium ion batteries and electric vehicles. Japanese and South Korean battery and automotive companies are heavily targeting investments in these two sectors as well, partnering with both leading Chinese firms and Tesla so as to stay relevant as this massive, unstoppable technology driven disruption unfolds globally.

Unlike countries like America and Australia who are net fossil fuel exporters, China, India, Japan and South Korea are amongst the world’s largest importers of fossil fuels, particularly oil.

Electrification combined with an ever greater deployment of domestic, low cost renewable energy plus storage means all four countries can progressively and permanently reduce their energy security issues relating to their excessive economic reliance on fossil fuel imports.

SE Asia has been a laggard to-date, but with continued strong economic growth across the region comes the ever increasing reliance on imported fossil fuels. This growing pressure applies to Vietnam, Thailand, Philippines, Indonesia, Pakistan and Bangladesh. India shows that with the right policy framework, addressing the Paris and pollution issues can also create massive new investment and employment opportunities in industries of future whilst driving energy deflation.

xxx INDONESIA

xxx Ian Fox, CEO, Leader Energy

Ian Fox, CEO talked of Leader Energy, talked to Asian Asian Power to YTL Power International Power how operational and financial risksthe have Berhad’s CEO Tan Sri Francis Yeoh about intensified coalprojects.

IPPs in Asia as the region company’s for largest makes a gradual shift towards renewables.

Tell us about the company’s most stellar What the risks associated with they coal IPPs? powerare projects to date and where are Operational located. risk is a key thing, provided you’ve got the rightwe contractual structure At present, are constructing thewith firstyour oil shale power buyer power and your fuelwith supplier, that allow mine mouth plant a capacity of 2 x you not(net) takeutilising risks in the those areas. For example, 235 to MW circulating fluidised we two small coal-fired in power projects bedhave boilers (CFB) technology the Hashemite in our portfolio.

We have long-term powerat Kingdom of Jordan.

The project is located purchase agreements with fixed prices so that Attarat um Guhdran which is 110 km southeast we don’t take market volatility, the fuel of Amman.

Atany a total investment ofand US$2.1b, it is that we buyprivate is passed on project to the buyer.

Theto risk the largest sector in Jordan date of price increase is not taken by us, it’sannual taken andfuel is expected to meet 15% of Jordan’s by the buyer.

That really leaves theCompany risk out of electricity demand.

Attarat Power our day-to-day we think we’re (APCO) which isoperations, the projectwhich company has entered pretty good at.Power Purchase Agreement (PPA) into a 30-year with the Jordanian national utility and single How risks IPPs now that buyer,have NEPCO forfor thecoal sale of thegrown entire electric financiers pulling out ofother coal? capacity andare netslowly electrical output.

The For newwe IPPs, biggestdeveloping risk will beisfinancing project arethe currently in Cirebon -Regency, whetherWest or not youIndonesia. can obtainThe low-cost, Java, 2 x 660 MW non-recourse If you big enough (net) coal-firedfinancing. power plant willa utilise state-ofbalance sheet, obtaining technology. money probably won’t the-art ultra-supercritical The project be very difficult.

But the forCompany larger-scale company, PT Tanjung Jatinorm Power has power plants is non-recourse financing without executed a Power Purchase Agreement (PPA) awith sponsor’s that, it’s very difficult PT PLNsupport.

(Persero)For in December 2015.

We to find financiers.

That’s probably the biggest risk, are always on the lookout for new opportunities assuming thatwhether you haveit all the contracts and in generation is bidding for existing structures like that.in new projects. assets or investing

MYANMAR

Myanmar lures power project sponsors in global energy players amidst reforms When Myanmar first launched its massive national electrification agenda, many international players were understandably cautious over pouring funds into the newly-opened country. But now, energy projects are being approved at an unprecedented pace, and investors are benefiting from a range of government reforms.

VDB LOI’s senior partner in Myanmar, Edwin Vanderbruggen commented, “We have noticed a shift in the profile of the sponsors of power projects. Since 2018, we see involvement by major global energy players.”

Joo Yeow Lee, IHS Markit senior research analyst, noted that four notices to proceed (NTP) - the equivalent of MOUs in other countries - have been issued to fast-track development of plants with total capacity of 3,111MW. In 2018, the government has approved two projects in excess of 1,000MW, namely the LNG to power projects of Total Siemens at Kanbauk, and of Zhefu/Supreme Trading in Ayawaddy. The government also approved a project in excess of 600MW, the Shweli 3 hydropower 10 ASIAN POWER

project of EDF and Marubeni. Three other power projects below 200MW were also approved - TTCL’s Ahlone LNG project, Sinohydro’s gas-fired plant in Kyauk Phyo and the Deedoke hydropower project.

Another change in Myanmar is the reform of the procurement process. Under the new rules, a sponsor would receive a notice to proceed from the Ministry of Electricity and Energy. “The new procurement process has some important advantages. It narrows the range of commercial negotiation room between the parties, and factors such as tariff range, the currency and main points of risk allocation will be much closer between the parties by the time the NTP is issued,” Vanderbruggen added.

Lee said that capacity is set to grow as demand has risen from over 6TWh in 2010 to almost 16TWh in 2016, setting the yearly rate at 10%. Myanmar has set its electrification target to 100%, and so far, it has reached 37%, a notch higher compared to 30% in 2016. It currently has 5GW of installed capacity, mainly composed of hydropower and gas.

Powering Myanmar Total primary energy production was 22.5 million tons pf oil equivalent (mtoe) in 2013

Energy consumption by sector in 2012

Most people use traditional biomass( mainly firewood and agricultural wastes) particularly for cooking and lighting

Source: The ASEAN Post

The Noor Energy 1 Plant has a total investment cost in excess of $5b to reliably deliver electricity 24 hours a day for the next 35 years, generated entirely through solar energy at a price of 7.2 cents/ kWh which is competitive shoulder to shoulder with the cost of electricity generated with gas as fuel on a combined cycle generation plant.

Paddy Padmanathan CEO and President ACWA Power

CEO INTERVIEW

ACWA Power builds world’s largest single-site CSP ACWA Power CEO Paddy Padmanathan leads the company into Asia with investments in Vietnam, market entry into Indonesia, and its ties with Silk Road Fund to create the world’s largest single-site concentrated solar power project.

I

n an exclusive interview with Asian Power, the president and CEO of Saudi Arabian utility ACWA Power, Paddy Padmanathan, shared the company’s expansion to the rest of Asia with its entry into Indonesia and ties with China’s Silk Road Fund. He also gave a glimpse into ACWA Power’s bid to build the world’s largest single-site concentrated solar power (CSP) project.

Can you give us your top three priorities for ACWA Power’s generation side?

At ACWA Power, our main priority is to ensure the reliable delivery of energy and where relevant desalinated water at the lowest possible cost utilising a bulk capacity on long term offtake contract model. For every project we undertake, we rigorously focus on reducing the cost of each and every component that contributes to tariff and work with our partners and supply chain to not market price any input but to assess real cost and apply a reasonable risk reflective margin and profit.

Secondly, we prioritise on identifying, evaluating, allocating, mitigating and managing risks in each project at each phase of the transaction from origination, development, construction, commissioning, operation and maintenance and finally decommissioning. And thirdly we seek to maximise local content in what we get built and what we use to operate and maintain the plant and create local employment opportunities at all stages of the transaction in order to maximise the impact on the social and economic development of the communities and countries we invest in, given that our investments have a time horizon of several decades and our returns are only assured throughcontinued growth and prosperity of the countries we invest in.

What’s behind ACWA Power’s expansion to Indonesia?

As an investor, owner and operator with a long term mind-set and given the capital intensity of our business, we recognised at the outset the importance of establishing a balanced portfolio of assets across a wide geography over time to become resilient as a business through diversity.

Having now established a presence in a few countries across four geographies; Turkey, Morocco, South Africa and Vietnam beyond our home region; that of Saudi Arabia and the neighbouring counties within the GCC and Egypt and Jordan, we are now expanding in each geography to other countries which show a steady growth in demand for power generation capacity, which welcome foreign private investment in their power sector and who have a demonstrable track record of honouring contracts and where one can efficiently operate to deliver power at sufficiently low cost to endure the test of time.

Now that we have secured our first two developments in Vietnam, we are ready to expand to the next country in the Southeast Asian region and Indonesia to us is a very logical choice that fits all our criteria and thus our move to establish an office and start to identify opportunities.

What opportunities do you see in Indonesia’s power sector?

A country of 255 million people with per capita electricity consumption rate of just 1 MWh compared to say South Korea’s 11 MWh per capita or even Vietnam’s 1.6 MWh per capita and an installed generation capacity of just 59GW and a projected demand growth rate of 6.87% per annum, the Government of Indonesia has published a plan to add 56 GW within the next decade. Given the range of resources available spanning from geothermal, solar, wind, gas and coal, we see a major opportunity

to establish a business of a significant size to develop, own and operate a multi fuel portfolio and grow that business along with the social and economic growth and development of the country.

What factors led to Silk Road Fund’s investment in ACWA Power’s concentrated solar power project in the UAE? ACWA Power has an established strategy of sharing investments with like-minded value adding partners. Having already established a close relationship with the Silk Road Fund through an equity investment partnership on the 2,400MW ultrasupercritical Hassyan Coal fired power plant also at Dubai, they were a natural partner to then bring into this iconic and strategic project, the largest single renewable energy project underway in the world today, the Noor Energy 1 plant. It has a total investment cost in excess of $5b to reliably deliver electricity 24 hours a day for the next 35 years, generated entirely through solar energy at a price of 7.2 cents/kWh which is competitive shoulder to shoulder with the cost of electricity generated with gas as fuel on a combined cycle generation plant.

How significant is the power demand that ACWA Power aims to address with the Salalah II IPP-Greenfield Project?

By 2021, peak energy demand in the Dhofar region of Oman is expected to reach 700 MW. ACWA Power’s project, Salalah II IPP, of 445 MW capacity will cater for over 60% of this demand thus eliminate the need for intra region transfers.

What is your outlook on the power sectors in the Middle East and the rest of Asia?

With a young population growing into the economically active age group and with population itself growing right across the Middle East and Asian region, demand for electricity is steadily increasing all driven by industrialisation, employment generation and expansion of social services. Also, driven by the compelling need to decarbonise as much of human activity as possible and with the wide range of options technology is giving us spanning from electric vehicles to electrification of industrial processes, the per capita consumption of electricity is increasing in this region even as efficiency of utilisation of electricity by devices ranging from the light bulb to air conditioners is reducing consumption per unit of GDP which thus is contributing to a net growth rate in excess of 4 to 6% in demand right across the regions.

In addition to the need driven by growth in generation capacity, the significant underinvestment in power generation sector in the last few decades also means the existing fleet is aging and now requiring replacement. Also with technology having made significant advance, the existing fleet is also inefficient in utilising the valuable resource of fossil fuels compared to the equipment available today giving yet another reason to replace them.

All Governments across the region have also recognised the need to eliminate unsustainable subsidies, increase efficiency and reduce the cost of electricity by selecting the most appropriate fuel mix which now means an increasing level of renewable energy in the mix and to utilise the resources of the private sector not just to supply the technology and get plants built but to get the private sector to finance, build, own and operate assets and deliver the required kilowatt hours. We therefore see an attractive and rapidly growing market which allows ACWA Power to grow with the countries of the region to utilise the ingenuity of the private sector to reliably deliver electricity at the lowest possible cost and in the process support the countries to localise technology, generate employment and develop communities.

ASIAN POWER 13

Country report 1: CHINA

Stakes are higher in China’s energy transition With 38% of renewables already in the energy mix and a newly opened retail market, the country might be halfway in its energy transition, but issues especially regarding its overseas investments in coal are potential hurdles.

R

enewables have displaced coal and fossil fuels in powering China’s gigantic economic machine, taking 38% of the energy mix and leaving a third of it to thermal power sources in 2018, data from the National Energy Administration (NEA) showed. However, it will need more renewables not only to address the environmental, social, and health impacts of its traditional energy sources that have built up over the decades, but also to hold up the growth of its massive economy which has begun to slow down.

The latest China Renewable Energy Outlook noted that renewable energy sources will become the core of China’s energy system by 2050, with about 80GW to 160GW of annual solar photovoltaic (PV) installations expected. The report, which was released on the sidelines of the 24th Session of the Conference of the Parties to the United Nations Framework Convention on Climate Change (COP24) in Katowice, Poland in December 2018, noted the need to move China’s power sector towards a more sustainable path, with renewables now bannering the transition compared to being a mere add-on to coal and fossil fuel in previous national energy strategies.

This is in line with the government’s 13th Five-Year plan, its economic and development blueprint for the next halfdecade. “The single most important step now is to reduce coal consumption in China,” the report authors noted. This sentiment also reverberated amongst the international community— highlighting the Chinese government’s efforts as aligned with global interests—with a host of multilateral development banks, which include the likes of the World Bank and the Asian Development Bank (ADB), announcing a joint framework to combat climate change and carbon emissions globally.

Following decades of economic success, China is at the

China expects 80GW to 160GW of solar installations annually.

14 ASIAN POWER

Renewables have displaced coal and fossil fuels in powering China’s gigantic economic machine, taking 38% of the energy mix

forefront again of what could be a revolution towards more sustainable and renewable energy sources. Whilst China’s energy demand and consumption continues to rise, experts and observers said this should not mean an increase in the use of coal as a main source of energy.

Kaare Sandholt, chief expert at China National Renewable Energy Centre, noted that in order to reduce the effects of global warming, China needs to reduce its coal consumption significantly and replace it with wind turbines and solar panels.

“We can prove that in 2050, China will be able to rely on an energy system with significantly less use of both coal and oil,” Sandholt added.

Shakeup of energy mix With annual solar photovoltaic installations expected to reach 80GW to 160GW per year, wind is also expected to increase between 70GW to 140GW annually. This will push both renewable energy sources as the core of China’s energy system by 2050, according to the state-sanctioned report, with the country’s dependence on fossil fuels declining to 30%.

The focus on renewables, according to the outlook, will not only provide a more sustainable and secure energy future for China, but also spell a boost to the country’s pursuit of sustainable growth and development, particularly in 2025-2035.

“This positive effect is greater than the negative effects related to a decrease in employment in fossil energy such as coal and thermal power generation” which may lead to more health risks and, in turn, incur more social costs to societies, the report said.

One of the significant effects of increased renewables development involves China’s acceleration to become the far fastest expanding electric vehicle (EV) market over the

Country report 1: CHINA Residential electricity in selected regions by scenario

Source: IEA WEO 2018

coming decade. According to Fitch Ratings, China’s Battery Electric Vehicle (BEV) fleet could hit 11 million vehicles by 2027, compared to 3.4 million vehicles in Europe, and 1.4 million vehicles in the US. The upside risk is that Chinese air pollution reduction efforts ramps up more than expected, with EV storage playing an active role in integrating intermittent wind and solar power supplies.

Fitch Ratings said China could harness its substantial EV fleet to support the integration of increasing volumes of intermittent wind and solar power in the market through technology called vehicleto-grid solutions (V2G). However, coal generation overcapacity could mean that this V2G deployment will be less important to energy security in China than for example Western Europe, where baseload capacity is going of line at a rapid pace, it said.

V2G entails a two-way tow of electricity between electric vehicles and the grid, with EVs helping to balance power supply and demand by charging during peak supply, and selling power back to the grid during peak demand, the firm explained. “China’s surging EV segment will mean that the country will be able to scale up V2G solutions before any other market, and at a scale unrivalled over the coming decade,” Fitch Ratings added.

However, China’s leadership in renewables investment seems to be challenged by its own actions. A report by the Institute for Energy Economy and Financial Analysis (IEEFA) revealed that it has committed or proposed about $36b in financing for about 102GW of coal-fired capacity in 23 countries. Of the 399GW of coal plants currently under development outside China, Chinese financial institutions and corporations have committed or offered funding for over one-quarter of them, or 102GW. Whilst the Chinese government has signalled it will restrict coal lending, the country has yet to formally limit its investment in coal plants. “Instead, Chinese finance is increasingly stepping in as the lender of last resort for coal plants, as other banks take active measures to restrict their funding,” said IEEFA researcher Christine Shearer.

The country with the most coal-fired capacity supported by Chinese finance is Bangladesh, followed by Vietnam, South Africa, Pakistan, and Indonesia. About 76GW of the 102GW of capacity is in pre-construction status.

IEEFA also revealed that Chinese companies often act as engineering, procurement, and construction (EPC) contractors for the projects, and increasingly as co-managers and owners. Of the 102GW of global coal-fired capacity supported by Chinese finance, 30GW involves joint ownership with Chinese firms.

Moreover, the biggest lenders are Chinese policy banks: China Development Bank and the China Export-Import Bank, followed

by Chinese state-owned commercials banks such as the Bank of China (BOC) and the Industrial and Commercial Bank of China (ICBC). The corporations most involved are large state-owned entities, including utility monopoly State Grid Corporation

Jon Moore

Joseph Jacobelli

Kaare Sandholt

of China, infrastructure group China Energy Engineering Corporation, and power giants State Power Investment Corporation and China Huadian Corporation.

Funding for these projects leaves China increasingly isolated as other nations move away from supporting coal, IEEFA added. In terms of international financing for future coal plants by state-owned policy banks, China is by far the leader with 44GW of capacity, followed by South Korea with 14GW and Japan with 10GW. However, the picture is not completely dim for China’s global energy investment as China is also a world leader in developing sustainable renewable energy projects. In 2014 and 2015, it launched two multilateral development banks, the Asian Infrastructure Investment Bank (AIIB) and the New Development Bank (NDB), both of which have a priority focus on low emissions technology deployment.

As of July 2018, the NDB had approved 23 projects valued at $5.7b, with a primary focus on renewable energy, energy conservation, water access, and sustainable development infrastructure. “However, to-date the investment in coal fired power plants globally by the traditional China’s state-owned banks are far more significant than the AIIB and NDB. It is also undermining the stated strategy of the AIIB to enhance and support the Paris Agreement.,” Shearer commented.

China should reconsider its funding for export coal mines, coal-fired power plants, and the associated rail and port infrastructure, according to Shearer. The Belt and Road Initiative (BRI) has driven $8b of solar equipment exports from China, helping China overtake the US and Germany to be the top exporter of environmental goods and services. “It makes sense for China to continue to build on its position as the global leader in renewable energy development as the world moves away from fossil fuel-based capacity,” she said.

With the scale and significant impact of developments in China’s energy scene, some wonder if reform in the country can keep up. Joseph Jacobelli, senior analyst — Asia utilities, Bloomberg Intelligence, described the speed of reform in China as “absolutely staggering” during a conference in September 2018.

“It is creating opportunities - it is in an embryonic stage - the retail power markets have only just started. As you imagine, there’s a lot of hurdles, but there are some companies that are already taking advantage of that to create new income streams,” he said, and noted that 35% of the electricity market could already be deregulated in 2018.

“If you take the fact that China power is about $90/MWh, I think you’re talking about a market which is almost $600b right now. Out of that $600b, one-third or $200b is now basically deregulated. And that market is prone to be something like $680b, assuming that $90/MWh — which is the average end-

Despite a surge in renewables investments, China still injects money into coal.

decarbonisation ensured it remained in the survey’s top ten,” Zindler added.

To resolve this, Zindler noted that China would either have to resort to unpopular levy increases on retail electricity prices or inject funds directly from the government’s budget.

On 1 June 2018, when it was recorded that about a third of commissioned renewables have yet to receive their first subsidy payment, China said it was restricting new solar installations that would require the national subsidy, until a solution to funding the deficit was found.

The effect of the policy was seismic, as Chinese solar investment plunged 53% to $40.4b and in turn, pushed down global solar investment by 24% to $130.7b for 2018, a separate report from BNEF has revealed. The country’s total clean energy investment also fell 32% to $100.1b solely because of the plunge in the value of solar commitments.

Jon Moore, chief executive of BNEF, commented: “Once again, the actions of China are playing a major role in the dynamics of the energy transition, helping to drive down solar costs, grow the offshore wind and EV markets and lift venture capital and private equity investment.”

Green bonds are also helping China boost its status in global renewables investment and it will need $447.05b to $596.06b (CNY3-4t) to help its businesses become more sustainable, Chinadialogue said in 2018. Since 2015, “businesses are using them to update production facilities and reduce their ecological footprint, cities to electrify infrastructure, and finance institutions to raise funds to lend to small and medium sized enterprises that have prospects for bringing innovative green technologies to market,” said Wang Yao, director general of the International Institute of Green Finance (IIGF) at the Central University of Finance and Economics.

Notably, some global investors have already hopped on this trend. FTSE Russell launched a new index tracking solely Chinese green bonds at the start of 2019.

Called the FTSE Chinese (Onshore CNY) Green Bond Index Series, the index benchmarks securities with proceeds that are specifically used to finance climate or environmental projects in mainland China. It covers 75% of all on-shore labelled green bonds issued by China’s government, agencies and corporations.

Waqas Samad, CEO Benchmarks at FTSE Russell, noted increased demand from their global customers. “In 2017, China green bonds issuance represented 23% of global green bond issues and the market is expected to continue to grow significantly over the coming years. The combination of FTSE Russell’s strong capabilities in fixed income, sustainable investment and regional presence in China allow us to develop innovative tools to help meet the growing demand from our global customer base,” he said at the launch of the index.

Renewables capacity additions by market between 2010 and 2027f, MW

f = Fitch Solutions forecast.

Source: EIA, Irena, Fitch Solutions

user price in China — go up which probably is not gonna happen in a couple of years as the government wants to keep prices low,” Jacobelli explained.

Bloomberg Intelligence mapped out the locations of the bulk of non-regulated retail activity for the first half of 2018, referring to client agreements which involve the producer, the buyer, as well as the grid. Most of the trading happens in East China (26-27%), followed by North China (25-26%), Northwest China (25%), and South China (24-25%).

Previously power was sold through the State Grid Corporation of China, China Southern Grid, or the Mongolian Grid. Now, non-regulated power sales now take over the total sales of top power utilities like China Yangtze Power (10%), Huaneng Power International (38%), China National Nuclear (23.7%), CGN Power (34.9%), based on Bloomberg Intelligence’s estimates.

The structure of sales is not limited to auctions (which is now present in 20 provinces), as other interesting formats that Bloomberg Intelligence has recorded include bi-lateral contracts that last for one to three years and listed bidding. Notably, Guangzhou has had 61 sellers and 143 buyers trade 4.42TWh at an average discount of CNY45/MWh in its power exchange during September 2018.

“It’s a lot more vibrant than people think,” Jacobelli said. The scene is so vibrant that the number of retail companies has grown to a whopping 3,410, he added. With a huge amount of retailers at present, the analyst noted that there’s meant to be a lot of consolidation in the next three to four years, but for now, a lot of these companies are active. “What’s exciting about the Chinese market, well obviously, a degree of monopoly erosion is yet to start, but it’s written in big, red letters on the wall that it’s happening, because the central government does want to reduce the market power of the State Grid especially,” he said.

Flow of investment Whilst China is expected to maintain its status as the world’s largest market for clean energy investment, Bloomberg New Energy Finance (BNEF) revealed that it is no longer the most attractive one in its Climatescope 2018 rankings as it dropped to rank seven. “China was accumulating an unsustainable subsidy budget deficit, which meant that a national fund intended to pay renewables developers above-market tariffs was not receiving sufficient capital injections to cover its obligations to the sector,” Climatescope project director Ethan Zindler said.

“Whilst China remains the largest market for clean energy build by far, curtailment issues and the halting of subsidies to solar generators dented its score. Climatescope’s updated methodology also places greater emphasis on countries’ openness to international investors over the availability of local manufacturing. Whilst these changes contributed to China’s drop, its unrivalled clean energy investment and potential for 16 ASIAN POWER

Yao Wang

Waqas Samad

Levelized auction bids for India and China, and BNEF Asia Pacific 1H 2018 levelized cost of energy forecast $2017/MW 120

2016 Xintai 2016 Lianghuai

100

2016 Baotou

80 60

NSMP II.I

40 20

2016 Wuhai

NSMP II.II.I Andra Prades h II

0 2016

Source: BloombergNEF

2017

2018 Baicheng Madhya Pradesh SECI 750MW Tami l Nadu 1

NSMP II.II.I U ttar Prades h II

2018 APAC LCOE range

Gujarat 500MW 2019 India

2020 China

2021

2 0 1 9

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Country report 2: INDIA

India has almost doubled its solar and wind capacity to 61GW in 2018.

Rising costs screw India’s 175GW energy goals Will India hit its 2022 wind-solar targets amidst waning investor confidence, auction cancellations, and higher solar prices?

W

ith a little more than just three years down the line, India’s 175GW wind-solar targets are in jeopardy as equipment duties rise and dampen investor confidence. Analysts also point to the scrapping of solar auctions during what supposedly was a sunshine year for domestic players.

India has set the targets at 100GW for solar and 75GW for wind for 2022, already an ambitious endeavour from the point of view of analysts and stakeholders.

Rishab Shrestha, solar analyst, Wood Mackenzie, said that despite significant cost declines, India will meet only 76% of the total target, which could be considered an achievement given the

About 7,000MW of solar tenders have been scrapped by central and state agencies in 2018.

Financial indicators of UP electricity discoms

Source: PFC. Note: ACS (Average Cost of Supply) & ARR (Average Revenue Realised)

18 ASIAN POWER

circumstances and in view of increasing electricity demand.

During a panel discussion in November 2018, Kanika Chawla, senior programme lead of the Council on Energy, Environment and Water (CEEW), a think-tank which advises the Indian government, said that the 175GW target is still considered “very much the floor and not the ceiling” and shared that experts even recommended that the target should be at 300GW. Over the last four years, India has already achieved a lot in terms of increasing its wind and solar capacity. The numbers have almost doubled from 2014 levels to 61GW in 2018, driven by the significant cost decline from auctions.

However, in the government’s process of churning reforms to strengthen the power sector, Chawla has observed some gaps in policy making. “I think at some point between forming the stop level target and where we are right now, we’ve lost sight at some of the trade-offs and now we’re making some policies that are at opposites with each other,” she said said, referring especially to the two-year safeguard duties.

Domestic power players immediately felt the pain from what is considered a frail attempt to protect them from overseas competition. About 7,000MW

of solar tenders have been scrapped by central and state agencies in 2018.

The Indian Solar Manufacturers Association (ISMA) said in a report that developers have stalled projects to avoid the duty timeframe and have resorted to importing equipment from Southeast Asia. The trade body plans to refresh a petition it withdrew last year to call for tighter anti-dumping measures and cash incentives for the local industry.

Investor confidence dampens “Various duties on equipment and the associated uncertainty has led to a shortterm uptick in solar prices. This leads to knock-on effect on already cash-strapped state distribution companies (discoms) who are showing an unwillingness to greenlight high priced solar projects,” Shrestha explained.

Investors may have lost their excitement around the targets, but the Indian government’s commitment and support appear to be strong as they respond to various industry hurdles. According to Shrestha, the government has been helping reduce project risks and as a result, has been able to keep renewable prices at a competitive rate.

The analyst added that capital costs are expected to decline by 23% for wind and 31% for solar in the next five years as new

Country report 2: INDIA India Renewable and Thermal Power Capacity Additions (MW)

Rishab Shrestha

Source: Central Electricity Authority of India (CEA), MNRE India, IEEFA estimates.

generation technologies push out old ones. By 2023, non-hydro renewables are expected to make up 13% of the generation mix.

“Initial policy discussions on 2030 renewables target already shed a positive light on renewables. Improving grid flexibility through storage and flexible power generation will be extremely crucial in achieving high levels of renewable penetration. Economic competitiveness, technological maturity, and financially healthy off-takers will provide a solid base for renewable capacity growth to cater to electricity demand growth,” he said.

Furthermore, it must also be noted that India had already installed 25GW of solar power by September 2018, a quadruple increase over less than three years. By the same month, total renewable energy installations across India had reached 75GW, which is 21% of total installed capacity and a record high of 11.9% of the entire power generation mix.

Tim Buckley, director, Energy Finance Studies, Australasia, Institute for Energy Economics and Financial Analysis (IEEFA) also said that the momentum is still very positive, with 26GW of new solar tenders in train and Prime Minister Narendra Modi’s $70-80b of renewable energy investment in the next four years.

Buckley notes that the country’s ambitious targets are not without rationales, as community concerns rise over excessive air pollution and associated health costs, especially in New Delhi.

“The devaluation of the rupee coupled with a volatility in oil prices during 2018 has increased the country’s energy security concerns, drawing attention to India’s excessive reliance on increasingly expensive imported fossil fuels. In addition, $10b worth of financial distress being experienced by import coal fired power plants at Mundra in Gujarat is further adding to the country’s significant financial and political angst of late,” Buckley added.

On top of renewables targets, India is on track to meet most of its Paris agreement goals. In fact, analysts estimate that 40% of the country’s non-fossil fuel capacity target will be met a decade early.

Buckley said that India’s achievement comes from Prime Minister Narendra Modi’s 2015 announcement of ambitious policy commitments to meet the global Paris agreement, focused on sustainable development and climate justice.

Struggling towards Paris goals However, headwinds have also begun hampering the path to the Paris agreement targets. The country’s National Electricity Plan (NEP) target to cut fossil fuel capacity to just 43% of its total installed capacity by 2027 is challenged by the electric grid’s struggle to incorporate high variable energy penetration.

India’s nationally determined contributions post-2020 include achieving 40% of electric power installed capacity from non-fossil fuel by 2030, representing a jump of 33% over non-fossil fuel capacity of 2015; reduction of emissions intensity of the country’s gross domestic product (GDP) by 33-35% from the 2005 level to 2030; and the creation of an additional 2.5-3.0 billion tonnes of carbon sinks through additional tree and forest cover. On the last one, analysts observe that India is behind schedule.

“The deflationary momentum in the solar and wind generation sectors has enabled India’s electricity sector to turn to deflationary, emissions-free, domestic alternatives in the past several years, particularly as renewable energy tariffs have fallen below 4.2 cents (Rs3.00)/ kWh with zero indexation for 25 years. In contrast, the Central Electricity Authority of India estimates the levelised tariff for an outdated-technology, super-critical minemouth coal-fired power plant operating at a realistic capacity factor of 60% would be Rs4.39/kWh,” Buckley said.

On the other hand, coal remains to be a key feature of India’s generation mix,

Kanika Chawla

Tim Buckley

Pralabh Bhargava

especially in the short-term. Pralabh Bhargava, coal principal analyst, Wood Mackenzie, said that they have increased India’s imports for thermal coal from 158 Mt to 164 Mt in 2018, with a further upside risk of 3-4 Mt as coal stocks are at historically low levels.

The country’s fast growing electricity needs have been the subject of various proposals, one of which is THDC India Limited’s proposed 1,320MW Khurja Supercritical Thermal Power Plant located in the Bulandshahr district of Uttar Pradesh. However, Buckley said that the power plant is a long delayed, outdated business proposal that can no longer satisfy the country’s energy hunger.

Coal’s continued dominance “The cost at the Khurja plant will almost certainly be higher. For starters, the plant is not a mine-mouth facility and will have to transport its coal more than 900km, incurring significant freight charges. In addition, the plant’s initial cost estimates were prepared before the coal price increases of the past couple of years.

Finally, the plant’s environmental impact assessment (EIA) from November 2016 assumed the facility would post a capacity factor of 90%; the country’s existing coal fleet has averaged below 60% for the past two years,” the analyst added.

According to Bhargava, the growth in domestic coal production and dispatches can only partially meet the growing demand for coal, which is resulting in increased reliance on imports. “With a decade-low stockpile at Coal India’s mines and more than half of the plants with a supercritical level of less than seven days’ stock, the reliance on imported coal for several power plants will increase the flow of imports into India,” he said.

If India wants to meet its energy targets at all, it should not only look towards a distant future. A report by the International Energy Agency (IEA) noted that in highly regulated markets such as India, there is a risk that capacity runs ahead of demand. They estimate that today, there are 350GW of excess capacity in regions including India, China, Southeast Asia, and the Middle East. IEA said that this represents additional costs to the system which it cannot afford.

Meanwhile, there has not been an acceleration of emission standards enforcement for existing thermal plants, especially for private and state plants.

Analysts say that retrofits are expensive for plants left with substantial operational life. This, coupled with the existing financial burden in the thermal power sector, has left the government at a loss on how to resolve thermal power challenges.

Hence, coal remains in the focus whilst renewable targets are being strived for.

ASIAN POWER 19

SECTOR report 1: WIND

Hurdles slow down Asia’s race for wind power Amidst a gradual shift from coal to renewables, Asia Pacific countries have shown a raging appetite for wind power, but high costs, patchy support, and unattractive feed-in-tariffs mean that not all governments will be able to deliver.

W

hen Indonesia unveiled its very first wind farm in July 2018, the 75MW facility in Sulawesi instantly became an object of much fanfare and national pride. The Sidrap wind farm featured 30 towering turbines spread across a mountainous terrain measuring 100 hectares, capable of producing energy for over 70,000 households. It is the largest project of its kind in Southeast Asia, with a hefty investment cost of $150m.

Costs for building wind farms have been steadily declining for years.

According to Wood Mackenzie, the levelised cost of electricity (LCOE) for offshore wind in the Asia Pacific could fall 44% during 2018-2023 due to reasons like lower costs for turbines and financing.

Despite stated national targets for wind energy – ranging from an ambitious 2GW in Vietnam and 1.5GW in Indonesia by 2025 to a modest 73MW in Lao PDR by 2025 – no country stands out as a thriving market, due to a dearth of long-term policy frameworks.

Prices are dropping BloombergNEF revealed that the global LCOE for onshore wind in H2 2018 fell 6% to $52/MWh in just a half-year.

“Competitive auctions for new renewable energy capacity have forced developers, equipment providers, and financiers to bear down on all the different costs of establishing wind and solar projects,” said Seb Henbest, BloombergNEF head of Europe, Middle East and Africa.

“We are seeing record-low prices being

The wind isn’t blowing as hard as some Asian countries expect it to.

20 ASIAN POWER

set for wind and solar, and then those records being broken again and again on a regular basis. This is having a powerful effect – it is changing perceptions,” the analyst added.

In India, for example, data from Bloomberg reveals that benchmark LCOE for onshore wind is at $39 per MWh, down 46% on a year ago, and for solar PV at $41, down 45%. By comparison, coal comes in at $68 per MWh, and combined-cycle gas at $93. Prices of wind-plus-battery and in India range from $34 to $208 per MWh depending on project characteristics, but the centre of those ranges is falling fast.

As a result, both onshore and offshore wind farms are springing up across the region, with governments pledging more support for wind projects. In Vietnam, for instance, 12 onshore wind power projects have received licenses in the central province of Ninh Thuan, whilst 16 projects in all have been approved. These projects have a combined capacity of over 748MW and capital of $978m.

“Whilst the cost structures of project development vary from country-tocountry, reductions can be achieved through a focus on enabling deployment policies, reducing the soft-costs associated with project development (e.g., licensing

and permitting, grid connection, land acquisition), increasing efficiency of regional supply chains, improving local installation services, introducing risk mitigation products and unlocking lesscostly capital,” noted Divyam Nagpal in a report for the International Renewable Energy Agency (IRENA).

Unattractive incentives In the past, feed-in tariff (FiT) programmes ensuring power purchases and priority grid connections have encouraged wind project development in the Philippines, Thailand, and Vietnam. There is currently almost 1GW of collective installed capacity in these countries, but development has slowed as governments started considering shifting from FITs to schemes such as auctions.

In the Philippines and Thailand, wind FITs are no longer favoured by the national governments. “In the Philippines, the wind industry is waiting for the RPS to be announced in 2018, which is expected to reinvigorate renewable energy investment.

FiT incentives remain in Indonesia and Vietnam, but in both cases, are perceived as unattractive by most international developers, due to either unfavourable tariff levels or insufficient PPA template,” the IRENA report warned.

SECTOR report 1: WIND Global offshore wind LCOE and Asia Pacific offshore wind prices

Seb Henbest

Divyam Nagpal

Source: WoodMackenzie, IEA

Olivier Duguet, CEO and co-founder of the Blue Circle, a Southeast Asia-based renewables firm, noted that whilst the region has robust demand for wind energy, prices remain high in most countries. “Unfortunately, Southeast Asia or maybe India, is the last place on Earth where we’re still talking about opening new coal power stations. The rest of the world is shutting them down. Why is it so? Because of price, price, price,” he said in an interview with a local publication.

“If you look at wind power in the region the two main countries ahead of the other ones are Thailand and the Philippines for the moment. Vietnam is catching up very quickly, but the rest of the region has nothing. There is only one first project in Indonesia which we jumped into this year, but otherwise nothing in the rest of Indonesia. In some cases it’s because of a lack of resources, for example in Malaysia there’s no wind, it’s not commercial wind I’d say. Indonesia, very difficult also, very low-resource. But Indochina, yes, there are definitely resources,” he added.

IRENA notes that despite stated national targets for wind energy – ranging from an ambitious 2GW in Vietnam and 1.5GW in Indonesia by 2025 to a modest 73MW in Lao PDR by 2025 – no country stands out as a thriving market, due to a dearth of long-term policy frameworks.

Still, there are a few bright spots in the region: Vietnam has approximately 150MW of operational wind power and more than 1GW of additional supply in the pipeline, whilst Thailand saw an uptake of wind power investment in late-2017 when $1.14b was secured by one wind project developer to finance 450MW of onshore wind farms.

Whilst Southeast Asian countries are struggling to set up onshore wind farms, East Asian countries have moved on to developing offshore wind projects. New research from Wood Mackenzie indicates Asia-Pacific’s offshore wind capacity will rise twenty-fold to 43GW in 2027.

“The good news is that prices are

coming down. Future offshore wind prices are projected to be competitive with traditional thermal prices by 2025,” said Wood Mackenzie senior analyst Robert Liew. Leading the charge in offshore wind growth is China, which is expected to see offshore wind capacity grow from 2GW last year to 31GW in the next decade. Next is Taiwan which will account for 20% or 8.7GW of offshore wind capacity by 2027, making it the largest offshore wind market in AsiaPacific excluding China (APeC) by 2020.

Currently, Taiwan relies heavily on coal, gas and nuclear for power. However, the government has pledged to shut down nuclear plants by 2025, thereby leaving a void of 5 GW of power capacity to be filled. “Offshore wind is poised to fill this gap as more than 5.7GW of projects have been approved and planned for commissioning by 2025,” said Liew.

Offshore wind on the rise “Together with South Korea and Japan, East Asia needs around $37b in investments to meet the mammoth growth in offshore wind capacity over the next five years. Taiwan presents the biggest offshore market in APeC due to a relatively stable regulatory regime, a supportive government, and openness to foreign investment,” said Liew.

In Japan,the two houses of the National Diet (Parliament) have passed a bill meant to promote the use of the country’s territorial waters for the development offshore renewable power generation facilities, which will be enforced in spring.

Under the law, the Japanese government will identify approximately five offshore wind development areas and will launch the country’s first offshore wind tenders in spring or summer 2019.

Successful bidders will be given the right to use the zones for a 30-year period.

This marks a major change for the Japanese wind industry, which used to rely on FITs for the development of offshore projects. The Ministry of

Olivier Duguet

Robert Liew

Economy, Trade and Industry (METI) introduced a specific FIT for offshore wind in 2014. The development of a tender-based system sends a strong signal that the Japanese government is committed to long-term investment in the sector. “We expect more activity in Japan and South Korea towards the end of the forecast period, as the local offshore supply chain in both markets will be well established and as the companies gain more experience,” Liew said.

Headwinds ahead Key markets in Asia-Pacific have very ambitious government targets when it comes to offshore wind, but Liew notes that there is a slim chance that these targets will be met. India is by far the most ambitious of all, with the country aiming to establish 5GW of offshore wind power by 2022 and 30GW by 2030.

“The Indian government plans to achieve this by auction. But the target means that offshore wind prices will already have to be competitive with coal power,” Liew cautioned. “We are not expecting that all of these governments will achieve such targets.”

In Japan, analysts warn that profitability remains a key issue. “Unless the government sets and guarantees a high purchase price under the FIT system, it is difficult for power generation companies to secure profits and recover stable costs.

Thus, in Japan, wind power generation is not yet a cost-competitive power supply source,” said Jun Makita, senior researcher at the Institute of Energy Economics, Japan.

“Besides generation cost, the risk burden of power generation is heavy, such as land use control and long-term environmental assessment. Moreover, the area with good wind conditions is limited and the annual average wind speed is low. It turns out that Japan has various problems geographically and structurally,” he added.To support the ambitious growth in offshore wind capacity, a robust supply chain needs to be developed. According to analysts, maritime infrastructure, establishing a local vessel fleet to install and service offshore wind farms, and upgrades to transmission systems will take time to be built up.

This will require strong commitments by regional governments to support and invest in the growth of offshore wind.

“Fortunately, the experience in Europe is that when such support systems are in place, growth will be exponential given the increasing competitiveness of offshore wind prices, and developers eager to take advantage of economies of scale, local suppliers and opportunities in new markets,” Liew noted.

ASIAN POWER 21

SECTOR report 2: Solar

China, India, and Japan lead industry-changing solar power reforms.

Key solar markets shed subsidies and shift to auctions Amidst regional changes in regulations for solar power plants, demand is set to drop by 18% whilst installations are set to plummet by as much as 30%.

A

fter ten straight years of expansion, demand for solar power in the Asia Pacific will fall for the first time in 2018 before stabilising over the next five years as China and other large markets that have been driving growth begin to diminish their solar subsidies and move towards auctions from feed-in tariffs, or FIT. These key countries will continue to generate a lion’s share of demand in the medium term horizon, albeit emerging markets will start to pick up the slack.

Asia-Pacific’s demand for solar power will decline by 18% year-on-year to 59GW in 2018 from 72GW due to decreasing installations in China, India, as well as Japan, according to research firm Wood Mackenzie. “The key trend we are seeing is the phase-out of subsidies and transition towards auctions, which is leading to lumpy demand in the region,” said Rishab Shrestha, solar analyst.

“APAC markets still rely on subsidies but are rapidly transitioning,” he said.

“Remaining FIT markets are expected to transition to competitive bidding completely by 2020. Transitioning from FIT to auctions are expected to deliver the 22 ASIAN POWER

Asia-Pacific’s demand for solar power will decline by 18% year over year to 59GW in 2018 from 72GW due to decreasing installations in China, India, as well as Japan.

most significant cost reductions.”

In China, traditionally the leader of the pack in Asia Pacific, solar installations are expected to fall 30% in 2018 as it adopts various policy instruments which will diminish subsidies, according to Wood Mackenzie. Beijing’s stopgap measures in May included cancellations of further quotas for utility-scale projects, quota restrictions on distributed solar of 10GW for 2018, reduced levels, and a shift towards auctions.

The new regulation effective on 1 June issued by the China’s National Development and Reform Commission and Ministry of Finance introduced an 8 cents/kWh cut in the nationwide FIT and in the subsidies for PV distributed projects. The new on-grid power tariffs will range between 7.8-11 cents/kWh, whilst subsidies for county-level poverty reduction PV projects will remain steady.

The cut in solar subsidies has been seen as a necessary step to prevent the industry from overheating.

Wood Mackenzie noted that China has experienced brisk growth in photovoltaic, or PV, installations over the past few years, with the country meeting its minimum

target of 105GW under the 13th five-year plan in 2017, three years ahead of the planned 2020 schedule. Also, from 2016 to 2018, costs decreased at a faster pace than the FIT levels as module oversupply persisted. This resulted in installation frequently exceeding the annual provincial construction quota for utility-scale projects and prompted delays in subsidy payments and curtailment.

However, Shrestha noted that despite the demand contraction, China will remain the largest market for solar installation in APAC and globally through to 2023. Annual installations from 2018 to 2023 are estimated to range between 22GW to 37GW per year, with cumulative installation reaching 314GW by 2023.

Wood Mackenzie foresees the top barriers constraining demand aside from reduced subsidies will be limited quota and subsidy delays, whilst notable drivers will include the country’s top runner programme and the newly improved renewable portfolio standard, or RPS. In November 2018, IHS Markit revised its 2018 outlook for solar PV installations in China to 40GW from 37GW, after the country’s National Energy Administration reported that 34.5GW of solar PV power was added in the first three quarters. The agency is currently weighing new PV targets for 2020, with reported proposals ranging from 210GW to 270GW. “Whilst it appears that China will maintain a steady level of annual installations, quarterly fluctuations will continue, shaped by policy-making

SECTOR report 2: Solar Solar is expected to contribute ~5% of APAC power demand by 2035

Rishab Shrestha

Holly Hu

Source: WoodMackenzie

decisions,” Holly Hu, senior analyst, solar supply chain at IHS Markit, projecting the country’s total cumulative PV capacity to reach 255GW at the end of 2020, resulting in around 40GW of installations per year in 2019 and 2020. “Further adjustments of these numbers will be made once there is clarity on final policy decisions.”

Hu reckoned that, as expected, the limits on new PV installations announced by the Chinese government in May led to a decline in PV installations in the second half of 2018, although the fall in module prices bolstered demand more than the research firm anticipated and there are policy signals for sustained additions in the next few years.

Whilst the government has shown its continued determination to lead the global build-out of renewable energy sources. Hu said,“China’s challenge will be to design a policy to install new PV installations in the most power-hungry regions at a lower cost than other energy sources.” She expects support for distributed solar photovoltaics with self-consumption, competitive tenders or lowerFITs, and further top-runner auctions to be introduced in line with the new 2020 target but warns that Beijing should avoid a further ballooning of the current $17b subsidy payment backlog.

Japan jumps into auctions Japan, meanwhile, is transitioning from FIT to auction for projects greater than 2MW, according to Wood Mackenzie, noting that the past two auctions have been undersubscribed due to issues such as tight permitting and grid connection timeline, high cost, grid constraints, and limited land availability. In addition, the submitted bids for the second auction all exceeded the ceiling tariff of ¥15.5/kWh. “Due to these issues, utility-scale solar installations will decline significantly,” the research firm said. “Nonetheless, distributed solar installations are expected to remain stable as FIT remuneration declines along with cost.”

Fitch Solutions reckoned that Japan’s shift towards competitive auctions for relatively larger solar projects, paired with FIT subsidy cuts for smaller-scale projects, could weigh on the solar power sector, which has grown to 48.6GW in 2017 from 23.5GW in 2013 as the country sought to replace natural gas and coal imports with renewable energy.

“These changes seek to address the increasing concerns over the high costs of subsidising Japan’s solar power expansion amidst elevated retail electricity prices in the market,” Fitch Solutions said. “The transition to auctions will, therefore, seek to curb additional electricity price hikes in Japan.”

As companies and households look to capitalise on the higher FITs currently available, there is potential for a shortterm boom at the distributed solar capacity level, similar to that seen in utility-scale solar projects since 2013, the macro intelligence solutions firm added.

The Ministry of Economy, Trade and Industry has also previously proposed that firms which hold permits for solar projects in 2012 to 2014 through the FIT system need to submit their application to connect to the grid by March 2019, or their FIT price guarantees will be reduced from 28 to 36 cents/kWh to 18 cents/ kWh. However, power producers and investors have reportedly bristled against the proposed solar subsidy cuts, with some threatening legal action, despite the government’s argument that the cuts are needed to reduce the public burden resulting from the FIT subsidies.

The proposals, which could affect 23.5GW of solar capacity, come as some large-scale solar projects grapple with strict environmental mitigation measures and negotiations with landowners.

Even as major industry shifts in Japan and China, as well as heightened policy uncertainty in India, will serve as headwinds to solar sector demand, these three countries will still generate about 78%, or 279GW, of the 355GW of new

solar capacity between 2018 and 2023, according to Shrestha.

To highlight the expected dominance of Asia Pacific in driving demand despite the projected pullback, Wood Mackenzie estimates the region will account for 55% of the global annual new build PV plants in the next five years, resulting in the cumulative capacity increasing by 60% from 222GW in 2017 to 578GW in 2023.

By 2035, solar is expected to contribute to roughly 5% of APAC power demand and capture 12% of new power demand growth between 2018 and 2035.

APAC still at driving seat The continued expansion, albeit at a slower rate, is partly attributable to the reduction in PV capital cost globally, according to Shrestha, noting that a 25% reduction in PV capital cost has contributed to the 20% reduction in levelised cost of electricity (LCOE).

By 2023, he said the cost reduction in modules and balance of system by 42% and 18% respectively, are expected to lower LCOE to $55/MWh. In the next five years, average regional LCOE for solar is expected to drop by 25% from $73/MWh presently to $55/ MWh by 2023. “Today, LCOE of PV is already competitive against gas in the APAC region. By 2023, PV will be competing against coal. Competitive PV prices will continue to unlock new market potential across the region,” including emerging markets, said Shrestha.

BloombergNEF noted that unsubsidised onshore wind and solar have replaced coal as the cheapest power sources in almost all of the world’s major economies, including India and China, but excluding Japan. The firm’s analysis of the LCOE for the second half of 2018 showed the benchmark global levelised cost of new PV (non-tracking) decreased by 13% to $60/MWh, driven mostly by policy revisions in China that caused the utility-scale PV market to contract in the third quarter. Meanwhile, in India, solar and wind plants, now cost half that of new coal plants, BNEF added.

Wood Mackenzie said markets that will benefit most from this trend include those with attractive policies such as a high FIT like Taiwan and Vietnam and with renewable portfolio standards like South Korea and the Philippines. Voluntary procurement will also emerge as a key driver of solar installations as LCOE nears the wholesale power price levels, as seen in Australia. Vietnam has seen an influx of solar players, such as German power firm juwi signing contracts in October for 50MW and 30MW solar projects in Ninh Thuan province, in which it will oversee plant operation and maintenance for at least the next five years.

ASIAN POWER 23

Country report 3: Philippines

The Philippines needs to install new power sources as the Malampaya gas field’s production could drop by 2024.

Malampaya is running out of gas, what’s next?

Regulatory risks and implementation pose a threat to investment potential spurred by population and economic growth.

T

he race to build a groundbreaking liquefied natural gas (LNG) terminal in the Philippines is heating up as the country faces the anticipated drop in production at the Malampaya gas field by 2024. The government also eyes ramping up the exploration of renewable energy sources, with solar photovoltaic (PV) systems looking particularly attractive, to address an expected surge in energy demand and currently one of the most expensive electricity rates in Southeast Asia.

In early December, Japan’s Tokyo Gas signed a joint development agreement with the Philippine-listed First Gen Corporation to build an LNG terminal in the province of Batangas. The Japanese natural gas producer and supplier will take a 20% participating interest in the project. The Philippine National Oil Co. and the China National Offshore Oil Corp. (CNOOC) were also weighing the possibility of building and operating an LNG import terminal in the country.

Fitch Solutions, in a report in late 2018, noted that the outlook for the Philippines’ second LNG project has considerably improved in recent months, with the introduction of the Tanglawan Philippines LNG Inc., a joint venture between CNOOC and independent oil firm Phoenix Petroleum. “After multiple 24 ASIAN POWER

The government is aiming to boost solar PV installations to 3GW of utility solar in 2022.

calls for tenders and plenty of expressions of interest from a vast array of domestic and foreign firms, the keys to the Philippines’ second LNG development appears to be held by Tanglawan LNG, which is reportedly winning the race to be the Department of Energy’s (DOE) choice to lead the project,” the research firm said.

The partners are given six months to fulfill requirements for their plan to build an integrated LNG-to-power project in Batangas, which would include a regasification terminal with a capacity of 5 MTPA and gas-fired power generation capacity of 1-2 GW with a cost of about $1b to $2b. Fitch Solutions said, “Tanglawan LNG’s case for the project is strong, not least due to ample funding and an assured market for imported gas.”

Improved gas outlook The Philippines’ desire for a second LNG project stems from the fact that the Pagbilao LNG — an LNG-to-power project in Quezon being developed

by Hong Kong-based Energy World Corporation (EWC) — will only be able to meet some 83% of the 4.9 bcm that is expected to be needed to support the government’s gas power expansion plans.

The Pagbilao LNG project is comprised of a 4.1 bcm import terminal and a 650MW LNG-fired power plant, and is part of

plans to secure replacement gas as the giant Malampaya gas field loses steam.

“From a price standpoint, the next few quarters will be an opportune time for the Philippines to commence LNG imports, with global LNG prices set to be mostly anchored over 2019 to 2020, next to accelerating supply growth and liquefaction capacity additions across the globe,” said Fitch Solutions. “The Philippines has yet to enter into any LNG supply contracts for its terminals and as such, will have plenty of contracting opportunities amid a positive backdrop of competitive spot prices and a wave of new supplies emerging from the US, Russia and Asia.”

Despite the clear need for more gas in the Philippines, the Pagbilao LNG has faced multiple delays due to volatile LNG prices, regulatory obstacles, uncertainty surrounding transmission arrangements, and, most recently, setbacks in securing government clearance to connect to the local grid. It secured certification from the DOE as an “energy project of national significance” in November.

“The certification paves the way for it to benefit from a host of provisions set out under Executive Order 30, which was issued in 2017 to streamline approval processes, reduce red tape and provide administrative and technical support for

Country report 3: Philippines Philippines capacity mix

Ethan Zindler

Ville Rimali

Source: Department of Energy

projects deemed to help the development and security of the Philippines. This likely puts the project on track to be in commercial operations within 2019, eight years after it broke ground,” Fitch Solutions said.

Aside from LNG, solar PV and other renewables have been attracting more attention from analysts that believe these could provide the country with considerable opportunities, especially amid an expected spike in demand.

Bloomberg New Energy Finance’s (BNEF) Climatescope project ranked the Philippines as the sixth most attractive emerging market in the world for clean energy investment particularly for the power sector’s structure and regulations.

Setting the renewables path However, a key roadblock has been in the feed-in tariff (FIT), which is paid on the basis of actual production. Climatescope project director Ethan Zindler noted that it was a “losing proposition” for many investors, with currently about 360MW of commissioned solar intended to receive the FIT missing cut to claim its benefits.

On the upside, financing is highly available, as seen by developer support from local and global sources.

In July 2018, Mordor Intelligence said the country is well-positioned to produce solar energy and holds “considerable” potential to take advantage of investments and jobs that can be generated from future solar power installations. The government is aiming to boost solar PV installations to 3GW of utility solar in 2022, and the research firm said that the cumulative solar installation in the Philippines is expected to hit 8.7GW by the end of 2030, with solar rooftops comprising 35% of the total installations.

Ville Rimali, business development manager at Wärtsilä Philippines, however argued that the Philippines is still on the opposite side of the fence when it comes to making the leap to renewables. In the DOE’s power development plan for 2016-

2040, the new generation capacity mix by 2030 is expected to comprise of the following: 7,800MW baseload, 700MW peaking, and 4,100MW mid-merit.

“Where are the renewables? They are inside the peaking segment. So inside the smaller segments, they have included the wind and solar and that’s tiny number.

I think it would make sense to build much much more than the mid-merit segment,” Rimali said in a September 2018 conference.

The prices in the Philippines’ wholesale electricity market are following the same trend everywhere and should drive renewables investments in the country, but, he said, “The plan that DOE is promoting is totally different from what is happening in other countries.”

“Luckily, industrial players/IPPs are looking at renewables and they are looking the big numbers, because they see that’s the future and that’s the way to get lower cost of power for Filipinos. But still it’s important that the DOE is also driving towards the same direction,” he added.

Solar PV potential “Solar energy provides an immediate solution to the country’s growing energy needs. With steadily falling costs of solar power equipment and the short duration of time needed to install and commission solar power projects, solar PV systems are increasingly becoming popular amongst consumers and industries across the Philippines,” Mordor Intelligence said, citing the commissioning of the Cadiz solar power plant, the largest of its kind in Southeast Asia, as one of the signs of a rapidly emerging solar power market. The National Renewable Energy Laboratory reckoned that the Philippines’ average solar radiation ranges from 128-203 W per sqm, whilst its annual average potential is estimated at 5.1 kWh per sqm per day.

Keen to take advantage of the burgeoning sector, Pure Energy Holdings Corporation in January acquired a

Sara Jane Ahmed

60% stake in three solar parks in the Philippines with a combined capacity of more than 13.8MW. Other major solar players in the country include Equis Energy, PetroEnergy Resource Corporation, San Carlos Sun Power Inc., and Solar Philippines.

Whilst rooftop solar holds strong potential for development in the Philippines, analysts cite an array of challenges that are weighing on the sector. Mordor Intelligence warned that the Philippines is being held back by an “extremely inefficient” grid infrastructure, one characterized by very high transmission and distribution losses estimated at around 15% of total output.

“Investment into the grid system has been the government’s focus. However, due to recovery efforts following the November 2013 typhoon, progress in the modernisation of the network has been delayed,” the research firm said.

“Rooftop solar in the Philippines can contribute significantly to enhancing national electricity supply whilst facilitating and creating financing for a growing share of new generation capacity requirements and lowering electricity costs,” said Sara Jane Ahmed, energy finance analyst at the Institute for Energy Economics and Financial Analysis, noting that a shift towards rooftop solar will reduce the need for imported coal and diesel power. The Philippines, which has some of the highest-priced electricity in the ASEAN, could save up to $2.2b annually in its current account deficits as well as $200m per year.

“A combination of cumbersome existing regulation, outdated administrative practices, and a lack of affordable and accessible financing are hindering the broad adoption of rooftop solar,” warned Ahmed. To bolster deployment of rooftop solar, she recommended developing cost-effective net metering government policies, easing approval processes, strengthening access to financing, and rolling out cheaper behind-the-meter integrated lithium-ion battery storage.

Total primary energy supply, 2017 and 2040

Source: Department of Energy ASIAN POWER 25

ANALYSIS 1: CHINA’S COAL LENDING A unit-by-unit analysis of all coal plants under development across the globe, based on the July 2018 Global Coal Plant Tracker, shows Chinese finance playing a significant role in supporting and funding new coal plants. Of all coal plants under development outside China (399GW as of July 2018), Chinese financial institutions and corporations have committed or offered funding for over one-quarter of them (102GW, or 26%).

China is an investment leader in renewables as well as coal.

How China turned into the last resort for coal plant developers

China risks losing its leadership in renewables investment, as analysis shows that over $36b has been committed to overseas coal plants with a total capacity over 102GW.

C

hina was the top global investor in clean energy investments, seen by the Chinese government’s record investment of $44b in overseas low-carbon energy projects in 2017 and $32b in 2016. Yet financing for clean energy exists in tension with the country’s fossil fuel investments, including mining, drilling, and power generation.

Coal plants in particular remain a large investment for China, with recent studies identifying it as one of the top funders of coal plants in the world. Chinese-led policy banks have financed nearly 60 completed and under construction coalfired power plants across the globe since 2001, totalling over $40b in financing.

From 2013 to 2016, the five biggest G20 coal plant financiers were located in China, totalling $15b in financing.

International energy funding from China has been increasing under its Belt and Road Initiative (BRI), in which China is offering to develop infrastructure worth an estimated $6t across 68 economicallydiverse countries in Asia, Europe, and Africa. Although BRI is technologyagnostic, most Chinese finance under BRI to date has gone to fossil fuels: of the $51.2b spent on electric power generation and transmission from 20142017, 36% ($18.2b) was spent on coal. In comparison, 11% ($5.9b) was spent on solar and wind energy. Most of China’s foreign investment in renewables has been outside BRI countries.

This funding for coal comes as financial 26 ASIAN POWER

Of all coal plants under development outside China (399GW as of July 2018), Chinese financial institutions and corporations have committed or offered funding for over one-quarter of them (102GW, or 26%).

institutions around the world are moving away from thermal coal. The Chinese government has signalled it will restrict its coal lending, stating as part of the 2015 US-China Joint Statement on Climate Change that “China will strengthen green and low-carbon policies and regulations with a view to strictly controlling public investment flowing into projects with high pollution and carbon emissions both domestically and internationally.”

However, the country has yet to formally limit its investment in coal plants. As a result, Chinese finance appears to be increasingly stepping in as the lender of last resort for coal plants, as other financial institutions restrict their funding for projects with high carbon emission risks.

Flow of Chinese funds To date, $21.3b has been committed to over 30GW of projects across thirteen countries. An additional $14.6b has been proposed in funding for over 71GW of projects across 23 countries. (For proposed capacity with no dollar amount, funding has been proposed but the amount has not yet been decided or disclosed.)

Most of the 102GW of capacity is located in Bangladesh, followed by Vietnam, South Africa, Pakistan, and Indonesia. About 76GW of the 102GW of capacity is in pre-construction status; of that 76GW, over 60GW is still trying to secure the permits needed to begin construction. Therefore, much of this capacity may eventually be cancelled, as only one GW of coal-fired capacity has been implemented for every 2GW cancelled or shelved since 2010.

Borrowing for large coal plant development and coal imports carries inherent risks around exchange rate volatility, currency deficits and inflation, and rising interest rates, all of which can lead to unsustainable debt. Such currency and systemic financial system default risks have been seen in Pakistan, Indonesia, and Turkey over 2018 alone.

Bangladesh also leads in proposed and committed funding, followed by Pakistan, Indonesia, Vietnam, and South Africa.

However, Indonesia leads in funding that has already been committed or has reached financial close, followed by South Africa, Zimbabwe, Pakistan, and Vietnam, suggesting the capacity is more likely to

Coal-fired Capacity Under Development with Chinese Finance (MW)

Source: Global Coal Plant tracker (JULY 2018) IEEFA analysis

ANALYSIS 1: CHINA’S COAL LENDING China a significant financing source for coal-plant projects globallly

Source: Global Coal Plant tracker (JULY 2018) IEEFA analysis

be completed. Most of the funding is provided by two Chinese policy banks: China Development Bank and the China Export-Import Bank, followed by Chinese state-owned commercial banks such as the Bank of China (BOC) and the Industrial and Commercial Bank of China (ICBC). The majority of the funding has yet to reach financial close and may therefore fall through.

The projects also often involve Chinese state-owned enterprises (SOEs) who construct the coal plants through engineering, procurement, and construction (EPC) contracts. The contracts may require a dominant or entirely Chinese workforce, restricting the local economic benefit of these mega-projects. China is reported to have 700,000 workers in Pakistan alone.

SOEs are increasingly moving into larger roles around management and operation of the coal plants. Of the 102GW supported by Chinese finance, 30GW involve joint ownership arrangements with SOEs, and an additional 11GW are build-own-operate arrangements. The big players are all large SOEs, including the utility monopoly State Grid, infrastructure group China Energy Engineering Corporation, and the power companies State Power Investment Corporation and the China Huadian Corporation.

Chinese finance is supporting all coalfired capacity under development only in countries with little capacity under development overall (3GW and below), such as Kenya, Ghana, and the Ivory Coast. Chinese finance makes up 75% or more of all coal-fired capacity under development in countries such as South Africa, Pakistan, and Zimbabwe, and 50% or more in Bosnia and Herzegovina, Bangladesh, and Egypt.

Whilst Vietnam, the Philippines, and Indonesia are amongst the countries with the highest amount of coal-fired capacity supported by Chinese finance, the support is less significant as a percentage

of total capacity, with Chinese finance supporting 30% of all coal-fired capacity under development in Vietnam, 28% in the Philippines, and 23% in Indonesia.

In these countries, Japanese and South Korean financiers are also significant.

Plants’ technology types Nearly two-fifths of the capacity under development with Chinese finance is categorised as ultra-supercritical technology (38%), followed by supercritical (35%) and subcritical (23%). This compares with subcritical technology making up 58% of plants funded by Chinese policy banks between 2001 and 2016.

Whilst the move away from predominantly subcritical technology means lower coal consumption per kilowatt-hour (kWh) of use, it also means higher costs, making the plants less competitive compared to ever-lower cost renewable energy alternatives. Also, many policy banks have implemented CO2 performance standards that rule out financing for less efficient subcritical or supercritical technology Green finance expansion Whilst this report focuses on China’s continued international financing and development of new coal-fired power plants, we note that China is a world leader in developing sustainable renewable energy projects, both within China and increasingly on the global stage. Consistent with this, in 2014 to 2015 China launched two multilateral development banks, the Asian Infrastructure Investment Bank (AIIB) and the New Development Bank (NDB), both of which have a priority focus on low emissions technology deployment.

The AIIB provides finance to support electricity access, with new renewable and gas power projects across countries like India, Pakistan, Bangladesh, Myanmar, and Egypt. The AIIB aims to be a green development bank, providing sustainable

Nearly twofifths of the capacity under development with Chinese finance is categorised as ultra-supercritical technology (38%), followed by supercritical (35%) and subcritical (23%).

energy investments whilst supporting the Paris Agreement.

As of July 2018, the NDB had approved 23 projects valued at $5.7b, with a primary focus on renewable energy, energy conservation, water access, and sustainable development infrastructure.

However, as we outline in this report, to-date the investment in coal fired power plants globally are far more significant than the AIIB and NDB. It is also undermining the strategy of the AIIB to support the Paris Agreement.

What China can do As other countries move away from financing coal, China will find itself increasingly isolated. The World Bank, most multilateral development banks, the export credit agencies (ECAs) of OECD countries, and many private banks have all ended or severely restricted their lending for coal plants. The moves have left China, Japan, and South Korea as the largest supporters of coal plants globally, although both Japan and South Korea have recently signalled their intent to limit coal financing.

This year, Japanese insurers Dai-ichi Life and Nippon Life have said they will not invest in new coal-fired generation projects, whilst national power giant Marubeni said that it will “no longer enter into any new coal-fired power generation business.” South Korea’s new president is no longer permitting new coal plants domestically, whilst promoting renewable energy investment and at the same time proposing to increase coal tax rates 30% to up to $40/ton from April 2019.

China should similarly reconsider its funding for export coal mines, coal-fired power plants, and the associated rail and port infrastructure. The International Energy Agency (IEA) sees renewables contributing 60% of global additions to electricity generation capacity through 2022 and dominating the scene over the next two decades.

Already, IEEFA estimates BRI has driven $8b of solar equipment exports from China, helping China become the number one exporter of environmental goods and services, overtaking the U.S. and Germany. Competitiveness for new, clean energy technology is only increasing as market-moving climate risks unfold in real time. It makes sense for China to continue to build on its position as the global leader in renewable energy development as the world moves away from fossil fuel-based capacity.

From “China at a Crossroads: Continued Support for Coal Power Erodes Country’s Clean Energy Leadership” by Christine Shearer, Melissa Brown, and Tim Buckley at the Institute for Energy Economics and Financial Analysis ASIAN POWER 27

OPINION

MUHAMAD REZA, PHD

Can PV systems provide resilient electricity to earthquake-prone areas in Indonesia?

D

uring July to October 2018, seven earthquakes with magnitudes greater than 5 have hit Indonesia. Two of them were very powerful and caused a lot of damages and fatalities. The first earthquake with 6.9 magnitude occurred in Lombok Island on 5 August 2018, causing more than 500 fatalities, 1,300 injuries, widespread damages, and displacing over 340,000 people. The other earthquake with 7.5 magnitude occurred in Central of Sulawesi Island on 29 September and eventually triggered a tsunami that caused more than 2,000 fatalities, 10,000 injuries, 5,000 people to be initially reported missing, and 70,000 homes to be destroyed.

In addition to fatalities and injuries, quake survivors were reported to have difficulties regaining their basic needs of water and electricity. Clean water was difficult to access, because the pipes from central water treatments to households were either damaged or there was no electricity to run the water pumps. Electricity went out mainly due to damaged substations and transmission and distribution lines. In the case of Lombok Island, electric power in 75% of the island went off following the quake, and some Base Transceiver Stations (BTS) for telecommunication around the Northern part of Lombok Island also experienced disruption. The latter was not less devastating since in such a disaster situation, communication services are very important in giving accurate information to the survivors about the situation as well as the relief efforts afterwards.

Earthquake-prone Indonesia Due to the meeting of major tectonic plates in the region, Indonesia is prone to earthquakes. United States Geological Survey has recorded that between 1901 and 2017, Indonesia has had more than 150 earthquakes with magnitude greater than 7.

Therefore, electrical system resiliency is one of the critical issues that must be seriously considered by the government. Photovoltaic (PV) systems that generate electricity from solar power can offer the potential solution for the matter. A PV system, especially when coupled with a sufficient battery system, possesses characteristics that make it resilient.

In areas hit by earthquakes, such as Lombok Island, the electricity went off in residential houses as well as public buildings primarily due to damaged transmission and distribution towers and lines. Moreover, power plants running on diesel fuel faced additional problems when the fuel supply became difficult to obtain due to damaged roads.

Earthquake hazards along plate boundaries near Indonesia

Source: World Economic Forum

Business Development Manager ASEAN, Solvina International

PV equipped with battery system can cope well with this kind of situation.

It can operate off-grid so that electricity can be continuously supplied even if the transmission and distribution towers and lines are damaged or the fuel supply to diesel power plants are temporary unavailable. This was proven during the time of the Lombok earthquake: some BTS equipped with backup system, PV, and batteries survived even though electricity from the grid was cut off. When such disaster hits, the modular design of PV panels is also one of the important characters that makes the chance of surviving panels higher. With a clever installation design and sufficient training for users, it is possible to reconfigure the surviving panels and make them to work as emergency power plants, even if the building where the PV was installed is damaged.

Indonesia’s PV attempts Despite price decreases in solar panels (which now cost closer to $1/Wp or less), progress in implementing PV in Indonesia has not been very successful. Developing large PV systems is still hindered by unattractive compensation and lack of financial support mechanisms, especially when competing with classical power plants.

On 16 November 2018, Indonesia’s Ministry of Energy and Mineral Resources (ESDM) issued the Ministerial Regulation Number 49 of 2018, which regulates the utilisation of rooftop PV, including solar panels, power inverter, electrical wiring systems, electrical protection systems, and bidirectional (export-import) kWh meters for residential, commercial and industrial installations.

A PLN customer is permitted to install rooftop PV and operate the system on-grid, subject to PLN’s approval of their application that includes technical specifications and administrative requirements. Once it is approved, a PLN residential customer, for example, can install rooftop PV to a maximum of 100% of the installed capacity – as determined by the total inverter capacity – and will not be burdened by capacity charge.

Most importantly, this also regulates the entitlement to sell the electricity generated from rooftop PV systems to PLN’s grid. The electricity kWh exported from a PV rooftop owned by a customer to PLN grid is priced at 65% of the applicable electricity tariff. To see the impact of the new regulation to rooftop PV installation from a residential customer perspective, with solar panel price at around $1/Wp, the total investment cost at retail of installing PV rooftop system still reaches rather high at $1.21.5 /Wp with all components, logistics, and construction costs counted. In the case of a 2240Wp solar panel, $1.2/Wp of total cost, four hours of full sun per day, and $0.11/kWh of electricity tariff, a rough calculation translates to an investment return of 7 to 8 years when all of the electricity generated is consumed by the PV owner.

However, a typical residential load pattern in Indonesia has its peak during early evening whilst a rooftop PV generates most electricity around noon time. Around noon time, the load can be typically as low as one third of its peak. Therefore, most of the electricity from the rooftop PV during noon time will be exported to the grid priced at 65% of the applicable tariff that results in a longer investment return of 11 to 13 years.

Many areas in Indonesia are prone to earthquakes, and PV systems show potential to be resilient against disasters. A clearer regulation on their installation has now been issued in Indonesia; however, the potential return of investment period for even rather simple systems could still be quite long. A message to all stakeholders is to value the potential of PV systems against disasters so that detailed actions on regulation, implementation, and technology development can be made towards promoting their installation.

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OPINION

Tim Camp

Chinese wind turbine manufacturers poised to overtake their European counterparts

F

or several years now, European OEMs Vestas and Siemens Gamesa have firmly held the top two positions in lists of the leading global turbine manufacturers. However, a number of Chinese suppliers are hot on their heels and have been increasing their market share through continued dominance in their domestic market and growth in wider Asian markets and further afield. As the market leader within China, Goldwind currently sits third in the global list, and is joined in the top ten by United Power and Envision. With other global up-and-comers Sinovel and Ming Yang Wind Power, the Chinese turbine market doesn’t lack for depth.

To date, however, none have been able to surpass Vestas and Siemens in terms of global installed capacity. Whilst there are numerous factors underlying this dominance, Chinese turbines have often suffered from a perception that they are of lower quality than their European counterparts.

This is all the more pertinent for offshore wind projects, where the high cost of maintenance and repair leaves little appetite for risk.

But the undisputed dominance of the European suppliers could be coming to an end. Over the past few decades Chinese OEMs have been remarkably successful in catching up with – and matching – the quality of technology produced by those operating predominantly in the more mature European and North American markets. Should Chinese turbine technology continue to progress at this accelerated rate over the next five years, they may well overtake them.

A continued gulf in scale Currently, the biggest difference between Chinese machinery and their European equivalents is turbine size. This divergence is most apparent in offshore turbines, with MAKE forecasting that new-to-market European offshore turbines will reach 12MW by 2024, whilst the average rated power of Chinese offshore turbines will increase to a more modest 5MW. This gulf in scale is the result of China’s slow start to offshore wind more generally. Whilst the Chinese government has long held ambitious plans for its offshore sector, implementation proved slow, with planning permissions a particular challenge. With few signs of growth, there was little incentive for Chinese suppliers to produce larger turbines.

However, this situation is about to change. With the recent growth of activity in the Chinese offshore market, many Chinese OEMs have publicised plans to develop larger machines. At the China Windpower event in November, Goldwind unveiled an 8MW model. In addition, Ming Yang Wind Power, Shanghai Electric, Dong Fang Electric Machinery, XEMC and CSIC Haizhuang all have 10MW models under development.

In Europe, MHI Vestas is currently offering a 10MW turbine to the market, whilst GE’s Haliade-X turbine will headline at 12MW. Senvion’s ReaLCoE project aims to develop a turbine of at least 10MW rated power.

In the race to larger turbines, European OEMs are currently in the lead, but Chinese OEMs are making up for lost time.

Despite their smaller size, improvements in the reliability and technical sophistication of Chinese turbines will mean that European OEMs will be nervously looking over their shoulders over the next five years or so – particularly when it comes to onshore wind. Here there will be greatest scope for Chinese manufacturers to take advantage of significant cost efficiencies, together with better quality technology, to begin competing with European OEMs in their home markets, and in the emerging markets of Latin America and Africa.

In the global offshore wind markets, however, the longer track record of larger machines will continue to give European OEMs the edge. The cost of maintenance and repair makes the offshore turbine market a conservative 30 ASIAN POWER

Director of Turbine Engineering, LOC Renewables Top onshore wind turbine manufacturers, 2016

Source: Bloomberg New Energy Finance

one, as owners tend to opt for technology with a track record of reliability.

This means that, even where Chinese OEMs produce bold innovations in turbine design – such as Ming Yang’s two-bladed downwind turbine with 6.5MW rating – the lack of appetite for risk amongst turbine owners will limit the commercial benefits of these new developments. The one exception to European offshore hegemony will likely be the Chinese market itself, where a strong preference to buy local will see Chinese OEMs dominate.

The three factors underlying Chinese growth It’s clear then that Chinese OEMs have made rapid strides in an attempt to catch up with, and in some areas overtake, European suppliers. This is the result of three key changes adopted by the Chinese wind industry over the past decade.

First and foremost, amongst these was a renewed emphasis on quality.

Chinese OEMs invested heavily in order to increase the reliability of their turbines, whilst still maintaining the low prices for which they were known.

Secondly, building initially on imported technology from Europe, they developed their own high-quality indigenous expertise. This development was not limited to IP, but saw Chinese companies also invest heavily in complementary software and in training their engineers to a high standard.

The third factor in the growth of Chinese OEMs has been their newfound focus on overseas sales. Whilst to date they have experienced slow sales in Europe, a number of suppliers have entered the US market, with Goldwind recently securing financing for the 160MW Rattlesnake wind farm in central Texas – its largest US project to date.

Looking to the future Faced with this Chinese expansion, how should European manufacturers react? Some have attempted to set up shop in China, but will likely struggle to compete with local OEMs on their home turf. As is the case in other industries, European manufacturers will need to focus on technological innovation – particularly in offshore wind where they maintain a clear lead.

Equally, given the scale of the US market, demand for additional capacity will likely prove strong enough to accommodate both European and Chinese OEMs and allow them to compete side-by-side. Indeed, this is where Chinese suppliers can expect to witness their strongest international growth. But given their difficulties in entering the Chinese market, European OEMs are set to focus on other Asian markets, particularly Taiwan, Japan and Korea. This expansion will be necessary if European OEMs are to maintain their leadership positions over the next five years.

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OPINION

Bree Miechel

Taiwan’s referendum on nuclear and feed-in tariff reductions – implications for investors Partner, Reed Smith

O

n 24 November 2018 Taiwanese voters passed a referendum to remove Article 95 of Taiwan’s Electricity Act that provided for the phase-out of nuclear energy by 2025. Within the week, the Ministry of Economic Affairs (MOEA) announced its intention to cut the feed-in tariff (FIT) for offshore wind by 12.71% and the FIT for ground-mounted and water-floating PV plants by 12.15% and 11.16% respectively for 2019.

A Trend Survey Research poll commissioned by pro-nuclear activists prior to the vote indicated drivers for the referendum result were voter concern over both the price and instability of renewable energy sources.

Whether the announced cuts to the FIT rates were a response to voter sentiment is unclear.

In accordance with Article 9 of Taiwan’s Renewable Energy Development Act, FIT rates are to be reviewed and adjusted every year following in committee discussion and a hearing involving stakeholders.Whilst the announcements for the 2019 FIT rates came relatively late, they were made in Q4 as usual and apply only to projects for which PPAs are signed in 2019.

What was perhaps more surprising for investors and stakeholders, was the lower FIT of NT$1.94 per kWh proposed to apply to offshore wind power generated above 3600 hours (or other threshold).

Windfarm developers have decried the proposed cuts as unsustainable for the industry considering they are being pushed to bear the multibillion NT$ grid connection and enhancement costs. They have stated that downstream supply contracts will be terminated if the FIT is reduced as currently proposed. They are seeking a FIT rate reduction of no more than 4.25% in line with the estimated international average for 2019.

Under Taiwan’s Referendum Act, a law repealed in a referendum is required to be rescinded three days after the Central Election Commission officially announces the result. Accordingly, Article 95 of the Electricity Act has been rescinded. Notwithstanding this, the referendum result does not mandate a reintroduction of nuclear power and does not infer that the planned share of renewables in Taiwan’s energy mix will be reduced to accommodate the retention of nuclear capacity.

What does this mean for Taiwan’s energy policy?

Whilst a Government spokesperson confirmed that the referendum result would be respected, they noted that the Government will continue with the active development of renewable energy. Lee Chun-li, the deputy director general of the Bureau of Energy at the MOEA noted that the deadline for applications to postpone the decommissioning of Taiwan’s first and second nuclear plants has already passed, and whilst it was still possible to apply for an extension for Taiwan’s third nuclear power plant, the Government’s plan to generate 20% of power by renewables should alleviate the need to do so.

Taiwan set itself on a course to increase its proportion of renewables as part of the energy mix with the promulgation of the “Statute for Renewable Energy Development” (Renewable Energy Development Act) in 2009 and amendment of the Energy Administration Act in 2009. The Government’s plan was to limit Taiwan’s carbon emissions at 2008 levels by 2016 and 2000 levels by 2025, with the development of renewable and pollution-free sources of energy given priority in terms of low-carbon energy generation.

The 2011 Fukushima nuclear disaster in Japan galvanised public opinion to achieve a nuclear-free Taiwan and, notwithstanding successful safety checks, a number of Taiwan’s nuclear units were taken offline and a greenfield nuclear project, the Lungmen nuclear plant, mothballed. Whilst Wu Cheng-cheng, a researcher at Green Citizens’ Action Alliance claims that the passing of deadlines for extending the legal licences for the nuclear plants make it practically very difficult to continue the use of nuclear power 32 ASIAN POWER

Taiwan nuclear power reactors

Source: World Nuclear Association

after 2025, it is within the Government’s power to revise the law setting the application deadline. In 2015, nuclear power provided Taiwan with 5,028 MWe capacity, accounting for approximately 8.1% of Taiwan’s energy consumption and 19% of its electricity generation.

Following the shutdown of one nuclear reactor in 2017, Taiwan suffered from blackouts causing concern for Taiwan’s semiconductor industry. The lead time and geographical constraints to successfully achieving Taiwan’s ambitious renewables targets (20% of the energy mix to come from renewable energy sources by 2025) may have fuelled voter concern over supply reliability. To achieve the renewables target, solar PV project capacity would need to reach 20 GW, whilst offshore wind power should reach 5.5 GW, by 2025. Realistically, however, given current available land resources, it is anticipated that just 6.2 GW of solar capacity will be reached by 2020.

Whilst costs blew out on the Lungmen nuclear plant due to project management issues and a series of delays, the cost of power generation from nuclear capacity in Taiwan in 2014 was NT$ 0.72 per kWh versus the considerably higher 2018 solar FITs of between NT$4.24 – 6.41 per kWh (excluding additional incentives) and 2018 offshore wind FIT of NT$5.8498.

Whilst much more competitive than the offshore wind FIT, the tariffs awarded to 1.66GW of offshore wind capacity in 2018 via auction were still higher than nuclear at between NT$2.2245 and 2.5481 per kWh. Taiwan has been one of the most promising markets for renewables at scale in Asia (excluding India and Mainland China), offering investors a stable regulatory environment. Taiwan’s next general election will be in January 2020 and although the anticipated successor ruling party (the KMT) supported the pro-nuclear activists during the referendum, the KMT may not want to be seen as taking a step back from clean pollution-free energy.

However, whether they would respond to pricing and stability concerns by decreasing renewables as part of the energy mix (or manage any shortfall in achieving renewables targets) in favour of nuclear or conventional power, remains to be seen.

Taiwan is aware that changes undermine investor confidence, adversely impacting investment and has a transparent process for considering investor feedback. The MOEA held public hearings in December ahead of finalising the FITs (still pending). In giving feedback, the government was clear that if developers wanted to see an increase in the government’s proposed rates they would need to provide substantial evidence that the proposed FITs would prevent the recovery of their investment. This article was coauthored by Ariel Huang and Billy Wu, Associates, LCS & Partners.

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